157 FERC ¶ 61,115

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM16-5-000; Order No. 831]

Offer Caps in Markets Operated by Regional Transmission Organizations and 

Independent System Operators

(Issued November 17, 2016)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule.

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

address incremental energy offer caps. We require that each regional transmission 

organization (RTO) and independent system operator (ISO): (1) cap each resource’s 

incremental energy offer at the higher of $1,000/megawatt-hour (MWh) or that resource’s 

verified cost-based incremental energy offer; and (2) cap verified cost-based incremental 

energy offers at $2,000/MWh when calculating locational marginal prices (LMP). 

Further, we clarify that the verification process for cost-based incremental offers above 

$1,000/MWh should ensure that a resource’s cost-based incremental energy offer 

reasonably reflects that resource’s actual or expected costs. This Final Rule will improve 

price formation by reducing the likelihood that offer caps will suppress LMPs below the 

marginal cost of production, while compensating resources for the costs they incur to 

serve load, by enabling RTOs/ISOs to dispatch the most efficient set of resources when 
Docket No. RM16-5-000 - 2 -

short-run marginal costs exceed $1,000/MWh, by encouraging resources to offer supply 

to the market when it is most needed, and by reducing the potential for seams issues. 

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

FEDERAL REGISTER.

FOR FURTHER INFORMATION CONTACT:

Emma Nicholson (Technical Information)

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8846

emma.nicholson@ferc.gov

Pamela Quinlan (Technical Information) 

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6179

pamela.quinlan@ferc.gov

Anne Marie Hirschberger (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8387

annemarie.hirschberger@ferc.gov

SUPPLEMENTARY INFORMATION:
157 FERC ¶ 61,115

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Cheryl A. LaFleur, and Colette D. Honorable. 

Offer Caps in Markets Operated by Regional 

Transmission Organizations and Independent System 

Operators

Docket No. RM16-5-000

ORDER NO. 831

FINAL RULE

(Issued November 17, 2016)

TABLE OF CONTENTS

Paragraph Numbers

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

II. Background .................................................................................................................7.

A. Offer Caps in RTOs/ISOs ......................................................................................10.

B. Offer Caps Waivers and Tariff Changes................................................................14.

III. Need for Reform........................................................................................................15.

A. Comments...............................................................................................................16.

1. Comments That Support the Preliminary Finding That Current Offer Caps are 

Unjust and Unreasonable.........................................................................................16.

2. Comments that Oppose Reforming Current Offer Caps ...................................20.

3. Generally Applicable Offer Cap Reforms..........................................................27.

B. Determination .........................................................................................................34.

IV. Offer Cap Reforms....................................................................................................42.

A. Offer Cap Structure ................................................................................................44.

1. NOPR Proposal...................................................................................................44.

2. Comments...........................................................................................................45.

3. Determination .....................................................................................................77.

B. Cost Verification ...................................................................................................96.
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1. NOPR Proposal...................................................................................................96.

2. Comments...........................................................................................................98.

3. Determination ..................................................................................................139.

C. Resource Neutrality.............................................................................................148.

1. NOPR Proposal................................................................................................148.

2. Comments........................................................................................................149.

3. Determination ..................................................................................................156.

V. Other Issues .............................................................................................................160.

A. Virtual Transactions............................................................................................160.

1. Comments........................................................................................................161.

2. Determination ..................................................................................................172.

B. External Transactions .........................................................................................178.

1. Comments........................................................................................................179.

2. Determination ..................................................................................................192.

VI. Other Comments.....................................................................................................199.

A. Verification Requirement Details .......................................................................200.

1. Comments........................................................................................................200.

2. Determination ..................................................................................................207.

B. Impact of Offer Cap Reforms on Other Market Elements..................................209.

1. Comments........................................................................................................210.

2. Determination ..................................................................................................213.

VII. Requests Beyond the Scope of this Proceeding....................................................214.

A. Comments............................................................................................................214.

B. Determination ......................................................................................................218.

VIII. Information Collection Statement .....................................................................219.

IX. Regulatory Flexibility Act Certification ..............................................................223.

X. Environmental Analysis ..........................................................................................225.

XI. Document Availability ...........................................................................................226.

XII. Effective Date and Congressional Notification ....................................................229.

Regulatory Text

APPENDIX: List of Short Names/Acronyms of Commenters
Docket No. RM16-5-000 - 3 -

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) offer caps on incremental energy offers1 (offer cap) 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,2 that each RTO/ISO:

(1) cap each resource’s incremental energy offer at the higher of $1,000/megawatt-hour 

(MWh) or that resource’s verified cost-based incremental energy offer; and (2) cap 

verified cost-based incremental energy offers at $2,000/MWh when calculating locational 

marginal prices (LMP) (hard cap).3

 Further, we clarify that the verification process for 

cost-based incremental offers above $1,000/MWh should ensure that a resource’s costbased incremental energy offer reasonably reflects that resource’s actual or expected 

costs.

2. We reach this conclusion for several reasons. First, offer caps in some RTOs/ISOs 

may prevent a resource from recouping its short-run marginal costs by not permitting that 

resource to include all of its short-run marginal costs within its incremental energy offer. 

 1 The incremental energy offer is the portion of a resource’s energy supply offer 

that varies with output or level of demand reduction. 

2 16 U.S.C. 824e (2012).

3 In this proceeding, a hard cap refers to an upper limit on the incremental energy 

offers that RTOs/ISOs can use to calculate LMPs. The hard cap does not limit the costbased incremental energy offers that a market participant may submit to the RTO/ISO.
Docket No. RM16-5-000 - 4 -

Second, current offer caps in some RTOs/ISOs are likely to suppress LMPs below the 

marginal cost of production during periods when fuel costs increase dramatically. Third, 

when several resources have short-run marginal costs above $1,000/MWh but are unable 

to reflect those costs within their incremental energy offers due to the offer cap, the 

RTO/ISO is unable to dispatch the most efficient set of resources because it will not be 

able to distinguish among the resources’ actual costs. Finally, the $1,000/MWh offer cap 

in some RTOs/ISOs may discourage resources with short-run marginal costs above 

$1,000/MWh from offering supply to the RTO/ISO, even though the market may be 

willing to purchase that supply.4

 To remedy these problems, we are setting forth 

requirements for each RTO/ISO regarding the offer cap in this Final Rule. We believe 

generic action is appropriate to avoid the creation of seams that would result from 

different offer caps in adjacent RTO/ISO markets. 

3. We have modified the proposal in the Notice of Proposed Rulemaking (NOPR) to 

include a $2,000/MWh hard cap for the purposes of calculating LMPs. While the offer 

cap proposed in the NOPR would address the concerns identified above, we are 

convinced by commenters that the absence of a hard cap creates practical concerns that 

must be addressed. First, several commenters note that RTOs/ISOs and/or Market 

Monitoring Units may have imperfect information about resource short-run marginal 

 4 Many resources are subject to must-offer requirements in either the day-ahead or 

real-time markets. These offer cap reforms ensure that such a resource has an economic 

incentive that matches its tariff obligation and also provide an economic incentive to 

those resources that are not subject to a must-offer requirement.
Docket No. RM16-5-000 - 5 -

costs, which can create challenges for the proposed requirement to verify cost-based 

incremental energy offers above $1,000/MWh prior to the market clearing process. 

Additionally, as noted by market monitors, the dynamics of natural gas spot market 

prices during periods when they rise to levels that could result in the short-run marginal 

costs of some natural gas-fired resources exceeding $1,000/MWh can make verification 

challenging, particularly verification of expected costs. Thus, while a hard cap may 

diminish the ability to fully address the shortcomings of current offer caps identified 

above in all circumstances, we find that, on balance, a hard cap is necessary to reasonably 

limit the adverse impact that any imperfect information during the verification process 

could have on LMPs. 

4. 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

 5 See 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) (Notice Inviting Comments); Price Formation in Energy and Ancillary Services 

Markets Operated by Regional Transmission Organizations and Independent System 

Operators, Notice, Docket No. AD14-14-000 (June 19, 2014) (Price Formation Notice).
Docket No. RM16-5-000 - 6 -

5. The reforms adopted in this Final Rule advance two of the Commission’s goals 

with respect to price formation. First, the reforms will result in LMPs that are more 

likely to reflect the true marginal cost of production when resources’ short-run marginal 

costs exceed $1,000/MWh. In the short run, LMPs that reflect the short-run marginal 

costs of production are particularly important during high price periods because they 

provide a signal to consumers to reduce consumption and a signal to suppliers to increase 

production or to offer new supplies to the market. In the long run, LMPs that reflect the 

short-run marginal cost of production are important because they inform investment 

decisions. Second, the reforms will give resources the opportunity to recover their shortrun marginal costs, thereby encouraging resources to participate in RTO/ISO energy 

markets. Adequate investment in resources and resource participation in RTO/ISO 

energy markets ensure adequate and reliable energy for consumers. The benefits 

summarized above and discussed in detail below would ultimately help to ensure just and 

reasonable rates.

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

changes needed to implement this Final Rule within 75 days of the Final Rule’s effective 

date. 

II. Background

7. In June 2014, the Commission initiated a proceeding, in Docket No. AD14-14-

000, to evaluate issues regarding price formation in the energy and ancillary services 
Docket No. RM16-5-000 - 7 -

markets operated by RTOs/ISOs.6

 In the notice initiating that proceeding, the 

Commission stated that there may be opportunities for the RTOs/ISOs to improve the 

energy and ancillary services price formation process. As set forth in that notice, LMPs 

and market-clearing prices used in energy and ancillary services markets ideally “would 

reflect the true marginal cost of production, taking into account all physical system 

constraints, and these prices would fully compensate all resources for the variable cost of 

providing service.”7

 

8. In the instant proceeding, on January 21, 2016, the Commission issued a NOPR 

proposing to require that each RTO/ISO: (1) cap each resource’s incremental energy offer 

to the higher of $1,000/MWh or that resource’s verified cost-based incremental energy 

offer; and (2) use verified cost-based incremental energy offers above $1,000/MWh to 

calculate LMPs.8

9. The Commission also sought comments on the NOPR proposal regarding: 

(1) whether a hard cap on cost-based incremental energy offers used for purposes of 

calculating LMPs should be included in any Final Rule in this proceeding and, if so, 

whether the hard cap should equal $2,000/MWh or another value; (2) the ability of the 

 6 Price Formation Notice, Docket No. AD14-14-000.

7 Price Formation Notice, Docket No. AD14-14-000 at 2.

8 Offer Caps in Markets Operated by Regional Transmission Organizations and 

Independent System Operators, 81 Fed. Reg. 5951 (Feb. 4, 2016), FERC Stats. & Regs. 

¶ 32,714, at P 3 (2016) (NOPR).
Docket No. RM16-5-000 - 8 -

Market Monitoring Unit or RTO/ISO to verify the costs underlying incremental energy 

offers above $1,000/MWh prior to the day-ahead or real-time market clearing process, 

including whether the verification of physical offer components is also necessary; 

(3) whether the Market Monitoring Unit or RTO/ISO may need additional information to 

ensure that all short-run marginal cost components, such as risk or opportunity costs that 

are often difficult to quantify, are accurately reflected in a resource’s cost-based 

incremental energy offer, and whether an adder is appropriate; (4) whether the Market 

Monitoring Unit or RTO/ISO may need additional information or the authority to require 

revisions or corrections to cost-based incremental energy offers to ensure that cost-based 

incremental energy offers are accurate reflections of a resource’s short-run marginal cost; 

(5) whether the proposal should apply to imports and whether a cost verification process 

for import transactions is feasible; (6) whether excluding virtual transactions above 

$1,000/MWh could limit hedging opportunities, present opportunities for manipulation or 

gaming, or create market inefficiencies; and (7) the impact the proposal would have on 

seams.9

 

A. Offer Caps in RTOs/ISOs

10. Supply offers in day-ahead and real-time energy markets consist of both financial 

and physical components. The financial components of a supply offer are denominated 

in dollars (e.g., $/start and $/MWh) and represent the costs underlying a resource’s offer 

 9 Id. P 73.
Docket No. RM16-5-000 - 9 -

to supply electricity in a given day-ahead or real-time interval. The physical components 

of a supply offer, which are not denominated in dollars, describe the resource’s physical 

operating parameters. These include, for example, a resource’s minimum and maximum 

operating limits in a given day-ahead or real-time interval, and are denominated in MW, 

MWh, time, or some other unit.

11. This Final Rule addresses the incremental energy offer component of a resource’s 

supply offer, which is a financial component consisting of costs that vary with a 

resource’s output or level of demand reduction. Incremental energy offers typically 

consist of a supply curve made up of multiple price-quantity pairs that indicate the price, 

expressed in $/MWh, that a resource is willing to accept to produce a given quantity of 

energy. 

12. All six Commission-jurisdictional RTOs/ISOs have at one time imposed a 

$1,000/MWh cap on incremental energy offers.10 The offer cap remains at $1,000/MWh 

in CAISO, ISO-NE, MISO, NYISO, and SPP, and resources in these RTOs/ISOs may not 

submit incremental energy offers above $1,000/MWh. As discussed further below, 

 10 See, e.g., California Independent System Operator Corporation, eTariff, 

§ 39.6.1.1 (11.0.0); ISO New England Inc., Transmission, Markets and Services Tariff, 

Market Rule 1, §§ III.1.10.1A(c)(iv), III,1.10.IA(d)(iv), III.2.6(b)(i), and III.A.15.1(b) 

(46.0.0); Midcontinent Independent System Operator, Inc., FERC Electric Tariff, Module 

D §§ 39.2.5 (35.0.0), 39.2.5A (34.0.0), 39.2.5B (34.0.0), 40.2.5 (35.0.0), 40.2.6 (35.0.0) 

and 40.2.7 (33.0.0); New York Independent System Operator, Inc., NYISO Tariffs, 

NYISO Markets and Services Tariff, §§ 21.4 and 21.5.1 (7.0.0); PJM Interconnection, 

L.L.C., Intra-PJM Tariffs, OATT, Tariff Operating Agreement, Attachment K, 

Appendix, § 1.10.1A(d) (24.0.0); Southwest Power Pool, Inc., OATT, Sixth Revised 

Volume No. 1, Attachment AE, Section 4.1.1 (2.0.0). 
Docket No. RM16-5-000 - 10 -

resources in PJM may submit incremental energy offers above $1,000/MWh provided 

they are cost-based, but PJM applies a hard cap that limits incremental energy offers to 

$2,000/MWh when calculating LMPs.11 

13. While the current offer caps restrict the incremental energy offers, one of the 

components used to set LMP, they do not limit LMPs to the level of the offer caps 

because the addition of the congestion and loss components of the LMP can result in 

LMPs that exceed the offer cap. Scarcity or shortage pricing and emergency purchases 

can also cause LMPs to exceed the offer cap. 

B. Offer Caps Waivers and Tariff Changes

14. As described in the NOPR, after the extreme weather experienced during the 

winter of 2013/14, dubbed the “Polar Vortex”, PJM, NYISO, and MISO filed various 

requests to either temporarily or permanently revise their respective offer caps.12 During 

the winter months of 2014, the Commission approved requests to temporarily waive tariff 

provisions related to offer caps in NYISO13 and PJM.14 In the following winter of 

 11 PJM Interconnection, L.L.C., 153 FERC ¶ 61,289, at P 25 (2015) (PJM 2015 

Offer Cap Order). 

12 NOPR, FERC Stats. & Regs ¶ 32,714 at PP 13-17.

13 N.Y. Indep. Sys. Operator, Inc., 146 FERC ¶ 61,061, at PP 2-4 (2014).

14 PJM filed concurrently two tariff waiver requests related to its offer cap. In its 

first request, which the Commission granted for the January 24 - February 10, 2014 

period, PJM requested that certain resources with cost-based offers above $1,000/MWh 

receive uplift payments to recoup those costs. See PJM Interconnection, L.L.C., 

146 FERC ¶ 61,041, at P 2 (PJM 2014 Waiver Order I), order on reh’g, 149 FERC 

(continued ...)
Docket No. RM16-5-000 - 11 -

2014/15, the Commission approved temporary changes to the PJM tariff and temporarily 

waived some MISO tariff provisions to address issues with the offer caps in the PJM and 

MISO energy markets.15 During the winter of 2015/16, PJM and MISO again filed 

requests to modify their respective offer caps. On December 11, 2015, the Commission 

accepted tariff revisions in PJM that would raise the cap on cost-based incremental 

energy offers to $2,000/MWh for purposes of calculating LMPs.16 The Commission also 

granted MISO’s request to temporarily waive tariff provisions related to its $1,000/MWh 

offer cap.17 MISO recently filed another request to temporarily waive tariff provisions 

related to its offer cap for the upcoming winter of 2016/17.18

 

¶ 61,059 (2014). In its second request, which the Commission granted for the 

February 11 - March 31, 2014 period, PJM requested that certain resources be allowed to 

submit cost-based incremental energy offers in excess of $1,000/MWh, with no cap on 

cost-based offers. See PJM Interconnection, L.L.C., 146 FERC ¶ 61,078, at PP 3-4 

(2014) (PJM 2014 Offer Cap Order II).

15 The temporary revisions to the PJM tariff were accepted for the January 16, 

2015 through March 31, 2015 period. See PJM Interconnection, L.L.C., 150 FERC 

¶ 61,020, at P 5 (2015) (PJM 2014/15 Offer Cap Order). The temporary waiver of the 

MISO tariff provisions was granted for December 20, 2014 through April 30, 2015 

period. See Midcontinent Indep. Sys. Operator, Inc., 150 FERC ¶ 61,083, at P 3 (2015) 

(MISO 2014/15 Offer Cap Order). 

16 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 25. The tariff provisions 

related to the offer cap do not have a sunset date.

17 Midcontinent Indep. Sys. Operator, Inc., 154 FERC ¶ 61,006, at P 1 (2016) 

(MISO 2015/16 Offer Cap Order). This waiver was granted for the January 1, 2016 

through April 30, 2016 period.

18 Midcontinent Indep. Sys. Operator, Inc., Transmittal, Docket No. ER16-2685-

000.
Docket No. RM16-5-000 - 12 -

III. Need for Reform

15. In the NOPR, the Commission preliminarily found that the $1,000/MWh offer 

caps currently in effect in some RTOs/ISOs19 are unjust and unreasonable for four 

reasons.20 First, some current RTO/ISO offer caps may prevent a resource from 

recouping its short-run marginal costs by not permitting that resource to reflect its shortrun marginal costs within its incremental energy offer. Second, current offer caps may 

suppress LMPs below the marginal cost of production. Third, when several resources 

have short-run marginal costs above $1,000/MWh but are unable to reflect those costs 

within their incremental energy offers due to the offer cap, the RTO/ISO may not 

dispatch the most efficient set of resources because it will not be able to distinguish 

between the resources’ actual costs. Finally, the $1,000/MWh offer cap in some 

RTOs/ISOs may discourage resources with short-run marginal costs above $1,000/MWh 

from offering supply to the RTO/ISO, even though the market may be willing to purchase 

that supply.21 We believe generic action is appropriate to avoid the creation of seams that 

would result from different offer caps in adjacent RTO/ISO markets. As described 

below, based on our analysis of the record, we adopt the preliminary findings in the 

 19 Specifically CAISO, ISO-NE, MISO, NYISO, and SPP. See supra n.10. 

20 See NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 43-47.

21 Id. PP 44-47.
Docket No. RM16-5-000 - 13 -

NOPR and conclude that the current offer caps in RTOs/ISOs are unjust and 

unreasonable. 

A. Comments

1. Comments That Support the Preliminary Finding That Current 

Offer Caps are Unjust and Unreasonable

16. Several commenters, for various reasons, support the Commission’s preliminary 

finding in the NOPR that existing offer caps in RTOs/ISOs are unjust and unreasonable,22

and others express general or conditional support for the NOPR.23 Some commenters 

agree that the $1,000/MWh offer cap prevents resources from recovering their short-run 

marginal costs.24 For example, Direct Energy states that generator cost assurance is key 

to maintaining reliability because it ensures that resources will have the incentive to 

follow RTO/ISO dispatch instructions when called upon by the RTO/ISO, without 

 22 See generally CEA Comments at 3-4; Direct Energy Comments at 2-3; Exelon 

Comments at 5-7; PJM/SPP Comments at 1-2; EEI Comments at 3-4; Competitive 

Suppliers Comments at 4, 6, 7-15; Ohio Commission Comments at 4. A list of 

commenters and the abbreviated names used for them in this Final Rule appears in the 

Appendix.

23 See generally Dominion Comments at 3; EEI Comments at 3-5; Golden Spread 

Comments at 1; Midcontinent Joint Consumer Advocates Comments at 2; MISO 

Comments at 1; NESCOE Comments at 1; New Jersey Commission Comments at 1; 

NY Transmission Owners Comments at 2; NYISO Comments at 2; OMS Comments at 2; 

OPSI Comments at 10; PJM/SPP Comments at 1; Potomac Economics Comments at 1; 

Powerex Comments at 6; Six Cities Comments at 2.

24 CEA Comments at 4; Direct Energy Comments at 2-3; OMS Comments at 2; 

Six Cities Comments at 2.
Docket No. RM16-5-000 - 14 -

concern for receiving compensation below their short-run costs.25 Six Cities states that 

exceptional circumstances may give rise to marginal costs for specific resources that 

exceed $1,000/MWh and those resources should have an opportunity to recover their 

actual costs of production.26 

17. Several commenters support the Commission’s preliminary finding that existing 

RTO/ISO offer caps should be reformed because they can suppress LMPs below the 

marginal cost of production.27 For example, PJM/SPP28 state that the current offer caps 

could undermine market efficiency by preventing legitimate incremental energy offers 

above $1,000/MWh, which they state has occurred in some parts of the country, because 

LMPs that fail to reflect the cost of serving demand are inefficient.29 Competitive 

Suppliers assert that while the costs of the marginal resources have not frequently 

exceeded $1,000/MWh, the impact of the $1,000/MWh offer cap is not trivial because 

 25 Direct Energy Comments at 2.

26 Six Cities Comments at 2. 

27 See generally CEA Comments at 3-4; Competitive Suppliers Comments at 9-13; 

Exelon Comments at 5-7; EEI Comments at 3-5; PJM Power Providers Comments at 1-2; 

PJM/SPP Comments at 1-2; Powerex Comments at 6.

28 “PJM/SPP” indicates comments filed jointly by PJM and SPP. PJM and SPP 

also make individual comments within their joint filing.

29 PJM/SPP Comments at 1-2 (citing PJM, Analysis of Operational Events and 

Market Impacts During the January 2014 Cold Weather Events (May 8, 2014), available 

at http://www.pjm.com/~/media/committeesgroups/task-forces/cstf/20140509/20140509-

item-02-cold-weather-report.ashx). 
Docket No. RM16-5-000 - 15 -

artificially suppressing day-ahead or real-time LMPs during those few intervals can 

prevent economic outcomes that will support reliability and motivate consumers to 

reduce consumption during stressed system conditions.30 Midcontinent Joint Consumer 

Advocates support changing the offer cap because incremental energy costs would only 

exceed $1,000/MWh in extreme conditions.31 

18. Other commenters agree with the Commission’s preliminary finding that the 

$1,000/MWh offer cap should be reformed because it can discourage a resource with 

costs above the offer cap from offering its supply to the RTO/ISO, even though the 

market may be willing to purchase that supply.32 For example, OMS states that when the 

(primarily fuel) cost to generate electricity is unusually high, the current $1,000/MWh 

offer cap can limit the willingness of resources to offer into the day-ahead and real-time 

markets.

33 

19. CEA and EEI express general support for the Commission’s preliminary finding in 

the NOPR that current offer caps could also prevent the RTO/ISO from dispatching the 

most efficient set of resources because the RTO/ISO will not have access to the 

 30 Competitive Suppliers Comments at 9.

31 Midcontinent Joint Consumer Advocates Comments at 3-4.

32 See generally CEA Comments at 3-4; Competitive Suppliers Comments at 13; 

OMS Comments at 2; Powerex Comments at 6.

33 OMS Comments at 2.
Docket No. RM16-5-000 - 16 -

underlying costs associated with the multiple incremental energy offers above the offer 

cap.34

2. Comments that Oppose Reforming Current Offer Caps 

20. Several commenters disagree with the Commission’s finding that the current offer 

cap is unjust and unreasonable and therefore should be reformed. For example, CAISO 

argues that the current $1,000/MWh offer cap in CAISO should not be changed because 

$1,000/MWh is far in excess of what the highest reasonable cost-justified offer could be 

from a CAISO resource.35 CAISO explains that natural gas prices have generally been 

stable, and argues that even if natural gas market fundamentals changed, periods when 

incremental energy costs exceed $1,000/MWh would be infrequent and short-lived and 

do not justify the offer cap changes proposed in the NOPR.36 ISO-NE does not oppose 

raising its current offer cap to a higher fixed level, but nonetheless maintains that the 

current $1,000/MWh offer cap in ISO-NE is just and reasonable because the cap has not 

inappropriately limited LMPs below the marginal cost.37 

21. The ISO-NE and SPP Market Monitors assert that there is no need to reform the 

offer caps in their markets. The ISO-NE Market Monitor states that there is no need to 

 34 CEA Comments at 2-3; EEI Comments at 3-4.

35 CAISO Comments at 4.

36 Id. at 4-5.

37 ISO-NE Comments at 1-3.
Docket No. RM16-5-000 - 17 -

revise ISO-NE’s $1,000/MWh offer cap because natural gas prices have become more 

stable and, if completed, proposed pipeline expansions in New England will help 

alleviate some of the natural gas congestion that led to the high LMPs observed in ISONE in 2014.38 The SPP Market Monitor states that SPP resources have not experienced 

costs above $1,000/MWh and the SPP Market Monitor expects that fuel price spikes that 

would raise costs to that level would rarely occur.39

22. A number of commenters argue, for various reasons, that current RTO/ISO offer 

caps should not be revised.40 For example, several commenters assert that revising the 

offer cap is an overreaction to anomalous, infrequent, and/or transitory market and 

weather conditions that do not justify changing the offer cap. Steel Producers’ Alliance 

observes that the current offer cap has only been an issue in a handful of instances, which 

it argues demonstrates that the offer cap is set at the appropriate level and performing as 

intended.41 APPA, NRECA, and AMP assert that the offer cap issues described in the 

 38 ISO-NE Market Monitor Comments at 12-14 (citing ISO-NE Market Rule 1, 

Appendix A, Section III.A.15).

39 SPP Market Monitor Comments at 8-9.

40 See generally APPA, NRECA, and AMP Comments at 5-8; AF&PA Comments 

at 2-3; CAISO Comments at 2; Industrial Customers Comments at 3-9; Industrial Energy 

Consumers Comments at 2; ISO-NE Market Monitor Comments at 12-14; NY 

Department of State Comments at 3-5; NYPSC Comments at 1, 4; Steel Producers’ 

Alliance Comments at 2-3; ODEC Comments at 3-5; PG&E Comments at 1-2; PJM Joint 

Consumer Advocates Comments at 2-4; SPP Market Monitor Comments at 2, 6, 12-13; 

TAPS Comments at 1, 4-7.

41 Steel Producers’ Alliance Comments at 2. 
Docket No. RM16-5-000 - 18 -

NOPR are merely hypothetical, and that there is insufficient evidence that current offer 

caps are unjust and unreasonable.42 

23. Some commenters disagree with the NOPR’s preliminary finding that offer caps 

are unjust and unreasonable because they can suppress LMPs below the marginal cost of 

production. For example, ODEC argues that a higher cap is unnecessary because LMPs 

are lower in PJM than they were when PJM’s current higher offer cap was adopted.43 

Other commenters argue that LMPs above $1,000/MWh do not send a useful price signal 

to consumers,44 and may in fact harm consumers because most demand for electricity is 

inelastic, or unresponsive to price changes.45 These commenters argue that, because most 

demand is inelastic, raising the offer cap would lead to market power abuses and transfer 

payments from load to generators.46 For example, Industrial Customers argue that 

resources can take advantage of inelastic demand and exercise market power to obtain 

 42 APPA, NRECA, and AMP Comments at 9-13.

43 ODEC Comments at 3-4.

44 NY Department of State Comments at 3; New York Commission Comments at 

5-6.

45 AF&PA Comments at 2-3; Industrial Energy Consumers Comments at 2; 

Industrial Customers Comments at 10; PJM Joint Consumer Advocates Comments at 4; 

TAPS Comments at 6, 12. 

46 Direct Energy Comments at 3-5; Industrial Customers Comments at 10; 

NY Department of State Comments at 3; TAPS Comments at 3.
Docket No. RM16-5-000 - 19 -

prices above competitive levels.47 The New York Commission argues that without 

sufficient competition, including from demand response, raising the offer cap will not 

change behavior in NYISO and will only increase prices and burden ratepayers.48 The 

New York Commission asserts that the Commission should not revise the offer cap until 

more effective demand response resources can participate in NYISO’s real-time energy 

market.49 

24. Many commenters argue that the current offer caps in RTOs/ISOs should be 

maintained because they protect consumers from excessive LMPs that result from market 

power abuse.50 For example, NY Department of State argues that the offer cap benefits 

consumers by shielding customers from high real-time LMPs or market manipulation.51 

Similarly, TAPS states that the current offer caps act as a critical safety valve to protect 

consumers from excessive prices.52 Industrial Customers assert that increasing the offer 

cap above $1,000/MWh would raise consumers’ costs to hedge electricity 

 47 Industrial Customers Comments at 10.

48 New York Commission Comments at 5-6.

49 New York Commission Comments at 6.

50 Industrial Customers Comments at 3, 10-11; Industrial Energy Consumers 

Comments at 2; TAPS Comments at 1, 8-12, NY Department of State Comments at 4. 

51 NY Department of State Comments at 4.

52 TAPS Comments at 1.
Docket No. RM16-5-000 - 20 -

procurements.

53 Industrial Energy Consumers stress that offer caps are essential for 

consumers to be confident that rate structures are fair and nondiscriminatory.54 

25. Some commenters argue that current offer caps do not suppress LMPs in a manner 

that impacts resource investment decisions. AF&PA asserts that periodic and 

unpredictable price spikes have limited value in sustaining resource viability or inducing 

consumers to make long term behavioral changes.55 Similarly, TAPS argues that 

allowing offers above $1,000/MWh to set the LMP would not have a practical impact on 

resource investment decisions because, even if the offer cap were raised, the LMP would 

remain the same in the vast majority of hours. TAPS adds that no resource owner would 

base its capital investments on the hope that LMPs will be extremely high for just a few 

hours every year.56 

26. Some commenters argue that offer cap waivers are the best remedy to address 

issues associated with the offer cap.57 For example, Industrial Energy Consumers state 

that the Commission adequately addressed the isolated Polar Vortex event by granting 

either temporary, limited waivers, or uplift payments, thereby sending the correct price 

 53 Industrial Customers Comments at 20.

54 Industrial Energy Consumers Comments at 2.

55 AF&PA Comments at 2-3.

56 TAPS Comments at 6-7.

57 AF&PA Comments at 6-7; Industrial Energy Consumers Comments at 2; Steel 

Producers’ Alliance Comments at 2-3.
Docket No. RM16-5-000 - 21 -

signal for investment.58 AF&PA supports current Commission protocols of waivers and 

other reforms that allow generators to recover verifiable costs in certain situations, and 

supports the expansion and streamlining of these protocols.59 

3. Generally Applicable Offer Cap Reforms

27. In addition to the four preliminary findings stated above,

60 the Commission also 

stated in the NOPR that the lack of a uniform offer cap has the potential to exacerbate 

seams issues between neighboring RTOs/ISOs.61 The Commission recognized in the 

NOPR that the proposed reforms could result in neighboring markets having different 

effective offer caps in a given interval because the marginal cost of production in one 

RTO/ISO may differ from neighboring markets due to resources with different short-run 

marginal costs being on the margin in those markets.62 The Commission preliminarily 

found, however, that these differences will not adversely affect seams because the 

differences would be driven by actual costs and not by offer caps artificially suppressing 

LMPs. The Commission stated that, to the extent incremental energy offers can be 

verified, a reform applicable to all RTOs/ISOs that allows cost-based incremental energy 

offers to exceed $1,000/MWh would enhance market efficiency and mitigate the potential 

 58 Industrial Energy Consumers Comments at 2.

59 AF&PA Comments at 6. 

60 See supra P 2.

61 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 70.

62 Id. P 71.
Docket No. RM16-5-000 - 22 -

for seams issues.63 The Commission sought comment on these preliminary findings and 

other seams issues related to this proposal.

28. The majority of commenters agree with the NOPR’s proposal to make a change 

in the offer cap across all RTOs/ISOs in order to avoid seams issues,64 and several 

commenters generally agree with the importance of mitigating seams issues.65 For 

example, the IRC notes the importance of uniformity in the treatment of offer caps, 

particularly in neighboring RTOs/ISOs.66 NYISO supports a uniform RTO/ISO offer cap 

and argues that, in areas with a common fuel source, differing offer caps in neighboring 

regions could lead to restricted fuel procurement in the region with the lower offer cap.67 

MISO asserts that without a common offer cap, tight operating conditions could provide 

counterproductive arbitrage opportunities.68 The ISO-NE Market Monitor notes that 

 63 Id. P 48.

64 See generally Dominion Comments at 8; Competitive Suppliers Comments at 

23, 25; EEI Comments at 4; Exelon Comments at 22-23; MISO Comments at 19; 

NESCOE Comments at 2; PJM Power Providers Comments at 6-7; OMS Comments at 4; 

PJM/SPP Comments at 2-3; IRC Comments at 3; NY Department of State Comments at 

6; NYISO Comments at 9-10; ISO-NE Market Monitor Comments at 14; Steel 

Producers’ Alliance Comments at 3-4. Some of these commenters express conditional or 

qualified support of the NOPR and/or propose alternative offer caps.

65 Industrial Customers Comments at 21, 24; Midcontinent Joint Consumer 

Advocates Comments at 9-10; TAPS Comments at 21-22.

66 IRC Comments at 1, 3.

67 NYISO Comments at 10. 

68 MISO Comments at 19.
Docket No. RM16-5-000 - 23 -

different offer caps in neighboring regions could be detrimental to ISO-NE’s ongoing 

efforts to develop a clearing mechanism to select external resources in economic merit 

order.69 

29. The PJM Market Monitor states that the proposal’s impact on seams would be 

consistent with efficient markets whereby energy would flow to where it is valued 

most.70 EEI argues that the actual effect of the NOPR on seams would be determined by 

market forces and the marginal cost to operate the system.71

30. With respect to the Western Electricity Coordinating Council (WECC), CAISO 

and Exelon argue that the Commission must address how it will ensure consistency 

between the proposed offer cap in CAISO and the existing $1,000/MWh offer cap in 

WECC.72 CAISO and Exelon observe that, in instituting the existing offer cap in WECC, 

the Commission recognized the interdependency between CAISO and WECC and 

therefore stated that it would be unjust and unreasonable to have different offer caps in 

these two regions.73 CAISO further asserts that for those RTOs/ISOs, such as CAISO, 

 69 ISO-NE Market Monitor Comments at 14.

70 PJM Market Monitor Comments at 12.

71 EEI Comments at 4. 

72 CAISO Comments at 14; Exelon Comments at 22.

73 CAISO Comments at 14 (citing Western Electric Coordinating Council, 

133 FERC ¶ 61,026 (2010)); Exelon Comments at 22 (citing Western Electric 

Coordinating Council, 131 FERC ¶ 61,145 (2010)).
Docket No. RM16-5-000 - 24 -

that do not share a seam with another RTO/ISO, the Final Rule should allow these 

RTOs/ISOs to demonstrate that raising the offer cap is unnecessary.74 

31. Some market participants support the NOPR’s applicability to all RTOs/ISOs in 

theory, but argue that the effect on seams would depend on implementation. The 

Delaware Commission cautions that the degree to which the verification of cost-based 

offers above $1,000/MWh is sufficiently rigorous will determine the effect on seams and 

that this will not be known until implementation.75 ISO-NE agrees that consistent energy 

offer caps are important to prevent flows that run contrary to reliability needs, but argues 

that the NOPR’s actual effect on seams is unknown because real-time cost verification 

for imports is not possible.76 PJM Joint Consumer Advocates argue that the 

Commission’s proposal could exacerbate seams because shortage pricing mechanisms 

vary across RTOs/ISOs.77 Industrial Energy Consumers note that allowing different offer 

caps in adjacent markets could create seams issues.78

32. Other commenters argue that there should be regional flexibility in implementing 

an offer cap. PG&E argues that a one-size-fits-all solution for all RTO/ISO markets is 

 74 CAISO Comments at 2, 4.

75 Delaware Commission Comments at 14-15.

76 ISO-NE Comments at 9.

77 PJM Joint Consumer Advocates Comments at 6-7. 

78 Industrial Energy Consumers Comments at 2.
Docket No. RM16-5-000 - 25 -

not appropriate.79 As noted above, the NY Transmission Owners suggest that different 

hard caps in different regions might be justified, so long as regions that are dependent on 

the same gas supply coordinate their caps.80 Direct Energy supports the NOPR’s 

proposal for verified cost-based offers above $1,000/MWh, but argues that individual 

RTOs/ISOs should be able to set offer caps above $1,000/MWh in recognition of regional 

differences.81 

33. APPA, NRECA, and AMP assert that the NOPR runs counter to the Commission’s 

usual practice of recognizing and accommodating regional differences.82 APPA, 

NRECA, and AMP state that a concern over seams is not adequate justification for the 

rule because it fails to account for regional differences, and because the Commission 

determined that the need for an increase in the offer cap outweighed seams issues when it 

approved PJM’s $2,000/MWh offer cap.83 

 79 PG&E Comments at 1-2. 

80 NY Transmission Owners Comments at 4-5. 

81 Direct Energy Comments at 5-6.

82 APPA, NRECA, and AMP Comments at 5-6.

83 Id. at 6 (citing PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 55).

Additionally, APPA, NRECA, and AMP argue that the fact that PJM has this higher offer 

cap and it has not resulted in seams issues proves that concerns over seams are purely 

hypothetical. Id.
Docket No. RM16-5-000 - 26 -

B. Determination

34. Based on our analysis of the record, we adopt the preliminary findings in the 

NOPR, and conclude that the offer caps currently in effect in RTOs/ISOs are unjust and 

unreasonable. We find that the currently effective offer caps may prevent a resource 

from recovering its short-run marginal costs, which could result in that resource operating 

at a loss.84 We also find that the $1,000/MWh offer caps in effect in some RTOs/ISOs 

may suppress LMPs below the marginal cost of production given that recent history 

demonstrates that resource short-run marginal costs can exceed $1,000/MWh.85 We also 

find that preventing resources from including all of their short-run marginal costs in their 

incremental energy offers when those costs exceed $1,000/MWh may discourage 

resources that are not subject to must-offer requirements from offering their supply to the 

RTO/ISO energy market. Finally, preventing resources from including their short-run 

marginal costs in their incremental energy offers when those costs exceed $1,000/MWh 

may also prevent the RTO/ISO from dispatching the most efficient resources when 

several resources have short-run marginal costs above $1,000/MWh.

 84 As discussed above, the Commission has previously accepted temporary 

changes to tariff provisions in MISO that enabled resources to receive uplift for short-run 

marginal costs above the $1,000/MWh offer cap. However, cost recovery through uplift 

is only guaranteed if a resource experiences short-run marginal costs above $1,000/MWh 

during the time period for which the Commission has accepted tariff revisions related to 

the offer cap. See supra P 14. Currently, resources in many RTOs/ISOs do not have the 

opportunity to recover short-run marginal costs above $1,000/MWh without a tariff 

modification.

85 PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 6. 
Docket No. RM16-5-000 - 27 -

35. We disagree with commenters who argue that there is no need to reform the offer 

cap or that the problems described in the NOPR are hypothetical and that insufficient 

evidence exists to conclude that the current offer caps are unjust and unreasonable. As 

discussed in the NOPR, three RTOs/ISOs made filings with the Commission (two on 

multiple occasions) to address issues related to the level of the offer cap.86 The waiver 

requests and high natural gas costs experienced during the Polar Vortex, which could 

have caused some resources to experience costs above $1,000/MWh, demonstrate that the 

deficiencies of current offer caps, in particular the $1,000/MWh offer cap, are concrete 

rather than hypothetical. 

36. Without Commission action to remedy these deficiencies, some resources could be 

forced to operate at a loss and some resources would be discouraged from offering their 

supply to the grid when it is most needed. A central tenet of sound wholesale electric 

market design is that resources must have an opportunity to recover their costs, so the 

question left to the Commission is how to provide that opportunity for cost recovery 

when short-run marginal costs exceed the $1,000/MWh offer cap. We have essentially 

two choices to enable resources to recover short-run marginal costs above $1,000/MWh: 

to allow cost recovery through energy prices or through uplift. Short-run marginal costs, 

which resources include in the incremental energy component of their supply offers, are 

 86 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 13-17.
Docket No. RM16-5-000 - 28 -

typically used to calculate LMP. As noted above,87 ensuring that LMPs reflect the 

marginal cost of production sends critical information to market participants, improves

transparency, and generally results in more efficient outcomes in RTO/ISO energy 

markets. We find that recovery through energy prices, in most circumstances, will 

provide the additional benefit that LMPs reflect the marginal cost of production, will 

increase transparency about the functioning of RTO/ISO energy markets, and will 

facilitate efficient dispatch of resources with short-run marginal costs above 

$1,000/MWh.

88 While we recognize that offer caps may not bind frequently, the Federal 

Power Act requires the Commission to ensure that rates are just and reasonable.

37. We also disagree with commenters that LMPs above $1,000/MWh do not send 

useful price signals to market participants because, in fact, the Commission has found on 

prior occasions that LMPs based on short-run marginal cost send efficient short-run and 

long-run signals to the market.89 In the short-run, LMPs based on short-run marginal 

costs are an effective way to communicate information to market participants about the 

 87 See supra P 5.

88 We note that uplift is necessary in some circumstances. For example, resource 

start-up and no-load costs are not typically included in LMP, and some resources receive 

uplift to recover these costs. 

89 PJM Interconnection, L.L.C., 110 FERC ¶ 61,053, at P 114 (2005) (“offers [in a 

competitive market] should set the market clearing price in order to send appropriate 

price signals about the need for new generation or enhanced load response”). PJM 2014 

Offer Cap Order II, 146 FERC ¶ 61,078 at P 40 (“By limiting legitimate, cost-based bids 

to no more than $1,000/MWh, the market produces artificially suppressed market prices 

and inefficient resource selection”).
Docket No. RM16-5-000 - 29 -

cost of providing the next unit of energy. For example, when LMPs are high, they 

provide a signal to customers to reduce consumption and a signal to suppliers to increase 

production or to offer new supplies to the market. In the long-run, LMPs based on shortrun marginal costs can help to inform investment decisions.90 

38. Furthermore, as noted by Competitive Suppliers and EEI, even if LMPs exceed 

$1,000/MWh for only a few hours during the year, the resulting LMPs in those hours 

could affect long-term price signals.91 For all of these reasons, we conclude that the 

existing offer caps are not just and reasonable and, thus, need to be reformed.

39. With respect to the applicability of the reforms adopted in this Final Rule, we find 

that making the reforms applicable to all RTOs/ISOs will avoid seams issues that could 

arise if RTOs/ISOs had different offer caps.92 We find that these offer cap reforms will 

also result in more economically efficient flows between RTOs/ISOs because 

transactions across RTO/ISO seams will occur based on economic merit rather than based 

on differences in the offer cap.93

40. We also find that continued use of temporary waivers related to the offer cap, as 

advocated by some commenters, is an inappropriate remedy for problems associated with 

 90 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 7.

91 Competitive Suppliers Comments at 9; EEI Comments at 5.

92 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 70-71.

93 Id. P 74.
Docket No. RM16-5-000 - 30 -

current offer caps in RTOs/ISOs. The reforms adopted in this Final Rule will provide 

more certainty to market participants and reduce the administrative burden on 

RTOs/ISOs associated with requests for temporary waivers of various tariff provisions 

related to the $1,000/MWh offer caps prior to the start of every winter to ensure that 

resources are given the opportunity to recover their costs.94 We also find that problems 

identified with the current offer caps are better addressed through a rulemaking rather 

than through continued use of either ad hoc actions to approve tariff waivers or 

temporary changes to tariff provisions to remedy issues associated with existing 

RTO/ISO offer caps.

41. We find that the reasons for requiring the proposed offer cap reforms apply 

equally to CAISO. As discussed above, the potential for resources to have short-run 

marginal costs above CAISO’s current $1,000/MWh offer cap requires some action to 

ensure that resources have an opportunity to recover costs. As in other RTO/ISO 

markets, increasing the offer cap will improve price formation in CAISO at times when 

the short-run marginal costs of CAISO resources exceed $1,000/MWh. CAISO’s lack of 

a seam with another RTO/ISO does not alter these effects. Contrary to the implication of 

CAISO’s argument, as explained above, we are not relying on the avoidance of seams 

issues as the sole rationale for adopting this Final Rule. With respect to comments 

regarding the WECC offer cap, we find that this issue is unique to CAISO, and if CAISO 

 94 Id. PP 45, 49 (citing Notice Inviting Comments, Docket No. AD14-14-000 at 2).
Docket No. RM16-5-000 - 31 -

finds that this Final Rule raises seams issues with WECC, it may raise such issues 

elsewhere.

IV. Offer Cap Reforms

42. Having concluded that the existing offer caps are not just and reasonable, 

section 206 of the Federal Power Act requires that the Commission determine the 

practices that are just and reasonable.95 We direct each RTO/ISO to establish in their 

tariffs the following three requirements:

(1) A resource’s incremental energy offer must be capped at the higher of 

$1,000/MWh or that resource’s cost-based incremental energy offer. For the purpose 

of calculating Locational Marginal Prices, Regional Transmission Organizations and 

Independent System Operators must cap cost-based incremental energy offers at 

$2,000/MWh. (Offer cap structure requirement)

(2) The costs underlying a resource’s cost-based incremental energy offer above 

$1,000/MWh must be verified before that offer can be used for purposes of calculating 

Locational Marginal Prices. If a resource submits an incremental energy offer above 

$1,000/MWh and the costs underlying that offer cannot be verified before the market 

clearing process begins, that offer may not be used to calculate Locational Marginal 

Prices and the resource would be eligible for a make-whole payment if that resource is 

dispatched and the resource’s costs are verified after-the-fact. A resource would also be 

eligible for a make-whole payment if it is dispatched and its verified cost-based 

incremental energy offer exceeds $2,000/MWh. (Verification requirement)

(3) All resources, regardless of type, are eligible to submit cost-based incremental 

energy offers in excess of $1,000/MWh. (Resource neutrality requirement)

43. The offer cap structure requirement is discussed in section IV.A. The verification 

requirement is discussed in section IV.B. The resource neutrality requirement is 

discussed in section IV.C. 

 95 16 U.S.C. 824e (2012).
Docket No. RM16-5-000 - 32 -

A. Offer Cap Structure

1. NOPR Proposal

44. In the NOPR, the Commission proposed the following offer cap structure 

requirement:

A resource’s incremental energy offer used for purposes of calculating Locational 

Marginal Prices in energy markets must be capped at the higher of $1,000/MWh 

or that resource’s cost-based incremental energy offer.96

The Commission sought comments on this proposed offer cap structure requirement and 

whether a hard cap that limited the incremental energy offers used to calculate LMPs 

would be necessary. The Commission also sought comment on whether the level of the 

hard cap should be $2,000/MWh or another value.97

2. Comments

45. Comments about the proposed offer cap structure focus on two key areas: 

(1) whether incremental energy above $1,000/MWh should be cost-based; and (2) how 

LMPs should be calculated when resource short-run marginal costs exceed $1,000/MWh, 

including whether resources with costs above $1,000/MWh should be compensated 

through higher LMPs or through uplift, whether a hard cap is necessary, and the 

appropriate level of any hard cap.

. 

 96 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 53.

97 See id. P 55.
Docket No. RM16-5-000 - 33 -

a. Whether Incremental Energy Offers above $1,000/MWh 

Should be Cost Based

46. Commenters differed on the proposal to limit incremental energy offers above 

$1,000/MWh to cost-based incremental energy offers. Some commenters support this 

proposal and argue that it is appropriate to limit incremental energy offers that are not

cost-based to $1,000/MWh as a backstop mitigation measure.98 As discussed further 

below,99 many commenters support the verification requirement proposed in the NOPR 

and stress that incremental energy offers above $1,000/MWh must be cost-based 

incremental energy offers before such offers are eligible to calculate LMPs.100

47. Regarding offer caps in general, MISO states that the offer cap is currently 

necessary because demand in RTO/ISO energy and ancillary service markets is inelastic 

and also because they serve as a safety net.101 MISO adds that offer caps should be set 

high enough so as not to interfere with valid market dynamics.102 NY Transmission 

 98 MISO Comments at 7; NY Transmission Owners Comments at 2-3.

99 See infra PP 100-101.

100 See generally NYISO Comments at 2; SCE Comments at 1-2; PG&E 

Comments at 3; NY Transmission Owners Comments at 3; Golden Spread Comments at 

3; Delaware Commission Comments at 11; TAPS Comments at 12; NESCOE Comments 

at 3. 

101 MISO Comments at 7.

102 Id. at 7.
Docket No. RM16-5-000 - 34 -

Owners maintain that the $1,000/MWh offer cap is an important backstop to protect 

consumers from the exercise of market power should mitigation fail.103 

48. Some commenters argue that the $1,000/MWh threshold, above which a 

resource’s incremental energy offer submitted to the RTO/ISO must be cost-based, is too 

high. The Delaware and New Jersey Commissions recommend that in PJM, all 

incremental energy offers above $400/MWh be verified before such offers are eligible to 

set LMP,104 and the Pennsylvania Commission asks the Commission to carefully consider 

the threshold above which incremental energy offers are verified.105 The PJM Market 

Monitor states that there is no reason that $1,000/MWh should be the dividing line 

between incremental energy offers that can include markups and incremental energy 

offers that must be cost-based, and that the threshold could be lowered to $500/MWh 

in PJM noting that only 0.17 percent of all offers were above $400/MWh in 2015.106

49. Exelon states that while it supports removing the offer cap completely, if the 

Commission finds that incremental energy offers above a certain threshold must be cost-

 103 NY Transmission Owners Comments at 2-3. 

104 Delaware Commission Comments at 4-7; New Jersey Commission Comments 

at 9.

105 Pennsylvania Commission Comments at 10-13.

106 PJM Market Monitor Comments at 2.
Docket No. RM16-5-000 - 35 -

based,107 Exelon recommends a $2,000/MWh threshold which it states is above a recent 

fully supported cost-based incremental energy offer of $1,724/MWh seen in PJM in 

2014.108 Exelon also recommends that this threshold be reevaluated on a triennial basis 

to ensure it reflects market realities.109 

50. Other commenters support an absolute cap on the incremental energy offers, even 

if a resource’s short-run marginal costs exceed that cap.110 Industrial Customers also 

claim that if incremental energy offers above $1,000/MWh are permitted, resources 

would have no incentive to minimize their fuel costs because they would recover all of 

their costs if they were dispatched by the RTO/ISO.111 Potomac Economics states that 

resources should be prohibited from submitting incremental energy offers above 

$2,000/MWh, and claims that without such an absolute cap, natural gas prices could be 

bid up to extraordinary levels.112 

 107 Exelon refers to this threshold as a “market-based offer cap.” See, e.g., Exelon 

Comments at 1, 7-10.

108 Exelon Comments at 9-10. 

109 Id. at 10.

110 Industrial Customers Comments at 10; Potomac Economics Comments at 7.

111 Industrial Customers Comments at 19.

112 Potomac Economics Comments at 7. Potomac Economics is the external 

independent market monitor for NYISO, MISO, and ISO-NE. ISO-NE and NYISO also 

have internal Market Monitoring Units. 
Docket No. RM16-5-000 - 36 -

51. However, several commenters state that resources should be able to submit 

incremental energy offers that reflect their short-run marginal costs, even if those offers 

exceed $1,000/MWh.113 For example, CEA argues that it is prudent to modify current 

offer caps to allow resources to submit incremental energy offers above $1,000/MWh 

when fuel and other inputs cause the marginal cost of production to exceed 

$1,000/MWh.114 PJM Power Providers argue that raising the offer cap is important 

because it would allow energy clearing prices to reflect market conditions and provide 

stability to consumers and suppliers by eliminating the need for ad hoc waivers.115 

52. Some commenters argue that offer caps that limit the incremental energy offers 

that resources can submit should be increased116 or removed entirely.117 For example, 

 113 See generally Competitive Suppliers Comments at 12-14; Dominion Comments 

at 3-4; EEI Comments at 3-4; Golden Spread Comments at 1; MISO Comments at 6; 

NY Transmission Owners Comments at 3; OMS Comments at 3; PJM/SPP Comments 

at 6; PJM Market Monitor Comments at 1; Six Cities Comments at 2.

114 CEA Comments at 3-4. 

115 PJM Power Providers Comments at 1-2 (citing NOPR, FERC Stats. & Regs. 

¶ 32,714 at PP 14, 16, 17).

116 API Comments at 3, 8, 13; Exelon Comments at 7; OMS Comments (on behalf 

of Public Utility Commission of Texas (Texas Commission), referring to MISO’s 

$1,000/MWh offer cap) at 3 n. 7; NEI Comments at 2, 4-5.

117 NEI Comments at 2, 4-5; Competitive Suppliers Comments at 4-5, 7, 13-15; 

Exelon Comments at 9-10.
Docket No. RM16-5-000 - 37 -

API and the Texas Commission argue that the offer cap should be raised significantly.118 

The Texas Commission asserts that MISO’s offer cap should be raised significantly to 

provide greater assurance of resource adequacy, reduce administrative complexity, and 

minimize uplift charges.119 

53. MISO states that it does not oppose the NOPR proposal to revise the offer cap 

because the proposal will allow market clearing prices to more accurately reflect the true 

marginal cost of production while protecting consumers from the effects of manipulation

and improving price transparency, and the proposal should also reduce uplift 

payments.120 However, MISO urges the Commission to consider whether the offer cap 

proposal in the NOPR is an appropriate long-term approach and states that it could 

support a gradual relaxation of offer caps to allow market forces to respond 

accordingly.121

54. PJM Power Providers assert that resources should be able to submit cost-based 

incremental energy offers that reflect all short-run marginal costs.122 Competitive 

Suppliers and Exelon argue that the offer cap should be removed entirely, or raised to 

 118 API Comments at 3, 8, 13; OMS Comments (on behalf of Texas Commission) 

at 3 n.7.

119 OMS Comments (on behalf of Texas Commission) at 3 n.7.

120 MISO Comments at 6.

121 Id. at 7.

122 PJM Power Providers Comments at 2.
Docket No. RM16-5-000 - 38 -

avoid adverse impacts on the market.123 According to Competitive Suppliers, significant 

improvements in electricity markets and market monitoring have occurred since the 

$1,000/MWh offer cap was put in place nearly 20 years ago.124 Competitive Suppliers 

also argue that, given these improvements, the offer cap should be removed, or if that 

approach is not taken, the verification process should involve minimal distortions.125

b. How LMPs Should Be Calculated When Resource ShortRun Marginal Costs Exceed $1,000/MWh

55. Several commenters discuss how LMPs should be calculated when resource shortrun marginal costs exceed $1,000/MWh, with some commenters arguing that LMPs 

should rise to reflect the marginal cost of production and others arguing that resources 

with short-run marginal costs above $1,000/MWh should be compensated outside of the 

market through uplift rather than through higher LMPs. Commenters also discuss the 

need for a hard cap and the appropriate level for any hard cap.

i. Whether to Compensate Resources With Costs 

Above $1,000/MWh Through Uplift or Higher 

LMPs

56. As noted above,126 several commenters state that incremental energy offers above 

$1,000/MWh should be used to calculate LMPs because the resulting LMPs will better 

 123 Competitive Suppliers Comments at 4-5, 8, 14; Exelon Comments at 10.

124 Competitive Suppliers Comments at 8, 14-15.

125 Id. at 4-5.

126 See supra P 17.
Docket No. RM16-5-000 - 39 -

reflect the marginal costs of production.127 MISO states that permitting cost-based 

incremental energy offers above $1,000/MWh to set LMPs should improve price 

transparency and should reduce uplift payments.128 EEI states that competitive wholesale 

electricity markets should provide accurate price signals and that cost-based incremental 

energy offers above $1,000/MWh should be used to calculate LMPs because LMPs 

should reflect the marginal cost of operating the system, which will promote efficient 

operation, resource accuracy, and result in savings for consumers.129 

57. However, other commenters argue that incremental energy offers above 

$1,000/MWh, even if they are cost-based, should not be able to set LMP.130 For 

example, Industrial Customers argue that letting incremental energy offers set LMP 

would be a windfall to resources.131 Many commenters argue that uplift or temporary 

waivers should be used to account for instances when resources’ short-run marginal costs 

 127 CEA Comments at 3-4; Competitive Suppliers Comments at 9-13; EEI 

Comments at 3; Exelon Comments at 5-7; Powerex Comments at 6; PJM Providers 

Group Comments at 2; Golden Spread Comments at 1; MISO Comments at 6; PJM/SPP 

Comments at 1-2.

128 MISO Comments at 6. 

129 EEI Comments at 3-4.

130 APPA, NRECA, and AMP Comments at 8-10; Industrial Customers Comments 

at 9; NY Department of State Comments at 3; ODEC Comments at 3; PJM Joint 

Consumer Advocates Comments at 5; TAPS Comments at 5-6; Steel Producers’ Alliance 

Comments at 3.

131 Industrial Customers Comments at 9.
Docket No. RM16-5-000 - 40 -

exceed the offer cap. Some commenters argue that rather than letting incremental energy 

offers above $1,000/MWh set LMP, resources with costs above the $1,000/MWh offer 

cap should be compensated through uplift.132 For example, the New York Commission

argues that an uplift mechanism could ensure that generators can recover all short-run 

marginal costs.133 KEPCo/NCEMC asserts that if cost-based incremental energy offers 

above $1,000/MWh are based on inaccurate fuel cost estimates, there may be no means 

of remedying the effects on the markets.134 KEPCo/NCEMC add that uplift is a more 

cost effective way to ensure both resource cost recovery and just and reasonable prices.135 

Industrial Customers assert that uplift is preferable to using incremental energy offers 

above $1,000/MWh to calculate LMP because uplift payments ensure cost recovery and 

can be limited to the resources that are necessary to balance supply and demand, rather 

than compensating all resources.136

 132 APPA, NRECA, and AMP Comments at 8, 13-14, 16; Industrial Customers 

Comments at 8-9, 23-24; KEPCo/NCEMC Comments at 4; TAPS Comments at 5-6; 

New York Commission Comments at 6-7; SPP Market Monitor Comments at 2, 4, 6-7; 

Industrial Energy Consumers Comments at 2. 

133 New York Commission Comments at 6-7. 

134 KEPCo/NCEMC Comments at 4.

135 Id. at 4. 

136 Industrial Customers Comments at 8-9.
Docket No. RM16-5-000 - 41 -

ii. Whether to Adopt a Hard Cap

58. Comments differ on the need for a hard cap that would limit the incremental 

energy offers RTOs/ISOs use to calculate LMPs, a limit referred to herein as a hard cap. 

Many commenters support a hard cap,137 and some argue that a hard cap serves as an 

important backstop mitigation measure to address concerns about the competitiveness of 

natural gas markets or as a means to protect consumers from unreasonably high LMPs.138 

59. CAISO, ISO-NE, and NYISO support a hard cap. CAISO asserts that, assuming it 

were able to verify cost-based offers above $1,000/MWh, a hard cap is necessary if the 

Commission permits resources to submit incremental energy offers above 

$1,000/MWh.139 CAISO adds that a hard cap may help mitigate price spikes in fuel 

markets.140 ISO-NE supports a hard cap established at a fixed level and argues that any 

new offer cap should be imposed in a straightforward manner such that market 

participants know the level of the offer cap with certainty when making advance fuel 

 137 ISO-NE Comments at 3; ISO-NE Market Monitor Comments at 12; 

Joseph Margolies Comments at 8; NYISO Comments at 7; SPP Market Monitor 

Comments at 2, 13; TAPS Comments at 7.

138 Direct Energy Comments at 3-5; Industrial Customers Comments at 12; ISONE Comments at 3; Joseph Margolies Comments at 3; Potomac Economics Comments 

at 7; NY Department of State Comments at 3; TAPS Comments at 7. 

139 CAISO Comments at 10. As noted in P 20, supra, CAISO opposes raising 

CAISO’s current $1,000/MWh offer cap. 

140 Id. at 10. CAISO refers to the hard cap as a “secondary hard cap.” 
Docket No. RM16-5-000 - 42 -

supply arrangements.141 NYISO asserts that a hard cap will protect the market from the 

inadvertent submission of offers above the cap, create bounds for offers that are difficult 

to verify, and prevent potential attempts to exercise market power that are not otherwise 

addressed by existing mitigation rules.142 While MISO takes no position on a hard cap as 

discussed further below,143 MISO states that a hard cap is easier to integrate with other 

market design elements because it is more challenging to establish the appropriate levels 

for other market elements, such as MISO’s Operating Reserve and Transmission 

Constraint demand curves, without a hard cap because the maximum incremental energy 

offers would not be limited to a pre-defined value.144

60. Potomac Economics, and the ISO-NE and PJM market monitors stress the need 

for the hard cap to address concerns about uncompetitive conditions in natural gas 

markets when natural gas supplies are scarce.145 Potomac Economics contends that 

during natural gas shortages, natural gas markets have two dominant customer types: 

local gas distribution companies and natural gas generators.146 Potomac Economics 

 141 ISO-NE Comments at 2-3.

142 NYISO Comments at 8.

143 See infra P 69.

144 MISO Comments at 13.

145 ISO-NE Market Monitor Comments at 13-14; Potomac Economics Comments 

at 7; PJM Market Monitor Comments at 4. 

146 Potomac Economics Comments at 7.
Docket No. RM16-5-000 - 43 -

states that natural gas generators are frequently the marginal buyers since local gas 

distribution companies will not interrupt supply to their customers at any price. Potomac 

Economics asserts that without a hard cap, natural gas prices could be bid up to 

extraordinary levels because local distribution companies are guaranteed to recover their 

cost, regardless of how high.147 The PJM Market Monitor also states that verticallyintegrated utilities with a gas marketing function could have the incentive to exercise 

market power in natural gas markets during extreme conditions in an effort to exercise 

market power in electricity markets.148

61. The ISO-NE Market Monitor also asserts that natural gas markets lack structural 

measures to prevent the exercise of market power. According to the ISO-NE Market 

Monitor, the offer cap in electricity markets can impact prices in natural gas markets 

when natural gas supplies are scarce because natural gas resources, particularly resources 

with must-offer requirements, are the marginal customers in natural gas markets and thus 

have a significant impact on natural gas prices.149 

62. Although the PJM Market Monitor argues that, in the absence of market power, 

there should be no absolute cap on the short-run marginal costs reflected in an 

 147 Id.

148 PJM Market Monitor Comments at 4.

149 ISO-NE Market Monitor Comments at 13-14.
Docket No. RM16-5-000 - 44 -

incremental energy offer,150 the PJM Market Monitor opines that the removal of hard 

caps in electricity markets should be considered in light of the competitiveness of natural 

gas markets. The PJM Market Monitor asserts that it is essential that market participants 

have confidence in the competitiveness of natural gas markets before removing hard caps 

in electricity markets.151 

63. The ISO-NE, PJM, and SPP market monitors also explain that when natural gas 

supplies are scarce, open exchanges for natural gas, such as the Intercontinental 

Exchange (ICE), tend to have low liquidity and wide bid-ask spreads. These market 

monitors state that it can be difficult to verify the short-run marginal cost of natural gas 

resources during periods when open natural gas exchanges have low liquidity because 

natural gas resources may purchase natural gas bilaterally rather than through the 

exchanges, and therefore the bid and ask spreads and settled transactions observed on 

the open exchanges may not represent the costs of the natural gas resources that make 

bilateral natural gas purchases. Furthermore, when liquidity in the open exchanges is 

low and the bid-ask spreads are wide, the ISO-NE, PJM, and SPP market monitors 

explain that there may be little basis on which to verify a resource’s natural gas 

procurement costs.152

 150 PJM Market Monitor Comments at 1.

151 Id. at 4.

152 ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6; 

SPP Market Monitor Comments at 7.
Docket No. RM16-5-000 - 45 -

64. The New Jersey Commission and NY Transmission Owners also argue that a 

hard cap is necessary to address issues related to the interactions between the gas and 

electricity markets.153 NY Transmission Owners explains that resource owners with

costs above $1,000/MWh that also own infra-marginal resources may benefit from 

paying more for natural gas which in turn increases LMPs and thus the revenues that 

infra-marginal resources receive.154 NY Transmission Owners further states that it will 

be difficult for market monitors to ascertain whether the price a resource has paid for 

natural gas reflects its expectations about the electricity market or an attempt to impact 

LMPs, and suggests that a hard cap can address these issues.155 The New Jersey 

Commission similarly states that, absent a hard cap, market power in natural gas markets 

could drive up cost-based incremental energy offers in electricity markets and increase 

LMPs.156

65. The SPP Market Monitor states that it would prefer to maintain SPP’s existing 

$1,000/MWh offer cap, but if it is to be revised, it would prefer a new fixed hard cap to 

 153 NY Transmission Owners Comments at 3-4; New Jersey Commission 

Comments at 9.

154 NY Transmission Owners Comments at 4.

155 Id.

156 New Jersey Commission Comments at 9. 
Docket No. RM16-5-000 - 46 -

serve as a backstop market power mitigation measure during periods of market anomalies 

when existing measures may fail to protect consumers.157

66. Comments from other stakeholders generally support a hard cap to protect 

customers against market power abuse.158 For example, the Ohio Commission asserts 

that if the Commission does not require PJM and the PJM Market Monitor to jointly 

review these cost-based energy offers, the $2,000/MWh hard cap in PJM should remain 

to protect against market power concerns and unverified price increases.159 Industrial 

Customers argue that the offer cap works in tandem with market power mitigation 

measures to prevent excessive prices when supplies are tight given that demand is 

inelastic.160 

67. Some commenters argue that a hard cap is necessary to protect customers from 

unjust and unreasonable prices resulting from market aberrations or other events when 

RTOs/ISOs fail to function properly.161 For example, TAPS asserts that removing the 

offer cap entirely would result in the Commission failing to meet its statutory duty to 

 157 SPP Market Monitor Comments at 6, 13.

158 See generally Direct Energy Comments at 4-5; Ohio Commission Comments 

at 6-7; Industrial Customers Comments at 10-11; TAPS Comments at 8-10; New Jersey 

Commission Comments at 7.

159 Ohio Commission Comments at 6-7.

160 Industrial Customers Comments at 10-11.

161 TAPS Comments at 8-9; Industrial Customers Comments at 19-20. 
Docket No. RM16-5-000 - 47 -

protect against excessive prices,

162 and it argues that the hard cap provides crucial 

damage control to shield consumers from unreasonably high prices.163 Industrial 

Customers argue that the hard cap helps discipline generator fuel procurement costs, 

stating that full cost recovery would significantly reduce incentives for generators to 

minimize their costs if these costs can be passed on to consumers.164 

68. Commenters opposed to the inclusion of a hard cap on offers used to calculate 

LMPs generally argue that any cap would artificially suppress LMPs and increase uplift 

payments.165 PJM/SPP state that there should not be a hard cap on cost-based offers used 

to calculate LMPs provided that appropriate verification processes are in place to ensure 

cost-based incremental offers reflect legitimate costs.166 PJM/SPP also assert that a hard 

cap can create unhedgeable uplift payments.167 PJM Power Providers assert that 

 162 TAPS Comments at 10 (citing FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 

760, 764 (2016)). 

163 Id. at 9-10. 

164 Industrial Customers Comments at 19-20. 

165 Competitive Suppliers Comments at 12-15; Dominion Comments at 4; Exelon 

Comments at 21-22; Golden Spread Comments at 2; PJM/SPP Comments at 6; EEI 

Comments at 7.

166 PJM/SPP Comments at 6.

167 Id.
Docket No. RM16-5-000 - 48 -

resources should be able to submit cost-based incremental energy offers that reflect 

their short-run marginal costs and that those offers should be able to set the LMP.168

69. MISO states that it does not have a strong preference on the imposition of a hard 

cap and notes that the same benefits and drawbacks that exist for the current 

$1,000/MWh hard cap (in some markets) would apply to any new hard cap.169 MISO 

identifies two drawbacks of a hard cap: (1) a hard cap could suppress LMPs below the 

marginal cost of production; and (2) a special uplift mechanism would be needed for 

offers that exceed the hard cap.170 MISO states that a hard cap may not be necessary 

because the verification requirement safeguards the market and states that the limitations 

and implementation costs associated with a hard cap would likely overshadow the 

benefits.171 

70. Exelon and EEI oppose a hard cap, arguing that it is important for LMPs to be as 

consistent as possible with the marginal cost of operating the system and that, therefore, 

resources should always be permitted to offer their costs, and that such offers should 

 168 PJM Power Providers Comments at 2.

169 MISO Comments at 13.

170 Id.

171 MISO Comments at 13.
Docket No. RM16-5-000 - 49 -

always be eligible to set LMP.172 As noted above, Competitive Suppliers assert that the 

offer cap should be removed entirely.173

71. Additionally, some commenters opposed to a hard cap assert that existing market 

monitoring and mitigation measures, as well as the proposed verification requirement for 

cost-based incremental energy offers above $1,000/MWh, render a hard cap unnecessary 

and duplicative.174 For example, Dominion states that a hard cap is not necessary for

cost-based incremental energy offers because market power concerns are not relevant for

cost-based incremental energy offers as offers based on resource costs do not constitute 

an exercise of market power.175 

72. Commenters disagree about the appropriate level for any new hard cap. ISO-NE 

states that it does not have evidence to substantiate a specific recommendation for the 

level of any new hard cap.176 NYISO states that the Commission should hold a technical 

workshop to determine the appropriate level of the hard cap that analyzes the elasticity of 

 172 Exelon Comments at 21; EEI Comments at 4. 

173 Competitive Suppliers Comments at 13. 

174 Competitive Suppliers Comments at 14; PJM/SPP Comments at 6; Dominion 

Comments at 4.

175 Dominion Comments at 4. 

176 ISO-NE Comments at 3. 
Docket No. RM16-5-000 - 50 -

the fuel markets, including natural gas markets, and fuel prices at various demand 

levels.177

73. Potomac Economics states that the $2,000/MWh level approved in PJM would be 

a reasonable hard cap for all RTOs/ISOs in the Eastern Interconnect.178 However, 

Potomac Economics states that the Commission should adopt a $2,000/MWh cap that not 

only caps the incremental energy offers eligible to set LMP but also prevents resources 

from recovering incremental energy costs above $2,000/MWh.179 Potomac Economics 

adds that the loss of generation resulting from any natural gas resources that do not 

procure natural gas during natural gas shortages due to such a cap will not substantially 

increase the probability of an electric outage.180

74. TAPS argues that offers above $1,500/MWh should not be used to calculate LMPs 

because a MISO analysis indicated that natural gas resources in MISO would have a 

marginal cost below $1,138/MWh if natural gas prices reached $65/MMBtu and that 

more than 98 percent of MISO’s gas capacity would have a marginal cost below 

 177 NYISO Comments at 8. 

178 Potomac Economics Comments at 7-8.

179 Id. at 8. Potomac Economics notes that its recommendation would require 

modifying PJM’s current offer cap, which permits resources to recover costs above 

PJM’s $2,000/MWh hard cap.

180 Id.
Docket No. RM16-5-000 - 51 -

$1,500/MWh if gas prices reached $100/MMBtu.181 TAPS further argues that 

$2,000/MWh is too high and that the value was not supported by PJM other than as a 

compromise between PJM stakeholders.182 Midcontinent Joint Consumer Advocates 

argue that a $2,000/MWh hard cap is unreasonably high and could cause prices to rise up 

to $2,000/MWh.183 

75. As noted above, some commenters support a $1,000/MWh hard cap on the 

incremental energy offers that are used to calculate LMPs.184 For example, APPA, 

NRECA, and AMP assert that the hard cap should be set to $1,000/MWh in all 

RTOs/ISOs, including PJM, which currently has a $2,000/MWh hard cap.185 Direct 

Energy and NY Transmission Owners state that different hard caps across RTOs/ISOs 

may be justified given differences in regional natural gas prices, but add that RTOs/ISOs 

with the same natural gas supply should have the same hard cap.186 Additionally, APPA, 

NRECA, and AMP, ODEC, PJM Joint Consumer Advocates, and Steel Producers’ 

 181 TAPS Comments at 10-11. TAPS uses the phrase “hard offer cap,” which 

could indicate that RTOs/ISOs should limit offers to $1,500/MWh for purposes of 

calculating LMPs or that resources should not be able to submit incremental energy 

offers above $1,500/MWh. 

182 Id. at 11. 

183 Midcontinent Joint Consumer Advocates Comments at 4.

184 New Jersey Commission Comments at 8-9; TAPS Comments at 10-11; APPA, 

NRECA, and AMP Comments at 8-9. 

185 APPA, NRECA, and AMP Comments at 9. 

186 Direct Energy Comments at 3-4; NY Transmission Owners Comments at 5.
Docket No. RM16-5-000 - 52 -

Alliance all ask the Commission to reinstate PJM’s previous $1,000/MWh offer cap.187 

ODEC and PJM Joint Consumer Advocates state that although they supported the 

consensus position on PJM’s current $2,000/MWh offer cap as an interim measure, they 

state that they were awaiting Commission action on offer caps and do not support such a 

cap as a long-term policy.188 ODEC and PJM Joint Consumer Advocates argue that the 

$2,000/MWh offer cap on cost-based offers is no longer necessary and that a 

$1,000/MWh offer cap is more appropriate because new measures, such as PJM’s new 

capacity construct and additional measures implemented in response to the Polar Vortex,

will ensure that prices remain at reasonable levels.189

76. Dominion states that the NOPR proposal will result in more accurate price signals 

and a better understanding of the true costs of serving demand, reduce uplift during 

stressed periods, and allow customers to more effectively hedge the costs of reliability 

through market participation.190 NESCOE states that the offer cap reforms proposed in 

the NOPR appear to appropriately balance price formation issues, seams issues, and the 

 187 APPA, NRECA, and AMP Comments at 7; ODEC Comments at 3-5; PJM 

Joint Consumer Advocates Comments at 2-4; Steel Producers’ Alliance Comments at 5.

188 ODEC Comments at 3; PJM Joint Consumer Advocates Comments at 2.

189 ODEC Comments at 5; PJM Joint Consumer Advocates Comments at 2-3.

190 Dominion Comments at 3.
Docket No. RM16-5-000 - 53 -

potential for market power abuse while allowing for regional variation in implementing 

consumer protection mechanisms.

191 

3. Determination

77. The Commission is adopting aspects of the offer cap structure set forth in the 

NOPR, which caps a resource’s incremental energy offer used for purposes of calculating 

LMPs in day-ahead and real-time energy markets at the higher of $1,000/MWh or that 

resource’s cost-based incremental energy offer. Based on the comments received in this 

proceeding, the Commission is also adopting a hard cap as part of this Final Rule.192 

Although a resource may submit a cost-based incremental energy offer above 

$2,000/MWh, the hard cap will prohibit the use of such offers above $2,000/MWh when 

calculating LMPs. As discussed further in section IV.B below, incremental energy offers 

above $1,000/MWh must be verified before they are used to calculate LMPs. As noted 

above, RTOs/ISOs must cap verified cost-based incremental energy offers at 

$2,000/MWh when calculating LMPs.

78. As a result of this Final Rule, an RTO/ISO will treat resources’ incremental energy 

offers differently, depending on the level of the offer itself. Each RTO/ISO shall treat 

incremental energy offers below $1,000/MWh as it currently does. Such offers: (1) are 

subject to existing RTO/ISO market power mitigation procedures and are not required to 

 191 NESCOE Comments at 2.

192 The hard cap was not included in the proposal set forth in the NOPR, but the 

Commission sought comment on it. See NOPR, FERC Stats. & Regs. ¶ 32,714 at P 55.
Docket No. RM16-5-000 - 54 -

be cost-based; and (2) may be used to calculate LMPs. A resource may only submit an 

incremental energy offer equal to or above $1,000/MWh if the offer is cost-based, that is, 

if the offer accurately reflects that resource’s actual or expected short-run marginal costs. 

For an incremental energy offer equal to or above $1,000/MWh and less than or equal to 

$2,000/MWh, the RTO/ISO or Market Monitoring Unit must verify that the offer is costbased before the RTO/ISO may use the offer to calculate LMPs. For an incremental 

energy offer above $2,000/MWh, the RTO/ISO or Market Monitoring Unit must also 

verify that the offer is cost-based. Cost-based incremental energy offers in excess of 

$2,000/MWh will be capped at $2,000/MWh for purposes of calculating LMPs. As such, 

the $2,000/MWh hard cap places an upper limit on the incremental energy offers that the 

RTO/ISO can use to calculate LMPs.193 We note that the resulting LMPs may exceed 

$2,000/MWh due to losses and congestion. Additionally, resources with verified costbased incremental energy offers above $2,000/MWh will be eligible to receive uplift. 

79. After consideration of the record in this proceeding, including responses to the 

question we asked about the need for a hard cap, we adopt a modified version of the offer 

cap structure proposed in the NOPR. This modified version recognizes the practical 

issues raised by commenters. While a hard cap may diminish the ability to fully address 

the shortcomings of the current offer caps identified above194 in all circumstances, we 

 193 The $2,000/MWh hard cap requires that the cost-based incremental energy 

offers that RTOs/ISOs may use to calculate LMPs may not exceed $2,000/MWh. 

194 See supra P 2.
Docket No. RM16-5-000 - 55 -

find that, on balance, a hard cap is necessary to reasonably limit the adverse impact that 

imperfect information about a resource’s short-run marginal costs during the verification 

process could have on LMPs.

80. First, the offer cap structure will reduce the likelihood that the $1,000/MWh offer 

cap in effect in some RTOs/ISOs195 will suppress LMPs below the marginal cost of 

production. Ideally, LMPs in RTO/ISO energy markets should reflect the short-run 

marginal cost of the marginal resource. Under the offer cap structure adopted in this 

Final Rule, cost-based incremental energy offers up to $2,000/MWh that have been 

verified by either the RTO/ISO or Market Monitoring Unit as being a reasonable 

reflection of a resource’s actual or expected short-run marginal cost may be used to 

calculate LMPs. 

81. Second, the offer cap structure and associated uplift payments discussed further in 

section IV.B below give resources the opportunity to be compensated for the short-run 

marginal costs they incur to provide service, which achieves the price formation goal of 

ensuring that resources have an opportunity to recover their costs. 

82. Third, the offer cap structure adopted in this Final Rule will encourage a resource 

to offer supply to the market when it is needed most. A resource that is compensated for 

its costs has an incentive to offer its supply into the market even when those costs are 

high, which often occurs when supplies are tight. Fourth, the offer cap structure enables 

 195 Specifically CAISO, ISO-NE, MISO, NYISO, and SPP.
Docket No. RM16-5-000 - 56 -

RTOs/ISOs to dispatch the most efficient set of resources when resources’ short-run 

marginal costs exceed $1,000/MWh.

83. We also find that the offer cap structure will mitigate market power associated 

with incremental energy offers above $1,000/MWh, as some commenters suggest. The 

requirement that incremental energy offers above $1,000/MWh be cost-based retains the 

backstop mitigation function that current offer caps play in existing RTO/ISO market 

power mitigation because incremental energy offers that are not cost-based may not 

exceed $1,000/MWh. A cost-based incremental energy offer is based on the associated 

resource’s short-run marginal cost, which constitutes a competitive offer free from the 

exercise of market-power. 

84. Revising the offer cap to permit cost-based incremental energy offers up to 

$2,000/MWh to set LMP will reduce the likelihood that the offer cap will suppress LMPs 

below the marginal cost of production. Permitting cost-based incremental energy offers 

up to $2,000/MWh to set LMP will also reduce uplift associated with the current offer 

caps, which will be beneficial to the market because uplift payments are less transparent 

to market participants than LMPs that reflect the marginal cost of production. Therefore, 

we disagree with arguments that all resources with short-run marginal costs above 

$1,000/MWh should be compensated through uplift rather than through the LMP. As 

discussed further below, we adopt a hard cap and provide cost recovery for resources 

with short-run marginal costs above $2,000/MWh to address practical concerns raised 

about the offer verification process. As discussed further below, some resources may not 

know their actual short-run marginal costs at the time they submit cost-based incremental 
Docket No. RM16-5-000 - 57 -

energy offers.196 Accordingly, the RTO/ISO or Market Monitoring Unit will have to 

verify that such offers reasonably reflect the associated resource’s expected short-run 

marginal costs, which necessarily involves an estimate. Furthermore, the information 

that RTOs/ISOs and/or Market Monitoring Units have to estimate and/or verify the shortrun marginal costs of some resources may be imperfect. For example, as noted above, 

information about the short-run fuel costs of certain natural gas-fired resources may be 

limited when natural gas supplies are scarce because publicly available natural gas 

indices may not be representative of the price that such resources actually pay for fuel.

197 

Given these limitations, we find it is appropriate to include a hard cap to ensure that 

LMPs calculated based on verified cost-based incremental energy offers above 

$1,000/MWh are just and reasonable.

85. We disagree with Industrial Customers that resources would have no incentive to 

minimize their fuel costs if the offer cap is above $1,000/MWh because, in the absence of 

market power, resources have an incentive to compete with other resources in order to 

clear the RTO/ISO day-ahead and real-time energy markets. Any resource that is able to 

procure natural gas at a cost less than the cost that sets the LMP will earn a profit and 

thus has a strong incentive to manage its fuel procurement. 

 196 See infra PP 105-108.

197 See supra P 63.
Docket No. RM16-5-000 - 58 -

86. However, as part of the offer cap structure, we will require a hard cap of 

$2,000/MWh on offers that are used to calculate LMPs. Under the hard cap, an RTO/ISO 

must place an upper limit, or hard cap, on the cost-based incremental energy offers that it 

uses to calculate LMPs.198 To implement the hard cap, we modify the offer cap structure 

requirement proposed in the NOPR and adopt the following offer cap structure 

requirement:

A resource’s incremental energy offer used for purposes of 

calculating Locational Marginal Prices in energy markets

must be capped at the higher of $1,000/MWh or that 

resource’s cost-based incremental energy offer. For the 

purpose of calculating Locational Marginal Prices, Regional 

Transmission Organizations and Independent System 

Operators must cap cost-based incremental energy offers at 

$2,000/MWh.

87. We find that a hard cap is necessary for two primary reasons. First, a hard cap 

will address the fact that RTOs/ISOs and/or Market Monitoring Units may have

imperfect information about resources’ short-run marginal costs during the verification 

process. As discussed further in section IV.B below, several commenters note that there 

may be imperfect information associated with the verification of cost-based incremental 

energy offers above $1,000/MWh prior to the market clearing process because some of 

those offers will be based on a resource’s estimate of its costs and RTOs/ISOs or Market 

 198 We note that PJM currently permits resources to submit cost-based incremental 

energy offers above its current $2,000/MWh hard cap, and PJM may use such offers to 

dispatch resources. However, incremental energy offers are capped at $2,000/MWh for 

purposes of calculating LMPs. See PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289.
Docket No. RM16-5-000 - 59 -

Monitoring Units may not have perfect information with which to estimate those costs. 

Additionally, as noted by market monitors, when natural gas spot market prices rise to 

levels that could result in the short-run marginal costs of some natural gas-fired resources 

exceeding $1,000/MWh, over-the-counter natural gas markets often lack liquidity or have 

wide bid-ask spreads, which can make verification challenging, particularly verification 

of expected costs. At those times, a market participant’s expected costs could vary 

significantly from its actual costs. Although, as discussed further below, only verified 

cost-based incremental energy offers above $1,000/MWh may be used to calculate LMPs

subject to the $2,000/MWh hard cap. We find that, on balance, a hard cap will 

reasonably limit the adverse impact that any imperfect information about resources’

short-run marginal costs during the verification process could have on LMPs. 

88. Second, we agree with MISO that a hard cap will be easier to integrate with other 

market constructs that place caps or upper bounds on various market elements (e.g., 

penalty factors associated with shortage pricing or violating transmission constraints). 

89. We are not persuaded by comments that a hard cap is duplicative of existing 

market power mitigation rules because existing market power mitigation provisions in 

most RTOs/ISOs only apply under certain circumstances, whereas this Final Rule 

essentially mitigates all incremental energy offers above $1,000/MWh to a level based on 

short-run marginal costs. Additionally, as noted above, the hard cap is necessary to 

address concerns about the imperfect information that RTOs/ISOs and/or Market 

Monitoring Units have about resources’ short-run marginal costs during the verification 

process.
Docket No. RM16-5-000 - 60 -

90. Having determined that a hard cap is necessary, we find that $2,000/MWh is a just 

and reasonable level for that hard cap based on the record in this proceeding. 

Historically, high natural gas prices during the Polar Vortex resulted in at least one 

resource with a cost-based incremental energy offer of $1,724/MWh.199 Based on this 

experience and noting that it occurred in an otherwise low natural gas price environment,

we expect that resources may experience costs that approach but are unlikely to exceed 

$2,000/MWh. With a hard cap of $2,000/MWh, we find that resources will be able to 

recover those costs and that LMPs will reflect marginal costs.200 The Commission has 

previously relied upon high and volatile natural gas prices as a justification for increasing 

offer caps.201 This $2,000/MWh level was also generally supported by Potomac 

 199 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 13 (citing PJM 2014 Offer Cap 

Order I, 146 FERC ¶ 61,041 at P 2). 

200 See Envtl. Action, Inc. v. FERC, 939 F.2d 1057, 1064 (D.C. Cir. 1991) (“it is 

within the scope of the agency’s expertise to make such a prediction about the market it 

regulates, and a reasonable prediction deserves our deference notwithstanding that there 

might also be another reasonable view.”). See also Michigan Consol. Gas Co. v. 

F.E.R.C., 883 F.2d 117, 124 (1989) (“It is also quite clear FERC may make predictions—

“[m]aking ... predictions is clearly within the Commission’s expertise” and will be upheld 

if “rationally based on record evidence.”) (citing East Tennessee Natural Gas Co. v. 

FERC, 863 F.2d 932, 938-39 (1988) (citing Associated Gas Distributors v. FERC, 

824 F.2d 981, 1008 (1987))).

201 See California Indep. Sys. Operator Corp., 114 FERC ¶ 61,026, at P 25 (2006) 

(In CAISO, natural gas prices rose from $3-$4/MMBtu when the bid cap in CAISO was 

$250/MWh to $14/MMBtu. Based on this information, the Commission found “that 

raising the bid cap is justified by the well-documented rise in gas prices” and accepted 

CAISO’s proposal to raise the bid cap from $250/MWh to $400/MWh.).
Docket No. RM16-5-000 - 61 -

Economics.202 With respect to treatment of cost-based incremental energy offers above 

$2,000/MWh, we expect RTOs/ISOs to use such offers to determine merit-order dispatch. 

We note that the Commission allowed this approach when accepting PJM’s current offer 

cap structure, in which PJM uses cost-based incremental energy offers above 

$2,000/MWh to determine merit order dispatch but limits cost-based incremental energy 

offers to $2,000/MWh for purposes of calculating LMPs.203 

91. We recognize that a $2,000/MWh hard cap leaves some possibility for price 

suppression when the marginal cost of production legitimately exceeds $2,000/MWh. 

However, by allowing verified cost-based incremental energy offers in the $1,000/MWh-

$2,000/MWh range to set LMPs, we significantly reduce the likelihood of such price 

suppression, and we find this balanced approach just and reasonable.

92. We decline to hold a technical workshop as suggested by NYISO or a triennial 

review as suggested by Exelon to determine an appropriate level for the hard cap because 

there is sufficient evidence in this record to support $2,000/MWh as a just and reasonable 

value. Based on the record, we decline to adopt a lower hard cap level, such as the 

$1,500/MWh value TAPS proposes, because this level is demonstrably lower than costbased incremental energy offers observed during the Polar Vortex. Additionally, the PJM 

 202 Potomac Economics Comments at 8.

203 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 11.
Docket No. RM16-5-000 - 62 -

Market Monitor reported that on 54 occasions in early 2015, resources submitted costbased incremental energy offers at prices above $1,000/MWh.204 

93. With respect to APPA, NRECA, and AMP’s argument that concerns over seams 

do not justify revising RTO/ISO offer caps, particularly because the Commission 

accepted PJM’s current $2,000/MWh offer cap, we reiterate that the Commission’s 

finding in that order was limited to the facts in that record. In accepting PJM’s proposal, 

the Commission stated that it would not prejudge broader reforms in the price formation 

proceeding.205

94. We decline to hold, as CAISO suggests, a technical workshop on implementation 

challenges. We expect that any issues regarding the implementation of this Final Rule 

will be raised by RTOs/ISOs on compliance, and the Commission will address them at 

that time. We also decline to implement a $400/MWh cap on incremental energy offers 

that are not cost-based, as some commenters have suggested. We find that the fact that 

resources rarely submit incremental energy offers above $400/MWh does not indicate 

that allowing resources to submit incremental energy offers as high as $1,000/MWh 

which are not cost-based (referred to as “market-based offers” in PJM) will result in 

unjust and unreasonable rates.

 204 Monitoring Analytics, Report on PJM Energy Market Offers January 16 to 

March 31, 2015, at 2 (May 1, 2015), available at

http://www.monitoringanalytics.com/reports/Reports/2015/IMM_Informational_Filing_D

ocket_No_EL15-31-000_20150505.pdf.

205 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 55.
Docket No. RM16-5-000 - 63 -

95. In response to MISO’s suggestion that future adjustments to the offer cap may be 

needed in response to market-based solutions that increase demand elasticity or resource 

mix changes, we decline to speculate as to what changes may or may not be necessary in 

the future.

B. Cost Verification 

1. NOPR Proposal

96. In the NOPR, the Commission proposed the requirement that cost-based 

incremental energy offers above $1,000/MWh be verified by the RTO/ISO or Market 

Monitoring Unit prior to being used to calculate LMPs (verification requirement).206 The 

Commission proposed the following verification requirement:

The costs underlying a resource’s cost-based incremental energy offer above 

$1,000/MWh must be verified before that offer can be used for purposes of 

calculating Locational Marginal Prices. If a resource submits an incremental 

energy offer above $1,000/MWh and the costs underlying that offer cannot be 

verified before the market clearing process begins, that resource’s incremental 

energy offer in excess of $1,000/MWh may not be used to calculate Locational 

Marginal Prices. In such circumstances a resource would be eligible for a makewhole payment if that resource clears the energy market and the resource’s costs 

are verified after-the-fact.207

97. The Commission reasoned that this requirement would ensure that the proposal 

results in LMPs that reflect the marginal cost of production during intervals when the 

marginal resource’s short-run marginal cost exceeds $1,000/MWh. Further, in the 

 206 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 56.

207 Id.
Docket No. RM16-5-000 - 64 -

NOPR, the Commission preliminarily found that the verification requirement was 

necessary to reduce the potential exercise of market power by resources, which could 

result in unjust and unreasonable rates.208 

2. Comments

98. As discussed further below, the Commission received several comments about the 

proposed verification requirement. Comments about the proposed verification 

requirement focus on whether it is needed and what type of verification would be 

acceptable and feasible. A number of commenters generally support the proposed 

verification requirement, but they express concerns or seek clarification about the 

proposed verification requirement.209

a. Need for the Verification Requirement

99. Commenters disagree about whether the proposed verification requirement for 

cost-based incremental energy offers above $1,000/MWh is necessary to reduce the 

potential exercise of market power. Several commenters support the verification 

 208 Id. P 57. 

209 ISO-NE Comments at 6; NYISO Comments at 2; PJM/SPP Comments at 2-3; 

TAPS Comments at 12.
Docket No. RM16-5-000 - 65 -

requirement,210 some asserting that the verification requirement is a critical element of 

the proposal.211 

100. OMS contends that the verification requirement protects retail consumers from 

unlimited and unjustified wholesale price increases.212 The Delaware Commission and 

TAPS assert that the verification requirement is necessary to address market power 

concerns.213 TAPS states that although it opposes revisions to the offer cap, the proposed 

verification requirement is needed to protect the integrity of the RTO/ISO markets and 

will help avoid litigation costs associated with re-running markets after-the-fact in the 

event that an LMP is subsequently found not to be cost-justified.214 PG&E and SCE 

generally support the prevention of unverified incremental energy offers above 

$1,000/MWh from setting the LMP, although PG&E does not support the proposal 

overall.215 

101. PJM Joint Consumer Advocates argue that the only way to protect consumers 

from unfair prices is to verify offers prior to the market clearing process and that fairness 

 210 SCE Comments at 1-2; PG&E Comments at 1-3; NY Transmission Owners 

Comments at 3.

211 Golden Spread Comments at 3; Delaware Commission Comments at 11; TAPS 

Comments at 12; NESCOE Comments at 3.

212 OMS Comments at 3.

213 Delaware Commission Comments at 11; TAPS Comments at 12-13.

214 TAPS Comments at 12-13.

215 PG&E Comments at 1-3; SCE Comments at 1-2.
Docket No. RM16-5-000 - 66 -

demands such a review, even if the verification process is technically complex. PJM 

Joint Consumer Advocates assert that market-based offers, which are not strictly tied to 

costs, should not be eligible to set LMP because they would unfairly inflate costs to 

consumers and result in a windfall for suppliers.216 

102. Other commenters assert that the verification requirement is unnecessary217 or 

unduly cumbersome.218 Potomac Economics and PJM Power Providers argue that cost 

verification is unnecessary given other RTO/ISO market constructs.219 Potomac 

Economics states that the justification for the proposed verification requirement is limited 

because competition is not diminished during the fuel price spikes that could cause a 

resource’s short-run marginal costs to exceed $1,000/MWh. Potomac Economics also 

argues that existing RTO/ISO market power mitigation measures address market power 

concerns.220 PJM Power Providers state that the verification requirement is unnecessary 

because resources have the incentive to submit incremental energy offers that reflect 

actual costs. PJM Power Providers assert that the threat of an investigation from the 

Commission’s Office of Enforcement and possible associated fines incent good behavior 

 216 PJM Joint Consumer Advocates Comments at 5.

217 Potomac Economics Comments at 12; PJM Power Providers Comments at 5.

218 OMS Comments (on behalf of Texas Commission) at 3 n.7.

219 Potomac Economics Comments at 12; PJM Power Providers Comments at 5.

220 Potomac Economics Comments at 12.
Docket No. RM16-5-000 - 67 -

and discourage the exercise of market power.221 Industrial Energy Consumers also state 

that the NOPR could lead markets to become more complicated and opaque, potentially 

leading to unintended consequences.222 

b. Verification Standard

103. The Commission sought comment on the Market Monitoring Unit’s or 

RTO’s/ISO’s ability to timely verify cost-based incremental energy offers above 

$1,000/MWh prior to the day-ahead or real-time market clearing process.223 In response, 

the Commission received a wide array of comments about the feasibility of the proposed 

verification requirement and the challenges associated with implementing the 

requirement. 

104. Many of the comments highlighted the difference between verification of actual 

costs and verification of expected costs. They noted that because verification has to 

occur before the market runs, verification of actual costs was more difficult than 

verification of expected costs. Indeed, several commenters contend that it is not possible 

prior to the market clearing process to verify that a resource’s cost based-incremental 

 221 Exelon Comments at 9; PJM Power Providers Comments at 5 (citing Public 

Citizen, Inc. v. Midcontinent Indep. Sys. Operator, Inc., 154 FERC ¶ 61,224, at P 88 

(2016)).

222 Industrial Energy Consumers Comments at 2.

223 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 59.
Docket No. RM16-5-000 - 68 -

energy offer equals that resource’s actual costs.224 Commenters raise two key obstacles 

to the verification of a resource’s actual costs prior to the market clearing process: 

(1) some natural gas resources do not know their actual costs at the time they submit 

offers; and (2) natural gas resource fuel costs are particularly difficult to verify during 

periods when natural gas supplies are scarce. Each obstacle is discussed in turn below.

i. Resource Cost Uncertainty When Submitting 

Offers

105. Many commenters, including RTOs/ISOs, market monitors, and generators, assert 

that because some resources, specifically natural gas resources, do not know their actual 

fuel procurement costs when they submit incremental energy offers to the RTO/ISO, it is 

impossible to verify the incremental energy offers of such resources prior to the market 

clearing process.225 

106. ISO-NE, MISO, and PJM/SPP state that some natural gas resources have not 

procured fuel by the time that they submit incremental energy offers to the RTO/ISO 

markets, and thus ISO-NE and PJM/SPP state that such resources often submit offers 

based on the cost that the resources expect to pay for natural gas on the natural gas spot 

 224 EEI Comments at 6; Exelon Comments at 11; IRC Comments at 2-3; ISO-NE

Comments at 2, 6-7; MISO Comments at 9; PJM/SPP Comments at 12-13; Potomac 

Economics Comments at 3-4; SPP Market Monitor Comments at 9.

225 Dominion Comments at 5; Exelon Comments at 16; ISO-NE Market Monitor

Comments at 7; ISO-NE Comments at 6; MISO Comments at 9; PJM Market Monitor

Comments at 6; PJM/SPP Comments at 10; Potomac Economics Comments at 3-5; SPP 

Market Monitor Comments at 9.
Docket No. RM16-5-000 - 69 -

market.226 For example, PJM/SPP state that some natural gas resources procure all or 

part of their natural gas requirements in the daily natural gas spot market, which is more 

volatile than month-ahead index prices because of changes in commodity prices and 

weather, as well as interstate natural gas pipeline capacity curtailments and maintenance 

activities.227

107. Comments from market monitors also suggest that some natural gas resources do 

not know their actual fuel costs at the time they submit offers.228 For example, the ISONE Market Monitor states that natural gas resources that have not purchased natural gas 

in advance submit offers based on their best estimate of what they expect to pay for 

natural gas in real-time.229 Potomac Economics and the ISO-NE Market Monitor state 

that resources submit initial incremental energy offers230 or updates to their cost-based 

incremental energy offers231 based on expected, rather than actual costs. Potomac 

Economics adds that such offers reflect a resource’s expectation of its costs, and these 

 226 ISO-NE Comments at 5; MISO Comments at 9; PJM/SPP Comments at 9.

227 PJM/SPP Comments at 9-10.

228 ISO-NE Market Monitor Comments at 7; Potomac Economics Comments at 4; 

SPP Market Monitor Comments at 9. 

229 ISO-NE Market Monitor Comments at 7.

230 Potomac Economics Comments at 4.

231 ISO-NE Market Monitor Comments at 7.
Docket No. RM16-5-000 - 70 -

costs may be subject to substantial uncertainty and thus cannot be verified in advance.232 

The ISO-NE Market Monitor, Potomac Economics, and the SPP Market Monitor 

conclude that strict verification of a resource’s actual costs prior to the market clearing 

process is not possible.233 

108. Generators also state that verification of actual costs may not be possible because 

some natural gas resources can only submit an estimate of their expected fuel costs.234 

For example, Exelon states that when a resource submits a day-ahead offer, which is due 

24-48 hours prior to actual dispatch, that resource must consider numerous costs and may 

have to make complicated and somewhat imprecise judgments to predict future events, 

which makes it difficult to quantify and substantiate risks on either an before-the-fact or 

after-the-fact basis.235 Additionally, EEI states that a resource that is not committed or 

not fully committed in the day-ahead market may not procure enough natural gas to meet 

its full output in the real-time market and may need to purchase fuel in the intra-day 

natural gas market where prices are significantly higher and more volatile than the dayahead natural gas market.236 

 232 Potomac Economics Comments at 4.

233 ISO-NE Market Monitor Comments at 4; Potomac Economics Comments 

at 3-4; SPP Market Monitor Comments at 9.

234 Dominion Comments at 5; Exelon Comments at 11-16.

235 Exelon Comments at 11-17.

236 EEI Comments at 5-6.
Docket No. RM16-5-000 - 71 -

ii. Cost Verification During Peak Periods

109. Several commenters state that the challenges associated with pre-verification 

become more acute during stressed system conditions when natural gas supplies are 

limited, which is precisely when resources may have incremental energy costs above 

$1,000/MWh.237 

110. PJM states that higher natural gas prices have led to higher cost-based incremental 

energy offers from resources, but verifying resource costs with natural gas price indices 

can be challenging because there is not a strong or straightforward correlation between 

changes in natural gas index prices and the magnitude of changes in cost-based offers, 

particularly when cost-based incremental energy offers in PJM are high.238 ISO-NE 

argues that indices may not fairly represent the fuel prices that resources must pay, 

particularly when natural gas supplies are tight.239 ISO-NE notes that there may be scant 

 237 See generally Dominion Comments at 4-5; PJM/SPP Comments 11; ISO-NE 

Comments at 4-5; SPP Market Monitor Comments at 7; PJM Market Monitor Comments 

at 6; EEI Comments at 6; Exelon Comments at 13-14; PJM Power Providers Comments 

at 3.

238 PJM/SPP Comments at 11 (citing Attachment A). Attachment A presents an 

analysis of cost-based incremental energy offers and natural gas prices during the winters 

of 2013/14, 2014/15, and 2015/16. The analysis in Attachment A shows that for costbased offers in the $500/MWh -$750/MWh range, the median gas price corresponding to 

the range of offers was $10.44/MMBtu in the 2013/14 winter, $15.62 MMBtu in the 

2014/15 winter, and $3.75/MMBtu in the 2015/16 winter. 

239 ISO-NE Comments at 4-5.
Docket No. RM16-5-000 - 72 -

independent or timely information on natural gas resources’ costs during such times.240 

Various commenters explain that during such times, natural gas resources must often 

purchase natural gas outside of the exchange trading platforms241 through bilateral deals 

that are not reported on such exchanges, and that a significant amount of such purchases 

tends to make natural gas indices less representative of the price natural gas resources pay 

for natural gas.242 

111. The ISO-NE, PJM, and SPP market monitors state that cost verification is most 

challenging when natural gas demand is high because of low liquidity and high bid-ask 

spreads for natural gas purchased on open exchanges such as the ICE.243 For example, 

the PJM Market Monitor and the ISO-NE Market Monitor state that the natural gas 

market is least transparent on days with very high electric demand and that the ICE index 

is likely to be unsuitable for verification purposes because there are either no completed 

trades reported, a low number of completed gas trades (i.e., low liquidity), or the bid-ask 

 240 Id.

241 Industrial Customers Comments at 16; ISO-NE Comments at 4-5; ISO-NE 

Market Monitor Comments at 8; PJM Market Monitor Comments at 6; SPP Market 

Monitor Comments at 7.

242 ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6.

243 ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6; 

SPP Market Monitor Comments at 7.
Docket No. RM16-5-000 - 73 -

spread is so wide as to be meaningless.244 The SPP Market Monitor states that the risk 

inherent in determining accurate fuel costs from natural gas indices is acceptable in most 

periods, but that the risk increases to unacceptable levels during extremely stressed fuel 

supply conditions.245 Comments from generators also suggest that natural gas indices 

become less reliable during periods when natural gas supplies are limited and natural gas 

prices spike.246 Dominion and Exelon assert that purchasing natural gas outside of an 

exchange through marketers or bilateral deals also increases the risks that a natural gas 

resource faces when it formulates its bid, and can increase the error associated with a 

resource’s estimate of its actual costs.247

c. Feasibility of Verification Requirement

112. The Commission sought comment on the feasibility of the proposed verification 

requirement.248 As discussed further below, ISO-NE, MISO, and NYISO state that 

current mitigation procedures could satisfy the proposed verification requirement if the 

Commission clarifies that the verification process can include expected, rather than 

 244 ISO-NE Market Monitor Comments at 7-8; PJM Market Monitor Comments 

at 6.

245 SPP Market Monitor Comments at 7.

246 EEI Comments at 6; Exelon Comments at 13-14; PJM Power Providers 

Comments at 3.

247 Dominion Comments at 5; Exelon Comments at 13-14.

248 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 59, 73.
Docket No. RM16-5-000 - 74 -

actual, costs.249 Several commenters express concerns that timely verification of a 

resource’s actual short-run marginal costs is not possible within the timeframe of the 

RTO/ISO day-ahead and real-time market clearing process.250 

113. For example, Potomac Economics states that time constraints will make the 

proposal infeasible if the proposed verification requires that resource cost data be 

collected and fully validated to actual cost prior to market clearing.251 The ISO-NE 

Market Monitor states that the lack of solid information about natural gas prices on highvolatility, low-liquidity days makes validation of a resource’s expected short-run 

marginal costs difficult, particularly if many resources seek to update their cost-based 

incremental energy offers.252 The PJM Market Monitor notes that in PJM, a large 

volume of data, including information from approximately 420 gas-fired resources and 

about 35 gas trading points, must be processed to review cost-based incremental energy 

offers.253 The SPP Market Monitor states that verification prior to market clearing may 

not be feasible in SPP given the tight timeline, particularly during sudden fuel shortages 

 249 See infra PP 126-127.

250 Exelon Comments at 11; Industrial Customers Comments at 13-16; ISO-NE 

Market Monitor Comments at 9; Joseph Margolies Comments at 13; Potomac Economics 

Comments at 3-4; SPP Market Monitor Comments at 2, 7, 9.

251 Potomac Economics Comments at 3-4.

252 ISO-NE Market Monitor Comments at 9.

253 PJM Market Monitor Comments at 7.
Docket No. RM16-5-000 - 75 -

and fuel price spikes, and adds that it would need additional technical capabilities for 

such verification.254 The SPP Market Monitor states that the proposal could also 

negatively affect RTO/ISO market monitors’ ability to conduct timely market power 

mitigation under the proposed timeline because market monitors would be required to 

perform cost verification and market mitigation before completion of the market clearing 

process.255 

114. Industrial Customers argue that market monitors cannot be expected to have the 

ability to assess the legitimacy of the cost component of resource offers in real-time.

256 

Industrial Customers add that even if a resource has a natural gas invoice with a high 

price and provides it to the market monitor, this alone does not provide adequate 

consumer protection because the market monitor must investigate, understand, and accept 

the dynamics that led to that invoice.257

115. Citing CAISO’s prior comments about practical implementation challenges 

associated with before-the-fact verification, Industrial Customers argue that the proposal 

in the NOPR may not be beneficial because pre-verification presents significant 

 254 SPP Market Monitor Comments at 2, 7, 9, 10-11.

255 Id. at 9.

256 Industrial Customers Comments at 14.

257 Industrial Customers Comments at 19.
Docket No. RM16-5-000 - 76 -

challenges given time constraints.258 KEPCo/NCEMC states that RTOs/ISOs may not be 

in a position to verify cost-based incremental energy offers prior to market clearing 

without substantial investment in both new technology and significant changes to the 

existing RTO/ISO tariffs and business practice manuals.259 KEPCo/NCEMC argues that 

the verification requirement involves substantial technological and regulatory costs for 

wholesale market participants, which KEPCo/NCEMC asserts are unwarranted given the 

limited nature of the problem with the current RTO/ISO offer caps.260 

116. EEI maintains that the NOPR proposal is heavily dependent on having a 

verification process that is not so cumbersome as to prevent a resource’s cost based 

incremental energy offer from being verified in time to be used in the LMP calculation. 

It argues that the use of make-whole payments would not serve the Commission’s goal of 

having clearing prices that reflect the true marginal cost of production, taking into 

account all physical constraints.261 NEI states that the manner in which the verification is 

performed is a key concern, and without a simple and efficient process, there is risk that 

the LMP will not reflect the true costs of operating the system because it will exclude 

offers above the cap. NEI maintains that an alternative approach would be warranted if 

 258 Id. at 14-16 (citing CAISO Post-Technical Workshop Comments, Docket 

No. AD14-14-000, at 4-6 (Mar. 6, 2015)).

259 KEPCo/NCEMC Comments at 5. 

260 Id.

261 EEI Comments at 5.
Docket No. RM16-5-000 - 77 -

market monitors cannot validate incremental energy offers in excess of $1,000/MWh 

quickly and efficiently.262 Competitive Suppliers contend that the proposed verification 

requirement would result in cost-based offers above $1,000/MWh being unable to set the 

LMP because cost verification prior to the market clearing process is not possible.

263

117. Competitive Suppliers argue that removing the offer cap entirely or increasing it 

significantly would alleviate any challenges inherent in a before-the-fact cost verification 

process.264 Similarly, NEI states that instead of the verification requirement, the 

Commission should lift caps to a level that does not artificially constrain LMPs.265 

118. Midcontinent Joint Consumer Advocates and TAPS argue that it is possible to 

perform the proposed cost verification prior to the market clearing process.

266 

Midcontinent Joint Consumer Advocates state that the MISO Market Monitor has 

publicly confirmed its ability to verify offers prior to market clearing and that it currently 

tracks fuel prices that could be used to make adjustments to gas and fuel costs included in 

a MISO resource’s cost-based incremental energy offer.267 According to TAPS, MISO’s 

 262 NEI Comments at 4. 

263 Competitive Suppliers Comments at 17-18.

264 Id.

265 NEI Comments at 4. 

266 Midcontinent Joint Consumer Advocates Comments at 5; TAPS Comments at 

13-15.

267 Midcontinent Joint Consumer Advocates Comments at 5.
Docket No. RM16-5-000 - 78 -

current process for developing and updating cost-based incremental offers for resources 

is workable because the vast majority of resources will never experience cost levels close 

to $1,000/MWh, and the resources that are likely to reach such levels should have already 

provided the Market Monitoring Unit with up-to-date information about their heat rates, 

which will allow the Market Monitoring Unit to quickly calculate cost-based incremental 

energy offers for such resources.268 TAPS states that MISO’s current methodology for 

verification of cost-based incremental offers could be modified and adapted in all 

RTOs/ISOs.269

d. Uplift Payments 

119. Several stakeholders commented on the after-the-fact review of costs in the event 

that the RTO/ISO or Market Monitoring Unit is unable to verify a resource’s incremental 

energy offer above $1,000/MWh prior to the market clearing process.270 MISO states 

that market participants should be required to consult with the Market Monitoring Unit 

before the submission of an offer in order for that market participant to be eligible for 

make-whole payments after-the-fact, and asserts that market participants should not be 

eligible for cost recovery above their offers just because in hindsight, their offers were 

 268 TAPS Comments at 13-14.

269 Id. at 14-15.

270 Competitive Suppliers Comments at 19; MISO Comments at 10; PG&E 

Comments at 3; PJM Power Providers Comments at 4.
Docket No. RM16-5-000 - 79 -

below their actual costs.271 PG&E states that if a cost-based incremental energy offer is 

verified after the market has run, energy cleared from such an offer should be 

compensated on an “as bid” basis.272 PG&E maintains that if a cost-based incremental 

energy offer cannot be verified even after the market has run, then that resource’s cleared 

energy should instead be compensated at the LMP.273 PJM Power Providers and 

Competitive Suppliers assert that even after-the-fact verification of a resource’s costs will 

be challenging, and, according to Competitive Suppliers, it will be particularly 

challenging for natural gas resources that have complex fuel supply arrangements.274 

120. Competitive Suppliers state that in some instances, a resource may not be able to 

use the RTO’s/ISO’s verification process to set the market clearing price (for offers 

above $1,000/MWh) and in such rare cases, it may be necessary to compensate that 

resource through an uplift payment based on after-the-fact cost verification.275 

Competitive Suppliers assert that if a resource incurs justifiable and demonstrable short-

 271 MISO Comments at 10.

272 PG&E Comments at 3.

273 Id.

274 Competitive Suppliers Comments at 19; PJM Power Providers Comments at 4.

275 Competitive Suppliers Comments at 20-21.
Docket No. RM16-5-000 - 80 -

run marginal costs, those costs should be recovered so that the resource does not operate 

at a loss and so that the resource is not discouraged from offering supply to the market.276

121. NEI states that, given that the Commission’s price formation reforms are aimed at 

reducing the use of out-of-market payments, NEI is disappointed by the NOPR proposal 

to include uplift payments as a fall back if before-the-fact cost verification proves 

infeasible in practice.277 However, Direct Energy states that if a resource’s verified costbased incremental energy offer exceeds the cap, that resource should be entitled to full 

cost recovery of RTO/ISO approved costs through uplift.278

e. Specific Proposals for the Verification Requirement

122. Given the concerns about verification of actual costs, several commenters, 

including RTOs/ISOs,279 Market Monitoring Units,280 and other stakeholders,281 request 

that the Commission clarify that if it is not possible to verify a resource’s actual costs 

prior to setting LMP, it will accept a process that verifies that a resource’s incremental 

energy offer reasonably reflects that resource’s expected costs.

 276 Id. at 21.

277 NEI Comments at 4.

278 Direct Energy Comments at 3.

279 ISO-NE Comments at 4-7; NYISO Comments at 2; PJM/SPP Comments at 12-

13.

280 Potomac Economics Comments at 3-4; ISO-NE Market Monitor Comments at 

4.

281 EEI Comments at 6-7; Exelon Comments at 17.
Docket No. RM16-5-000 - 81 -

123. Several commenters maintain that a prior-to-the-market-clearing verification 

process that requires cost-based offers be equal to actual costs will likely result in fewer 

incremental energy offers above $1,000/MWh that are eligible to set LMP.282 For 

example, EEI states that its primary concern with the NOPR is the verification process 

and whether it is workable.283 The ISO-NE Market Monitor and PJM/SPP state that 

there is a trade-off between the level of precision of the cost-based offer verification, 

the number of offers that will be eligible to set LMPs, and the level of uplift.284 

124. Several commenters ask the Commission to indicate the types of verification 

processes it would accept.285 ISO-NE, MISO, and NYISO state that their current process 

for developing and updating cost-based incremental energy offers, known as reference 

levels, could comply with the proposal as clarified to include estimated costs.

286

125. CAISO states that the simplest method of verifying cost-based incremental energy 

offers would involve reviewing a broker quote or procurement invoice provided as 

evidence of a resource’s costs, but CAISO questions whether such information would be 

 282 CEA Comments at 5; EEI Comments at 5. 

283 EEI Comments at 5.

284 ISO-NE Market Monitor Comments at 5; PJM/SPP Comments at 13.

285 CEA Comments at 6; IRC Comments at 2. 

286 ISO-NE Comments at 6; MISO Comments at 8; NYISO Comments at 2.
Docket No. RM16-5-000 - 82 -

sufficient.287 CAISO predicts that incremental energy offers above $1,000/MWh are not 

likely to be eligible to set the clearing price in CAISO and that instead a resource with 

costs above $1,000/MWh would receive an uplift payment, assuming that the resource’s 

costs were verified after-the-fact.288 

126. PJM/SPP state that the principles outlined in the NOPR are sound, provided that 

the Final Rule allows RTOs/ISOs flexibility to design verification procedures that are 

consistent with current RTO/ISO rules.289 PJM/SPP outline conceptual initial proposals 

for verification, but stress the need to provide RTOs/ISOs with latitude to develop the 

final verification process with stakeholders.

290 PJM presents a possible verification 

process that involves an automatic screen to filter out unreasonably high offers and to 

create a range of reasonableness based on an index of natural gas prices, the bid/ask 

spread, and resource heat rates.291 PJM states that the verification requirement could use 

a screening process that determines whether certain resources’ incremental energy offers 

in a given area are within ten percent or $100/MWh of a benchmark offer based on a 

 287 CAISO Comments at 11.

288 Id.

289 PJM/SPP Comments at 2-3.

290 Id. at 14-21.

291 Id. at 15-16.
Docket No. RM16-5-000 - 83 -

natural gas price index.292 SPP states that it could develop additional rules that facilitate 

resources’ submission of the fuel cost component of their cost-based incremental energy 

offers that is consistent with the resource’s actual costs where possible, or that is a 

reasonably accurate representation of those costs. SPP states that given the need to 

approximate fuel costs that are difficult to verify, in most cases such a verification 

process could be subject to a reasonable margin of error.293 

127. ISO-NE states that if its current cost verification process is acceptable to the 

Commission, then the offer cap proposal may be workable and would help improve price 

formation if high fuel prices cause generation costs to exceed $1,000/MWh.294 MISO 

contends that its current process to establish and adjust cost-based offers can be used to 

verify incremental energy offers above $1,000/MWh.295 NYISO also states that its 

current review process of a resource’s incremental energy costs could be used to satisfy 

the proposed verification requirement.296 

128. The ISO-NE Market Monitor states that the Commission should revise the 

proposed verification requirement to permit use of ISO-NE’s current Commission-

 292 Id. at 16-17.

293 Id. at 19.

294 ISO-NE Comments at 6.

295 MISO Comments at 8.

296 NYISO Comments at 3. 
Docket No. RM16-5-000 - 84 -

approved process where a resource can update its cost-based incremental energy offer, 

which occurs through a “Fuel Price Adjustment.”297 The ISO-NE Market Monitor states 

that ISO-NE’s Fuel Price Adjustment mechanism balances the desire to reflect resource 

costs in cost-based incremental energy offers, the limited information the ISO-NE Market 

Monitor has available to verify costs, and the need to deter abuse.298 The ISO-NE Market 

Monitor explains that ISO-NE’s market power mitigation software automatically 

calculates cost-based incremental energy offers for resources, which may be based on a 

day-ahead fuel price index.299

129. Potomac Economics states that MISO’s current process for developing and 

updating reference levels would comply with a Final Rule which clarified that before-thefact verification of a resource’s expected costs is acceptable.300 Potomac Economics 

explains that in MISO, cost-based offers are calculated on the day before every operating 

day based on next-day fuel price indices.301 In real-time, the MISO Market Monitor 

(i.e., Potomac Economics), reviews natural gas prices on ICE at various delivery points,

and if natural gas prices rise significantly compared to the next-day fuel index, the MISO 

 297 ISO-NE Market Monitor Comments at 5-10.

298 Id. at 5.

299 Id. at 6.

300 Potomac Economics Comments at 5. 

301 Id. at 4.
Docket No. RM16-5-000 - 85 -

Market Monitor adjusts the cost-based incremental energy offers of any affected 

resources.302 Potomac Economics adds that a MISO resource can also consult with the 

Market Monitor and request to raise its cost-based offer beyond this adjustment if the 

resource provides supporting information, which may or may not be approved.303 

130. Potomac Economics explains that a NYISO resource may also request to update 

its cost-based incremental energy offer through a software process that automatically 

permits such an increase, provided the increase does not exceed a predetermined 

threshold.304 Potomac Economics maintains that NYISO may need to adjust the 

validation threshold to account for periods of unusually high fuel price volatility, but that 

with such an adjustment, NYISO’s current verification process could comply with the 

proposal.305

131. The PJM Market Monitor explains that resource owners in PJM are responsible for 

submitting their own cost-based offers and fuel cost policies, and that fuel costs are an 

essential part of the verification process.306 The PJM Market Monitor states that it does 

 302 Id. In MISO, cost-based offers are referred to as reference levels.

303 Id. at 5. 

304 Id. NYISO states that a resource that updates the fuel type or fuel cost 

information associated with its cost-based incremental energy offer must make 

supporting documentation available for NYISO’s review after-the-fact. See NYISO 

Comments at 4.

305 Potomac Economics Comments at 6. 

306 PJM Market Monitor Comments at 4-5.
Docket No. RM16-5-000 - 86 -

not have the authority to tell a resource owner what its fuel cost is or what its offer should 

be, but it does have the authority to verify cost-based offers, to discuss cost issues with 

resource owners, and to refer resource owners to the Commission for rule violations and 

for the attempted or actual exercise of market power.307 It states that it is essential that 

the Commission impose significant penalties for rule violations determined during the 

after-the-fact review. According to the PJM Market Monitor, a resource should be 

required to have in place a fuel cost policy that has been approved by both the PJM 

Market Monitor and PJM before the resource is able to submit an offer in excess of 

$1,000/MWh.308 The PJM Market Monitor states that if a resource’s cost-based 

incremental energy offer above $1,000/MWh is used in the market clearing process, the 

PJM Market Monitor would perform a timely after-the-fact review to determine whether 

a resource’s offer was based upon the best information available at the time the resource 

submitted the cost-based incremental energy offer.309 The PJM Market Monitor states 

that, in cases where an offer above $1,000/MWh is not permitted, the PJM Market 

Monitor would perform a timely after-the-fact review to determine the actual incurred 

costs of a resource, and uplift would be paid if the costs exceeded the market clearing 

 307 Id. at 5.

308 Id. at 6.

309 Id. at 7-8.
Docket No. RM16-5-000 - 87 -

price.

310 Any uplift payments for such offers would be based on the actual gas cost 

incurred. The PJM Market Monitor also recommends that the $1,000/MWh offer cap 

apply to a resource’s “operating rate,” which is calculated by adding a resource’s 

incremental offer to its no-load offer.311 

132. The PJM Market Monitor also maintains that it is essential that any verification 

process include a rigorous and timely after-the-fact review and a requirement that a 

resource follows the cost-based offer submission rules and abides by its approved fuel 

cost policy. The PJM Market Monitor states that the verification process requires strong 

compliance incentives, and the Commission should impose significant penalties if a 

resource violates the cost-based incremental energy offer guidelines.312

133. Commenters representing generator and load interests also proposed verification 

processes. Competitive Suppliers and NEI state that lifting the offer cap to a level that 

does not artificially constrain LMPs is preferable to developing a verification process, as 

removing the cap allows the market price to convey accurate information of the state of 

the system even during high stress.313

 310 Id.

311 Id. at 2.

312 Id. at 7.

313 Competitive Suppliers Comments at 18; NEI Comments at 4. 
Docket No. RM16-5-000 - 88 -

134. Competitive Suppliers prefer no verification requirement but contends that if the 

Commission requires that all cost-based incremental energy offers above $1,000/MWh 

be verified, the RTO/ISO and the generator should be able to identify a set of accepted 

criteria and data inputs such that resources can submit offers that can be accepted and 

thus eligible to set LMP.314 Competitive Suppliers state that PJM’s Cost Development 

Guidelines provide a means of verifying resource costs and may provide an alternative 

approach to the proposed verification requirement.315 

135. Exelon proposes that the Commission require RTOs/ISOs to adopt tariff 

provisions that will permit timely review and approval of resources’ cost-based offers 

based on a resource-specific “safe harbor” formula that is agreed upon in advance.316 

Exelon proposes that, at a minimum, the safe harbor formula should include a ten percent 

uncertainty component and a fuel cost component based on a daily natural gas index, 

natural gas adders, balancing costs, transportation costs, and a risk adder.317 

136. Dominion supports a verification process that uses fuel estimates based on recent 

prices, historical prices during similar conditions, or a combination of both.318 Dominion 

 314 Competitive Suppliers Comments at 19.

315 Id.

316 Exelon Comments at 11.

317 Id. at 17-20 (citing Testimony of Leslie O. Dedrickson at 29-31).

318 Dominion Comments at 5.
Docket No. RM16-5-000 - 89 -

would support allowing market participants to submit cost-based offers within a 

reasonable range of a reference price that would be based on a historical fuel price index 

or an average of ask prices within a given fuel market, and that offers which fall in the 

range of that reference price and clear the market should be eligible to set LMP.319 

137. The New Jersey and Pennsylvania Commissions and OPSI maintain that in order 

to implement the proposal in PJM, resources should be required to have a fuel cost policy 

approved by the Market Monitoring Unit prior to submission of cost-based incremental 

energy offers above $1,000/MWh.320 The Pennsylvania Commission states that preapproved resource fuel cost policies in PJM would speed up the verification process, 

foster market stability, and provide certainty to resources.321 The New Jersey 

Commission and OPSI assert that resource fuel cost policies should be derived from a 

verifiable, algorithmic, and systematic approach consistent with the PJM Market 

Monitor’s fuel cost policy guidelines.322 The Delaware and Pennsylvania Commissions 

 319 Id.

320 New Jersey Commission Comments at 12-13; Pennsylvania Commission 

Comments at 9; OPSI Comments at 7-9. This issue was also raised in comments in 

PJM’s offer flexibility proposal in Docket No. ER16-372-000.

321 Pennsylvania Commission Comments at 9.

322 New Jersey Commission Comments at 13; OPSI Comments at 8 (citing 

Monitoring Analytics, Fuel Cost Policy Guidelines: Gas Replacement Cost (Sept. 24, 

2015), available at 

http://www.monitoringanalytics.com/reports/Market_Messages/Messages/IMM_Fuel_Co

st_Policy_Guidelines_20150924.pdf).
Docket No. RM16-5-000 - 90 -

and OPSI argue that PJM should clarify the role of PJM and the PJM Market Monitor in 

the review and approval of fuel cost policies and assert that the PJM Market Monitor 

should have the authority to verify offers above $1,000/MWh.323 

138. SCE argues that each RTO/ISO should utilize its own stakeholder processes to 

develop specific verification rules, which may reflect regional factors such as differences 

in market power mitigation processes and region-specific costs such as emissions and 

greenhouse gas costs.324

3. Determination

139. We adopt the NOPR proposal and clarify that each RTO/ISO or Market 

Monitoring Unit is required to verify that any incremental energy offer above 

$1,000/MWh reasonably reflects the associated resource’s actual or expected costs prior 

to using that offer to calculate LMPs. We find that this verification requirement is 

necessary for incremental energy offers above $1,000/MWh because market power 

concerns are heightened when a resource’s short-run marginal costs exceed $1,000/MWh. 

140. Based on the record, it is not practical to require that RTOs/ISOs or Market 

Monitoring Units verify a resource’s actual costs in all circumstances because a resource 

may not know its actual short-run marginal costs at the time it submits an incremental 

energy offer to the RTO/ISO for various reasons, including the timing of natural gas 

 323 Delaware Commission Comments at 12; OPSI Comments at 7-9.

324 SCE Comments at 1-2. 
Docket No. RM16-5-000 - 91 -

procurement. Accordingly, we clarify that an RTO/ISO or a Market Monitoring Unit 

must verify that cost-based incremental energy offers above $1,000/MWh reasonably 

reflect a resource’s actual or expected costs. Under this requirement, the verification 

process for cost-based incremental offers above $1,000/MWh must ensure that a 

resource’s cost-based incremental energy offer reasonably reflects that resource’s actual 

or expected costs. 

141. The RTO/ISO or Market Monitoring Unit, as prescribed in the RTO/ISO tariff and 

consistent with Order No. 719,325 must verify the costs within a cost-based incremental 

energy offer above $1,000/MWh before that offer is used to calculate LMP, subject to the 

condition that such offers are capped at $2,000/MWh for purposes of calculating LMP.

326 

To create such a verification process, we expect that the RTO/ISO would build on its 

existing mitigation processes for calculating or updating cost-based incremental energy 

offers.327 However, we appreciate statements from RTOs/ISOs, market monitors, and 

 325 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, FERC Stats. & Regs. ¶ 31,281, at PP 370-375 (2008), order on reh’g, Order 

No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719-B, 

129 FERC ¶ 61,252 (2009). See also 18 CFR 35.28(g)(3)(iii)(B) (2016). 

326 Pursuant to 18 CFR 35.28(g)(3)(iii)(B), either the internal or external market 

monitor can “provide the inputs required to conduct prospective mitigation...including, 

but not limited to reference levels, identification of system constraints, and cost 

calculations.” 18 CFR 35.28(g)(3)(iii)(B) (2016). However, prospective mitigation may 

only be carried out by an internal market monitor if the RTO/ISO has a hybrid Market 

Monitoring Unit structure. 18 CFR 35.28(g)(3)(iii)(D) (2016).

327 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 63.
Docket No. RM16-5-000 - 92 -

others about potential verification processes for incremental energy offers above 

$1,000/MWh. We recognize that the verification process for incremental energy offers 

may be a fact-specific inquiry, and we have previously provided Market Monitoring 

Units with flexibility to make case-specific determinations.328 Given the potential 

complexities involved in verifying incremental energy offers as well as the Commission’s 

recognition of the need for proper mitigation methods in energy markets, we will require 

that RTOs/ISOs explain in their compliance filings what factors will be considered by the 

RTO/ISO or its Market Monitoring Unit in the verification process for cost-based 

incremental energy offers above $1,000/MWh and whether such factors are currently 

considered in existing market power mitigation provisions or whether new practices or 

tariff provisions are necessary given the verification requirement adopted in this Final 

Rule. Therefore, we disagree that the verification requirement is needlessly cumbersome 

because RTOs/ISOs may build on existing processes for market power mitigation. 

142. Most RTOs/ISOs prohibit incremental energy offers above $1,000/MWh, a 

prohibition that some market monitors characterize as a backstop market power 

mitigation measure.329 The offer cap adopted in this Final Rule retains the backstop 

function that the current $1,000/MWh offer cap plays in existing RTO/ISO market power 

mitigation because it limits incremental energy offers that are not cost-based to 

 328 See New England Power Generators Association, Inc. v. ISO New England 

Inc., 144 FERC ¶ 61,157, at P 62 (2015).

329 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 23.
Docket No. RM16-5-000 - 93 -

$1,000/MWh. Under this Final Rule, incremental energy offers below $1,000/MWh will 

remain subject to existing market power mitigation measures. However, this Final Rule 

will require that all incremental energy offers equal to and above $1,000/MWh be costbased, which essentially requires mitigation of all incremental energy offers above 

$1,000/MWh. 

143. In this way, the verification requirement requires RTOs/ISOs to make only an 

incremental change to their existing market power mitigation procedures because the 

market power mitigation provisions that apply to incremental energy offers below 

$1,000/MWh will be unchanged. While in this Final Rule we increase the offer cap 

for cost-based incremental energy offers, we also subject offers above $1,000/MWh 

to additional market power mitigation in the form of the verification requirement. The 

verification requirement is designed to ensure that a cost-based incremental energy offer 

above $1,000/MWh is not an attempt by the associated resource to exercise market 

power. The verification requirement is part-and-parcel with the increase of the offer cap 

for cost-based incremental energy offers. We find that it would be inappropriate to raise 

the offer cap without imposing a verification requirement. The verification requirement 

thus serves as an additional backstop market power mitigation measure.

330 

 330 Moreover, existing Commission regulations establish that misrepresenting costs 

when submitting cost-based incremental energy offers as part of a supply offer may be in 

violation of 18 CFR 35.41(b) (2016) and 18 CFR 1c.2(a)(2) (2016).
Docket No. RM16-5-000 - 94 -

144. Contrary to Potomac Economics’ assertion that competition is not diminished 

when short-run marginal costs rise above $1,000/MWh, we find that market power 

concerns are heightened during such periods because short-run marginal costs in this 

range may indicate that very few resources are available to provide additional supply. 

Supply may be limited during such periods because of fuel supply limitations or the 

physical limitations of resources (e.g., ramping constraints). Accordingly, resources with 

available supply during such periods likely face little competition, particularly in realtime, and may therefore be able to exercise market power. We find that the verification 

requirement reasonably addresses market power concerns associated with incremental 

energy offers above $1,000/MWh because such offers will be required to be cost-based, 

which should deter attempts by resources to exercise market power. 

145. As discussed above, this Final Rule will require RTOs/ISOs to limit incremental 

energy offers to $2,000/MWh when calculating LMPs, which may be below the costbased incremental energy offer of a resource. Thus, we revise the verification 

requirement proposed in the NOPR as indicated below and add new language (underlined 

below) to account for any uplift associated with the $2,000/MWh hard cap and adopt the 

following verification requirement:

The costs underlying a resource’s cost-based incremental energy offer 

above $1,000/MWh must be verified before that offer can be used for 

purposes of calculating Locational Marginal Prices. If a resource submits 

an incremental energy offer above $1,000/MWh and the costs underlying 

that offer cannot be verified before the market clearing process begins, that 

offer may not be used to calculate Locational Marginal Prices. In such 

circumstances a and the resource would be eligible for a make-whole 

payment if that resource is dispatched and the resource’s costs are verified 

after-the-fact. A resource would also be eligible for a make-whole payment 
Docket No. RM16-5-000 - 95 -

if it is dispatched and its verified cost-based incremental energy offer 

exceeds $2,000/MWh.

146. We will retain the proposal in the NOPR which ensures that, if a resource’s 

incremental energy offer above $1,000/MWh is not verified but that resource is

nonetheless dispatched, that resource would be eligible to receive an uplift payment to 

recover its verified costs. The basis of the uplift payment would be the difference 

between a given resource’s energy market revenues and that resource’s actual short-run 

marginal costs of the MWs dispatched, as verified after-the-fact by the RTO/ISO or 

Market Monitoring Unit.

331 We find that such uplift payments are necessary given the 

challenges associated with the verification processes, to ensure that resources have an 

incentive to offer into RTO/ISO energy markets, and to ensure that resources are 

compensated for the service they provide. 

147. This Final Rule will permit regional variation in the process for treating 

incremental energy offers above $1,000/MWh that the RTO/ISO or Market Monitoring 

Unit cannot verify prior to the start of the market clearing process. For example, the 

RTO/ISO could have procedures to change the incremental energy offer to $1,000/MWh 

 331 The Commission notes that the clarification regarding use of a resource’s actual 

or expected short-run marginal costs during the verification process that occurs prior to 

the market clearing process is not applicable to such uplift payments. Any such uplift 

payment, which is paid after-the-fact, must be based on a resource’s actual short-run 

marginal costs. 
Docket No. RM16-5-000 - 96 -

or to mitigate that offer to a level below $1,000/MWh pursuant to other applicable market 

power mitigation provisions. 

C. Resource Neutrality

1. NOPR Proposal

148. In the NOPR, the Commission proposed the following resource neutrality 

requirement: 

All resources, regardless of type, are eligible to submit cost-based 

incremental energy offers in excess of $1,000/MWh.332

The Commission reasoned that this requirement would ensure that the eligibility to 

submit cost-based incremental energy offers in excess of $1,000/MWh would not be 

applied in an unduly discriminatory or unduly preferential manner.333 The Commission

also stated that the proposed resource neutrality requirement is consistent with prior 

orders related to the offer cap in PJM and MISO.334 

2. Comments

149. Several commenters support the proposed resource neutrality requirement.335 For 

example, MISO supports the resource neutrality requirement and notes that the MISO 

 332 NOPR, FERC Stats. & Regs, ¶ 32,714 at P 69.

333 Id.

334 Id. (citing MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 16; PJM 

2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 39).

335 EEI Comments at 1, 3; Ohio Commission Comments at 12; MISO Comments 

at 12.
Docket No. RM16-5-000 - 97 -

tariff currently allows any resource, regardless of type, to establish a cost-based reference 

level.336 MISO adds that some resources could be constrained by the $1,000/MWh cap 

because they may be unable to provide evidence of high fuel costs.337 

150. Commenters disagree about whether demand response resources should be able to 

submit incremental energy offers above $1,000/MWh. Some commenters argue that 

demand response resources should be treated the same as other physical generation 

resources that provide offers.338 Additionally, MISO questions why a demand response 

resource should be prevented from submitting an offer at the same level (in $/MWh) as 

physical resources.339

151. However, other commenters argue that demand response should not be able to 

submit incremental energy offers above $1,000/MWh. PJM/SPP argue that the proposed 

offer cap revisions should not apply to demand response resources because demand 

response resource offers are intended to capture foregone commercial revenues, not the 

short-run marginal cost of reducing output.340 ISO-NE asserts that a demand response 

 336 MISO Comments at 12 (citing MISO Tariff, Module D, §§ 64.1.4.a, 64.3.a, and 

64.1.4.h).

337 Id.

338 API Comments at 12-13; Competitive Suppliers Comments at 23-24; Exelon 

Comments at 23 (citing PJM Manual 11 § 2.3.3); Industrial Customers Comments at 28; 

PJM Market Monitor Comments at 12-13.

339 MISO Comments at 7.

340 PJM/SPP Comments at 5.
Docket No. RM16-5-000 - 98 -

resource’s costs would be based on its marginal opportunity cost of foregone 

consumption, which could routinely exceed $1,000/MWh or $2,000/MWh, and that 

verifying such costs could not be accomplished on short notice. ISO-NE surmises that 

allowing demand resources to submit incremental energy offers above $1,000/MWh 

could create perverse incentives and may give physical resources the incentive to move 

behind the meter to exploit asymmetries in the application of the offer cap. Accordingly, 

ISO-NE requests that the Commission carefully consider its position on verification of 

the actual costs of demand response resources.341

152. The New Jersey Commission argues that in the absence of a comprehensive 

definition of short-run marginal costs for demand response resource offers, demand 

response resources should not be permitted to offer and set the market clearing price 

above the Commission’s determined offer cap.342 The Pennsylvania Commission asserts 

that demand response resources should not be eligible to set LMP and should be treated 

as price takers, asserting that such resources do not generally exhibit competitive 

behavior in energy markets because the energy revenues of such resources are de minimis

relative to their capacity market revenues.343

 341 ISO-NE Comments at 7-8.

342 New Jersey Commission Comments at 18.

343 Pennsylvania Commission Comments at 14 (citing PJM, Demand Response 

Operations Market’s Activity Report: February 2016 (Feb. 16, 2016), Fig. 23; Monitoring 

Analytics, LLC, State of the Markets Report for PJM, Vol. 1., Fig. 10 (Mar. 10, 2016)). 
Docket No. RM16-5-000 - 99 -

153. Several commenters express concerns about whether RTOs/ISOs or Market 

Monitoring Units can verify the costs of demand response resources. For example, ISONE asserts that a demand response resource’s costs would be based on that resource’s 

marginal opportunity cost of foregone consumption and other information that is difficult 

to validate, particularly if the demand response resource’s costs increase significantly 

from the prior day.344 PJM/SPP state that it is not clear what demand response resource 

costs could be validated to justify an offer above the $1,000/MWh offer cap.345 The 

Pennsylvania Commission states that with the limited exception of on-site backup 

generation costs, the incremental energy costs of demand response capacity resources are 

largely unknown.346 ISO-NE urges the Commission to carefully consider whether the 

verification of actual costs should be imposed on a resource-neutral basis, and explains its 

concerns regarding its ability to timely verify the offers of demand response resources.347 

AEMA argues that it is impractical, if not impossible, to verify the costs of a demand 

response resource in the same manner as a physical generation resource, particularly 

before-the-fact.348 AEMA also cites a prior Commission order on ISO-NE’s Order 

 344 ISO-NE Comments at 7-8.

345 PJM/SPP Comments at 5.

346 Pennsylvania Commission Comments at 14.

347 ISO-NE Comments at 7-8.

348 AEMA Comments at 7-8.
Docket No. RM16-5-000 - 100 -

No. 745 compliance where the Commission found that “unlike with supply resources, 

it would be very difficult to develop a competitive offer or reference price to which to 

mitigate each demand response resource.”349 AEMA asserts that there is no need to 

create an additional verification requirement for demand response resources, because the 

Commission has recognized that comparability does not require identical treatment.350 

154. AEMA requests that the Commission clarify that the offer cap proposed in the 

NOPR only impacts demand response resources that participate in energy markets and 

would not apply to demand resources that exclusively participate in capacity markets.351 

AEMA explains that demand response resources that participate exclusively in capacity 

markets do not make incremental energy offers. AEMA explains that capacity-only 

demand response resources are only dispatched on a reliability-based trigger that 

determines the price the demand resource is paid as opposed to an offer price-based 

trigger that does not represent the LMP at which the customer wishes to be dispatched, or 

the costs of the customer to curtail its load. AEMA asserts that forcing these resources to 

 349 Id. at 8 (citing ISO New England Inc., 138 FERC ¶ 61,042, at P 138 (2012)).

350 Id. at 8-9 (citing Preventing Undue Discrimination and Preference in 

Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, 

Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-

B, 123 FERC ¶ 61,299, at P 216 (2008), order on reh’g, Order No. 890-C, 126 FERC 

¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009); Indep.

Market Monitor for PJM v. PJM Interconnection, L.L.C., 155 FERC ¶ 61,059, at P 31 

(2016) (“comparability does not require identical application to demand response 

resources and generation resources of PJM’s offer cap and the must-offer requirement”)).

351 Id. at 3.
Docket No. RM16-5-000 - 101 -

make “incremental energy offers” in the energy market would drive them away from 

participation.352 

155. AEMA requests that the Commission continue to allow demand response 

resources to submit offers up to the offer cap in energy markets and not impose additional 

verification requirements on demand response resource energy market offers beyond 

what has already been accepted.353 AEMA asserts that the Final Rule should not impact 

existing or proposed methods for monitoring and evaluating demand resource offers in 

energy markets or create additional verification hurdles for demand resource offers 

beyond those that currently exist.354

3. Determination

156. We adopt the NOPR proposal and find that resources with costs above 

$1,000/MWh should be able to submit cost-based incremental energy offers to recover 

their costs, regardless of the type of resource. Prohibiting a particular set of resources 

from submitting cost-based incremental energy offers above $1,000/MWh could preclude 

them from recovering their costs.

 352 Id. at 3-5.

353 Id. at 5-6.

354 Id. at 2-3, 7-9.
Docket No. RM16-5-000 - 102 -

157. In the NOPR the term “resource” referred to all supply resources, including 

demand response resources, that offer incremental energy to RTO/ISO energy markets.355 

As such, a demand response resource that submits incremental energy offers to the 

energy market based on short-run marginal cost would be subject to the verification 

requirement if that incremental energy offer exceeds $1,000/MWh. For such a resource, 

the short-run marginal cost may equal its opportunity costs.

158. We recognize that the verification process for demand response resources will 

necessarily differ from the verification process for generation resources, as noted by ISONE and AEMA. The Commission has recognized that demand response resources should 

receive comparable, but not necessarily identical treatment to generation resources.356 

However, we decline AEMA’s request to exempt demand response resources that submit 

incremental energy offers in RTO/ISO energy markets from any additional verification 

requirements associated with this Final Rule, because such an exemption does not 

constitute comparable treatment. However, as noted above,357 this Final Rule does not 

 355 This is consistent with prior uses of the term. See, e.g., Settlement Intervals 

and Shortage Pricing in Markets Operated by Regional Transmission Organizations and 

Independent System Operators, Order No. 825, 81 Fed. Reg. 42,882 (June 30, 2015), 

FERC Stats. & Regs. ¶ 31,384, at P 98 (2016).

356 Demand Response Compensation in Organized Wholesale Energy Markets, 

Order No. 745, FERC Stats. & Regs. ¶ 31,322, at P 66, order on reh’g and clarification, 

Order No. 745-A, 137 FERC ¶ 61,215 (2011) (“as a general matter demand response 

providers and generators should be subject to comparable rules that reflect the 

characteristics of the resource.”).

357 See supra P 141.
Docket No. RM16-5-000 - 103 -

prescribe how RTOs/ISOs should verify cost-based incremental energy offers above 

$1,000/MWh, including offers from demand response resources.

159. Finally, we find that the New Jersey and Pennsylvania Commissions’ comments 

that demand response resources should not be able to set LMP are beyond the scope of 

this Final Rule, which only applies to incremental energy offers above $1,000/MWh, and 

not the general eligibility of demand response resources to set LMPs in RTO/ISO energy 

markets. We clarify, however, that reforms adopted in this Final Rule, which provide 

that resources are eligible to submit cost-based incremental energy offers in excess of 

$1,000/MWh and require that those offers be verified, do not apply to capacity-only

demand response resources that do not submit incremental energy offers in energy 

markets.

V. Other Issues

A. Virtual Transactions

160. Although the Commission preliminarily found in the NOPR that virtual supply 

offers and virtual demand bids (virtual transactions) could not provide a cost basis for 

offers above $1,000/MWh, it sought comment about whether prohibiting virtual 

transactions above $1,000/MWh could limit hedging opportunities, present opportunities 

for manipulation or gaming, create market inefficiencies, or have other undesirable 

consequences.358 

 358 NOPR, FERC Stats. & Regs ¶ 32,714 at PP 64, 73.
Docket No. RM16-5-000 - 104 -

1. Comments

161. CAISO states that virtual transactions do not face short-run marginal production 

costs and would thus be unable to justify costs above $1,000/MWh.359 However, CAISO 

notes that if physical resources can submit incremental energy offers above $1,000/MWh, 

then virtual participants should also be able to bid above $1,000/MWh to arbitrage those 

physical offers.360 

162. ISO-NE states that market participants should be able to submit virtual supply 

offers at levels as high as offers from physical resources to ensure that there is a liquid 

supply of offers that can compete with physical resources in the day-ahead market under 

all market conditions, which can reduce the potential exercise of market power during 

tight day-ahead conditions.361 ISO-NE asserts that if the Commission adopts a new hard 

cap, there is no cost-basis or market power rationale to limit virtual supply offers below 

the level of any hard cap.362 

163. PJM argues that virtual transactions should be permitted to exceed $1,000/MWh 

or be subject to a reasonableness screen because virtual transactions increase competition 

 359 CAISO Comments at 13. 

360 Id.

361 ISO-NE Comments at 8.

362 Id. at 8-9. 
Docket No. RM16-5-000 - 105 -

in the day-ahead markets and reduce market share, and thus reduce market power.363 

MISO states that prohibiting virtual transactions above $1,000/MWh could limit hedging 

opportunities which could increase the price differentials between the day-ahead and realtime energy markets.364 MISO adds that revising the offer cap for virtual transactions 

could conceivably expose other market participants to high prices but notes that MISO 

already has mitigation measures in place for virtual transactions and that years of market 

experience have shown that such manipulation concerns are improbable.365 

164. NYISO states that cost-based incremental energy offers, interchange transactions 

(e.g., imports and exports), and virtual transactions should be capped at the level of the 

hard cap, which will allow market participants to continue to compete to the maximum 

extent practicable.366 NYISO also argues that a hard cap is appropriate for virtual 

transactions because such transactions are based on price expectations as opposed to 

verifiable costs.367 SPP states that it takes no position on the application of the proposed 

reforms to virtual transactions.368

 363 PJM/SPP Comments at 27.

364 MISO Comments at 18; see also PJM/SPP Comments at 27-28.

365 MISO Comments at 18.

366 NYISO Comments at 7-8.

367 Id. at 7. 

368 PJM/SPP Comments at 28.
Docket No. RM16-5-000 - 106 -

165. Potomac Economics states that competitive virtual transactions should be 

permitted to exceed $1,000/MWh when real-time prices are expected to exceed 

$1,000/MWh.369 Potomac Economics states that although virtual transactions do not 

have production costs, they do have marginal costs, and notes that the marginal cost of 

selling virtual energy in the day-ahead market is the expected cost of buying the energy 

in the real-time market.370 Potomac Economics states that virtual transactions support 

the competitive performance of day-ahead markets and thus argues that it is important 

to structure the rules for virtual transactions in a manner that does not impede their 

participation in the market.371 

166. Potomac Economics proposes that virtual transactions be permitted to exceed

$1,000/MWh when real-time LMPs are expected to exceed $1,000/MWh for more than 

a specified period (e.g., 30 minutes).372 The PJM Market Monitor argues that market 

participants should not be permitted to submit virtual transactions above $1,000/MWh 

because increasing the offer cap on virtual transactions would create opportunities for the 

exercise of market power and manipulation of markets and permit resource owners to 

avoid the requirement that incremental energy offers above $1,000/MWh be cost-

 369 Potomac Economics Comments at 10.

370 Id.

371 Id.

372 Id. at 9-10.
Docket No. RM16-5-000 - 107 -

based.373 The PJM Market Monitor states there is no evidence that virtual supply offers 

have increased competition or would increase competition in extreme circumstances.374 

The PJM Market Monitor recommends that if the Commission wishes to permit some 

virtual transactions to exceed $1,000/MWh, the Commission should: (1) limit virtual

transactions above $1,000/MWh to liquid trading hubs; (2) require market participants to 

explain why virtual offers or bids above $1,000/MWh are appropriate; and (3) subject 

such virtual transactions to a “reasonableness screen” and an after-the-fact review for 

whether they resulted in manipulation or market power.375 The PJM Market Monitor 

states that the asserted benefits of virtuals with respect to hedging, competition, and price 

convergence have not been empirically established, and, thus, it is unnecessary to create 

market power risks when revising the offer cap.376

167. Separately, the PJM Market Monitor recommends that up-to-congestion 

transactions in PJM be excluded from any offer cap reforms stating that because up-tocongestion transactions are spread bids between nodes there is no reason to relax the 

current rules that govern such transactions.377

 373 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 6.

374 PJM Market Monitor Answer at 5.

375 PJM Market Monitor Comments at 11-12.

376 PJM Market Monitor Answer at 5.

377 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 6. 
Docket No. RM16-5-000 - 108 -

168. Several commenters argue that the Commission should allow virtual transactions 

to exceed $1,000/MWh.378 Some commenters focus on the use of virtual transactions to 

hedge physical transactions and argue that virtual transactions should thus be subject to 

the same offer caps as physical resources.379 Dominion states that in extreme winter 

conditions, a physical resource that faces a start-up risk and is likely to receive a dayahead award may submit a virtual demand bid to hedge against the potential outage in 

real-time.380 Exelon also argues that hedging the risk of physical transactions through 

virtual transactions is especially important when the system is stressed, and that doing so 

may improve market performance by converging day-ahead and real-time prices.381 

Competitive Suppliers assert that the same argument articulated in the NOPR for having 

a uniform offer cap across regions demands similar treatment of virtual transactions, 

imports, and emergency demand response across regions.

382

169. Dominion states that limiting the ability to submit virtual transactions above 

$1,000/MWh to physical resources with verified cost-based incremental energy offers 

 378 Competitive Suppliers Comments at 23-24; Dominion Comments at 7; Exelon 

Comments at 23-24; ISO-NE Comments at 8; PJM/SPP Comments at 27; SPP Market 

Monitor Comments at 12; NY Department of State Comments at 6.

379 SPP Market Monitor Comments at 12; Competitive Suppliers Comments 

at 23-24; NY Department of State Comments at 6; Dominion Comments at 7.

380 Dominion Comments at 7.

381 Exelon Comments at 23-24.

382 Competitive Suppliers Comments at 23.
Docket No. RM16-5-000 - 109 -

above $1,000/MWh in order to allow such resources to hedge would minimize concerns 

about market manipulation.383 The PJM Market Monitor responds that Dominion’s 

proposal creates a significant risk of manipulation because Dominion does not propose to 

limit the virtual bids to the cost-based offer of the generator.384 

170. Several other commenters argue that virtual transactions should be prohibited from 

submitting transactions above $1,000/MWh.385 For example, several commenters argue 

that virtual transactions should not be permitted to exceed $1,000/MWh because allowing 

transactions in this range could raise clearing prices without a commensurate increase in 

short-run marginal production costs.386 Six Cities argues that permitting virtual 

transactions to submit offers above the $1,000/MWh cap would be inconsistent with the 

Commission’s goals of allowing recovery of actual production costs in excess of the cap 

and establishing LMPs consistent with actual production costs under extreme market 

conditions.387 TAPS argues that the Commission does not need to allow virtual 

 383 Dominion Comments at 7.

384 PJM Market Monitor Answer at 6.

385 APPA, NRECA, and AMP Comments at 19; Industrial Customers Comments 

at 28-29; Ohio Commission Comments at 14; New Jersey Commission Comments 

at 17-18; Six Cities Comments at 3.

386 Industrial Customers Comments at 28-29; New Jersey Commission Comments 

at 17-18; Six Cities Comments at 3; Ohio Commission Comments at 14; TAPS 

Comments at 20-21.

387 Six Cities Comments at 4. 
Docket No. RM16-5-000 - 110 -

transactions to exceed $1,000/MWh to encourage price convergence between the dayahead and real-time markets.388 

171. Some commenters argue, as the PJM Market Monitor does, that allowing virtual 

transactions above the $1,000/MWh cap could lead to undesirable consequences, such as 

creating the opportunity for market manipulation and the exercise of market power.

389 

For example, SCE cautions that allowing virtuals above $1,000/MWh would undermine 

the purpose of having a backstop for existing market power mitigation rules.390 APPA, 

NRECA, and AMP state that although they oppose the idea, any proposal to allow virtual 

transactions above $1,000/MWh must be accompanied by an assurance that the RTO/ISO 

and/or Market Monitoring Unit will be able to address any gaming or anti-competitive 

conduct.391 PG&E asks that the Commission direct market monitors to study the 

potential impacts and gaming opportunities associated with permitting virtual 

transactions above $1,000/MWh before revising any caps on virtual transactions.392 

Midcontinent Joint Consumer Advocates state that while it generally supports applying 

 388 TAPS Comments at 21.

389 APPA, NRECA, and AMP Comments at 19; ODEC Comments at 1; 

KEPCo/NCEMC Comments at 5; New Jersey Commission Comments at 18; PJM Market 

Monitor Comments at 11-12; TAPS Comments at 21.

390 SCE Comments at 2.

391 APPA, NRECA, and AMP Comments at 19.

392 PG&E Comments at 3-4.
Docket No. RM16-5-000 - 111 -

the same offer cap to physical and virtual transactions, the issue should be monitored to 

ensure that inappropriate virtual transactions do not affect real-time energy prices.393 The 

Delaware Commission recommends that virtual transactions in PJM be limited to 

$400/MWh.394 

2. Determination

172. In light of the comments received and our adoption of a $2,000/MWh hard cap, we 

find that it is just and reasonable to permit market participants to submit virtual 

transactions up to $2,000/MWh. We do not require that virtual transactions be subject to 

the cost verification described above. Allowing virtual transactions above $1,000/MWh 

could improve price convergence between day-ahead and real-time markets.395 An offer 

cap that is lower for virtual transactions than for physical resources could increase 

divergence between day-ahead and real-time LMPs. This finding is consistent with prior 

Commission precedent, which finds it is reasonable to permit market participants to 

submit virtual transactions at levels commensurate with the levels that real-time LMPs 

can reach.396

 393 Midcontinent Joint Consumer Advocates Comments at 9.

394 Delaware Commission Comments at 14. The Delaware Commission 

recommends that in PJM, virtual transactions and incremental energy offers that are not 

cost-based be limited to $400/MWh.

395 PJM Interconnection, L.L.C., 139 FERC ¶ 61,057 (2012).

396 Id. PP 123-126. In that order, the Commission found that “if virtual traders and 

demand cannot submit higher bids in the day-ahead market [commensurate with the 

(continued ...)
Docket No. RM16-5-000 - 112 -

173. We find that market participants should be allowed to submit virtual transactions 

up to the hard cap, as they can today. As such, this Final Rule is therefore less likely to 

result in unintended consequences associated with capping virtual transactions at a level 

below the hard cap. For example, capping virtual transactions at $1,000/MWh when the 

incremental energy offers used to calculate LMPs are capped at $2,000/MWh could 

encourage some market participants to place virtual demand bids at $1,000/MWh, a 

transaction that may be profitable if real-time prices exceed $1,000/MWh but would not 

contribute to day-ahead and real-time price convergence. 

174. Under this Final Rule, LMPs may rise above $1,000/MWh. By permitting virtual 

transactions to exceed $1,000/MWh, we preserve a market participant’s ability to use 

virtual transactions to hedge its exposure to real-time LMPs above $1,000/MWh. 

Otherwise, if virtual transactions are limited to $1,000/MWh, as proposed in the NOPR, 

a market participant would be barred from placing virtual transactions commensurate 

with its market risks.

175. We also find that allowing virtual transactions above $1,000/MWh may add 

liquidity to day-ahead markets. Permitting virtual transactions in the $1,000/MWh -

$2,000/MWh range could result in additional demand bids and supply offers (i.e., virtual 

 

$/MWh value that real-time LMPs can reach if shortage pricing is in effect], that market 

may not converge with prices in the real-time market during times when PJM experiences 

shortage conditions in the real-time market.” Id. P 124.
Docket No. RM16-5-000 - 113 -

demand bids and virtual supply offers) and will thus allow virtual transactions to continue 

to perform the functions that they do today by adding liquidity to the day-ahead market. 

176. We recognize that virtual transactions, by their nature, cannot be subjected to the 

type of cost-verification discussed above. However, in response to comments arguing 

that virtual transactions above $1,000/MWh will raise LMPs above verifiable costs 

and/or result in market power abuse, we note that Market Monitoring Units currently 

monitor for anti-competitive behavior by market participants. While they are not 

required to do so, if RTOs/ISOs determine that additional measures are necessary to 

address any concerns that arise from permitting virtual transactions up to $2,000/MWh,

RTOs/ISOs may propose such additional measures in a separate filing under section 205 

of the Federal Power Act.

177. Dominion proposes to limit the ability to submit virtual transactions above 

$1,000/MWh to physical resources that have cost-based offers above $1,000/MWh. We 

find that Dominion’s proposal to limit virtual transactions to certain market participants 

would be unduly discriminatory. Such a limitation would treat market participants 

differently depending on whether they owned physical generation assets, and would be 

unduly discriminatory because it would limit the benefits of virtual transactions above 

$1,000/MWh to those participants with physical assets. Further, such a limitation could 

limit the other potential benefits of virtual transactions above $1,000/MWh, such as 

increased liquidity and increased convergence between day-ahead and real-time LMPs. 

Additionally, we find that the PJM Market Monitor’s and Potomac Economics’ proposals 

to limit virtual transactions above $1,000/MWh to certain time periods or certain 
Docket No. RM16-5-000 - 114 -

locations lack sufficient detail and record evidence to make a finding that either proposal 

is just and reasonable. Finally, we clarify that this Final Rule does not apply to up-tocongestion transactions in PJM, because such transactions are spread bids and not virtual 

supply offers or virtual demand bids. 

B. External Transactions 

178. In the NOPR, the Commission stated that external RTO/ISO resources 

(i.e., imports) would not be eligible to submit cost-based incremental energy offers 

above $1,000/MWh because RTO/ISO processes to develop cost-based incremental 

energy offers for mitigation purposes typically only apply to internal RTO/ISO 

resources.397 The Commission added, however, that it would consider RTO/ISO 

proposals to verify cost-based incremental energy offers from external transactions in 

their respective compliance filings.398 The Commission also sought comment on whether 

the offer cap proposal should apply to imports and whether a cost verification process for 

import transactions is feasible.399

1. Comments

179. CAISO maintains that the consistent treatment of internal resources and external 

resources (e.g., imports) is key to an efficient market and to avoid unintended 

 397 NOPR, FERC Stats. & Regs ¶ 32,714 at P 63.

398 Id.

399 Id. PP 63, 73.
Docket No. RM16-5-000 - 115 -

consequences.400 CAISO surmises that capping import offers to a level below the cap 

that internal resource incremental energy offers are subject to could reduce supply offers 

from imports during periods when natural gas prices in the West rise to a level that would 

justify LMPs above $1,000/MWh.401 

180. ISO-NE states that it cannot verify the costs associated with energy import 

transactions in real-time.402 ISO-NE explains that an importer’s actual cost to import 

power into ISO-NE from an adjacent market is the adjacent market’s real-time LMP, 

which is determined at the same time as ISO-NE’s LMP. ISO-NE adds that, given the 

lack of organized markets in some control areas adjacent to ISO-NE, it is unclear how 

actual costs would be verified for import transactions from those areas. Accordingly, 

ISO-NE requests additional guidance from the Commission about the application of the 

proposed rule to imports and exports.403

181. PJM asserts that non-emergency imports should be allowed to submit offers above 

$1,000/MWh to ensure that economic import transactions occur even when PJM LMPs 

exceed $1,000/MWh because such purchases and sales will benefit the market and 

 400 CAISO Comments at 13.

401 Id.

402 ISO-NE Comments at 9.

403 Id.
Docket No. RM16-5-000 - 116 -

provide electric supplies by allowing the lowest cost energy to serve customers.404 PJM 

adds that imports may also defer operational emergency procedures in extreme 

situations.405 

182. PJM explains that under PJM’s current rules, economic transactions are capped 

at the maximum energy price (absent congestion and losses) of $2,700/MWh while 

emergency import transactions are not. PJM states that the value of lost load may exceed 

this level and states that PJM is thus willing to pay more than $2,700/MWh to procure 

emergency energy to prevent load shedding.406 PJM notes that the verification of 

import’s cost would have to follow a different process than internal resources because the 

resource behind the import is frequently unknown.407 

183. SPP states that verifying the costs of imports could be problematic because it is 

difficult to obtain cost information from resources outside of SPP.408 SPP asks the 

Commission to allow regional flexibility for this issue, noting that it would investigate 

the issue further in response to any Final Rule issued in this proceeding.409

 404 PJM/SPP Comments at 25.

405 Id.

406 Id. at 26 (citing PJM, Intra-PJM Tariffs, OATT, Tariff Operating Agreement, 

Attachment K-Appendix, section 3.2.3.A).

407 Id.

408 Id. at 27.

409 Id.
Docket No. RM16-5-000 - 117 -

184. According to the PJM Market Monitor, 99.99 percent of PJM imports are price 

takers but imports that are not price takers should continue to be limited to $1,000/MWh 

offers.410 Potomac Economics contends that external transactions should be eligible to 

submit offers above $1,000/MWh when prices in the real-time market exceed 

$1,000/MWh for more than a specified period of time (e.g., 30 minutes). Potomac 

Economics also asserts that Coordinated Transaction Schedules should be exempt from 

the proposed reforms because they reflect a forecast of the price spread between 

RTO/ISO markets and thus would not set the LMP in either market.411 

185. The SPP Market Monitor states that the proposed offer cap requirements should 

apply to imports because imports have the same potential impact on LMPs as internal 

resources. However, the SPP Market Monitor acknowledges that it is more challenging 

to verify the offers of imports as compared to offers from internal SPP resources because 

the SPP market monitor may have limited access to the cost data of external resources.412

186. Several commenters assert that imports should be able to offer above $1,000/MWh 

provided the costs in their offers are verified beforehand,413 and some commenters say it 

 410 PJM Market Monitor Comments at 10.

411 Potomac Economics Comments at 9-10.

412 SPP Market Monitor Comments at 11.

413 Delaware Commission Comments at 13; Midcontinent Joint Consumer 

Advocates Comments at 8; Ohio Commission Comments at 13; Six Cities Comments 

at 3. 
Docket No. RM16-5-000 - 118 -

is possible to develop a workable solution for such verification.414 For example, the 

New Jersey Commission argues that imports that clear the PJM capacity auctions, which 

are pseudo-tied, will have short-run marginal production costs that are available for the 

market monitor to review, and should thus be permitted to offer into the PJM energy 

market above $1,000/MWh when their costs exceed $1,000/MWh.415 Midcontinent Joint 

Consumer Advocates explain that offers from imports are provided in the day-ahead 

market and then only scheduled in real-time, and imports cannot set real-time LMPs in 

MISO.416 However, Midcontinent Joint Consumer Advocates state that if imports are the 

source of higher prices in MISO markets, then it would be important to verify the costs of 

imports and in such cases, Midcontinent Joint Consumer Advocates would support 

verification for imports so that all suppliers are treated equally.417 The Delaware 

Commission supports the NOPR proposal to require verification of exchange transactions 

provided the process in an exporting region is not less objective or rigorous than the 

process in the importing region.418 

 414 Midcontinent Joint Consumer Advocates Comments at 8; Six Cities Comments 

at 3; CEA Comments at 7-8. 

415 New Jersey Commission Comments at 18.

416 Midcontinent Joint Consumer Advocates Comments at 8.

417 Id.

418 Delaware Commission Comments at 13.
Docket No. RM16-5-000 - 119 -

187. Powerex asks the Commission to consider adopting a verification process for 

external resources that is distinct from the process used for internal resources because 

the two resource types differ.419 Powerex states that verifying external resource costs 

is challenging in WECC because large hydroelectric storage facilities in the Pacific 

Northwest do not have easily calculable and verifiable short-run marginal costs, and 

because CAISO does not require that import offers be associated with a specific 

resource.420 As an alternative, Powerex suggests that the Commission could direct the 

RTOs/ISOs to implement an offer cap tied to prevailing market prices, such as capping 

offers from external resources at the higher of $1,000/MWh or 120 percent of the highest 

market price index report in the region for the previous seven days.421 TAPS and APPA, 

NRECA, and AMP assert that the Commission should give individual RTOs/ISOs the 

discretion to determine whether to allow imports to submit cost-based incremental energy 

offers over $1,000/MWh.422 

188. Several commenters argue that limiting external resources to $1,000/MWh offers 

may dissuade them from offering electricity to the RTO/ISO in periods when it is most 

 419 Powerex Comments at 7-8.

420 Id. at 8-9.

421 Id. at 9.

422 TAPS Comments at 19-20; APPA, NRECA, and AMP Comments at 18-19.
Docket No. RM16-5-000 - 120 -

needed.423 For example, CEA states that in light of the Commission’s price formation 

proceeding, there is no compelling reason to adopt an asymmetrical offer cap for internal 

resources and imports and questions the wisdom of excluding external transactions when 

price signals indicate scarcity and extreme conditions.424 Powerex states that the Western 

Interconnection has a robust market for energy and ancillary services outside of CAISO 

and that non-CAISO resources may make the economically rational choice to sell power 

to a non-CAISO customer if CAISO has a lower offer cap compared to the non-CAISO 

WECC bilateral market.425 

189. NYISO and Competitive Power Providers state that all market transactions, 

including imports and virtual transactions, should be capped at the level of the hard cap, 

which will allow for a greater degree of competition.426 

190. Some commenters discussed emergency imports. For example, PJM Power 

Providers agrees with PJM that the Commission should not apply the proposed offer 

requirements to emergency imports because an offer cap on emergency energy or 

 423 NY Transmission Owners Comments at 5-6; CEA Comments at 7-8; 

NY Department of State Comments at 5; Powerex Comments at 7-8.

424 CEA Comments at 7-8.

425 Powerex Comments at 7-8.

426 Competitive Suppliers Comments at 23-24; NYISO Comments at 7.
Docket No. RM16-5-000 - 121 -

emergency load reductions would limit PJM’s ability to procure sufficient resources and 

could threaten reliability.427

191. However, the PJM Market Monitor argues that emergency imports above 

$1,000/MWh should be subject to cost verification before they are eligible to set LMP in 

PJM and asserts that such imports currently have an unmitigated opportunity to exercise 

market power in PJM markets.428 The PJM Market Monitor states that the rules of 

competitive markets should apply, even during emergency conditions.429 The PJM 

Market Monitor adds that verifying the costs of emergency imports is feasible because 

they occur infrequently.430 PJM Market Monitor asserts that PJM/SPP offer no rationale 

for exempting emergency imports from the proposed offer cap requirements, which the 

PJM Market Monitor states are most critical during emergency situations.431 

2. Determination

192. We find that it is just and reasonable to permit economic exchange transactions 

(i.e., imports and exports) to offer up to the level of the $2,000/MWh hard cap. We do 

not require that import or export transactions above $1,000/MWh be subject to the 

verification requirement prior to the market clearing process. 

 427 PJM Power Providers Answer at 6-7.

428 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 2-3.

429 PJM Market Monitor Answer at 2.

430 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 3.

431 PJM Market Monitor Answer at 3. 
Docket No. RM16-5-000 - 122 -

193. While in the NOPR the Commission proposed to make imports ineligible to offer 

above $1,000/MWh, i.e., to prohibit imports from making such offers, we now are 

persuaded that such a prohibition could discourage imports at times when they are most 

needed. Imports benefit the market because they offer additional supply and increase 

competition. A prohibition on imports above $1,000/MWh would discourage external 

resources with short-run marginal costs above $1,000/MWh from supplying energy to the 

RTO/ISO market, even though the market is willing to purchase that supply, and such a 

prohibition would thus put upward pressure on energy prices. We applied this rationale 

above in adopting the offer structure requirement and find that it applies equally to 

imports. Additionally, similar to the rationale outlined above for virtual transactions, 

allowing imports to offer up to $2,000/MWh without cost verification is generally 

consistent with the current market structures in RTOs/ISOs, which typically allow 

imports to offer up to the same offer cap that internal RTO/ISO resources are subject to. 

A similar logic applies to export transactions.

194. Further, prohibiting imports from offering above $1,000/MWh could result in 

uneconomic flows between RTOs/ISOs. For example, if the LMP in one RTO/ISO is 

$1,500/MWh and an external resource would like to offer an import at a price of 

$1,400/MWh, a prohibition on import offers above $1,000/MWh would restrict that 

transaction and result in inefficient flows across RTO/ISO boundaries.

195. Additionally, we will not require import offers above $1,000/MWh be costverified and find that imports are not similarly situated to internal generation resources. 

Unlike incremental energy offers from internal resources, import offers are often not 
Docket No. RM16-5-000 - 123 -

resource-specific and, thus, it is difficult – some commenters say impossible – to 

ascertain the underlying costs of most import offers. This approach is consistent with 

current market power mitigation measures in RTOs/ISOs that apply to internal resources 

but do not typically apply to imports. 

196. Additionally, RTO/ISO market participants can import energy from adjacent 

markets and sell that energy in the RTO/ISO energy market. Therefore, it is difficult for 

external resources in an adjacent market to withhold because internal RTO/ISO resources 

can import energy from that adjacent market. Additionally, provided the adjacent market 

is competitive, which is expected if the adjacent market is an RTO/ISO with market 

power mitigation, it would be difficult for an external resource to exercise market power

in the importing RTO/ISO. 

197. Though it is not required, the Commission would consider proposals by 

RTOs/ISOs to verify or otherwise review the costs of imports or exports and/or develop 

additional mitigation provisions for import and export transactions above $1,000/MWh. 

Such proposals should be submitted in a separate filing under section 205 of the Federal 

Power Act. 

198. We clarify that this Final Rule will not apply to Coordinated Transactions 

Schedules, which are spread bids as opposed to energy offers. Additionally, the Final 

Rule will not apply to emergency purchases, which would go beyond the scope of this 

Final Rule because such transactions are administratively priced rather than based on 

short-run marginal cost. 
Docket No. RM16-5-000 - 124 -

VI. Other Comments

199. The Commission also sought comment on various aspects of the verification 

process and the types of costs that should be considered in the verification. Specifically, 

the Commission sought comment on (1) whether the Market Monitoring Unit or 

RTOs/ISOs may need additional information to ensure that all short-run marginal cost 

components that are difficult to quantify, such as certain opportunity costs, are accurately 

reflected in a resource’s cost-based incremental energy offer, and (2) to the extent that 

RTOs/ISOs currently include an adder above cost in cost-based incremental energy 

offers, whether such an adder is appropriate for incremental energy offers above 

$1,000/MWh.432 Commenters also discussed the impact that the proposed offer cap 

reforms could have on other market constructs, such as shortage pricing. 

A. Verification Requirement Details

1. Comments

200. Commenters express differing views on whether opportunity costs are legitimate 

costs, and if so, whether it is appropriate to include them within cost-based incremental 

energy offers. The PJM Market Monitor states that it currently calculates opportunity 

costs at the request of PJM members and does not need additional information about the 

details of opportunity costs.433 The SPP Market Monitor explains that SPP currently 

 432 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 73.

433 PJM Market Monitor Comments at 8. 
Docket No. RM16-5-000 - 125 -

allows an opportunity cost adder above mitigated offers, which would still be appropriate 

to include if costs exceed $1,000/MWh.434

201. Midcontinent Joint Consumer Advocates and TAPS oppose opportunity cost 

adders in the verification methodology for cost-based incremental energy offers above 

$1,000/MWh.435 Midcontinent Joint Consumer Advocates add that if the Commission 

finds that opportunity costs may be recoverable, then the Market Monitoring Unit should 

review such costs to ensure they are just and reasonable.436

202. Commenters expressed a range of opinions regarding whether it is appropriate to 

account for cost uncertainty or other risks through an adder in cost-based incremental 

energy offers above $1,000/MWh. SPP takes no position on the appropriateness of the 

adder but argues that the different RTOs/ISOs should be allowed to develop verification 

rules that are consistent with their existing rules, including adders.437 PJM, MISO, the 

PJM Market Monitor, and Potomac Economics support an adder of up to ten percent to 

 434 SPP Market Monitor Comments at 10. The SPP Market Monitor notes that 

resources can use forecasted LMPs and production costs to estimate price-cost margins 

for each hour of the day to determine the opportunity cost component of the mitigated 

offer.

435 Midcontinent Joint Consumer Advocates Comments at 6-7; TAPS Comments 

at 16.

436 Midcontinent Joint Consumer Advocates Comments at 6-7.

437 PJM/SPP Comments at 24.
Docket No. RM16-5-000 - 126 -

account for uncertainty and risk.438 The ISO-NE Market Monitor states that the primary 

function of a ten percent adder is to provide for errors or under-estimation of a resource’s 

marginal cost and contends that the Commission should not require such an adder unless 

it identifies specific and valid costs that are unique to days with abnormally high natural 

gas prices.439

203. Dominion, Exelon, ODEC, and PJM support the inclusion of a ten percent adder to 

cost-based incremental offers.440 Dominion and Exelon contend that a ten percent adder 

to cost-based incremental offers is appropriate because the adder accounts for some of the 

uncertainty that accompanies fuel cost estimation as well as dispatch instructions.441 

ODEC maintains that the ten percent adder in cost-based incremental energy offers is 

both justified and necessary in PJM and should not be removed because it accounts for 

the fact that some costs are unknown when PJM resources compute their cost-based 

incremental energy offers.442 APPA, NRECA, and AMP state that adders above cost are 

 438 Id. at 22-23; MISO Comments at 15; PJM Market Monitor Comments at 9; 

Potomac Economics Comments at 7. 

439 ISO-NE Market Monitor Comments at 12 

440 Dominion Comments at 6; Exelon Comments at 20 (citing Testimony of Kevin 

A. Libby at 8-9 (Libby Test.)); ODEC Comments at 5-6; PJM/SPP Comments at 22.

441 Dominion Comments at 6; Exelon Comments at 20 (citing Libby Test. at 8-9).

442 ODEC Comments at 6 (citing PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 

at P 30).
Docket No. RM16-5-000 - 127 -

not necessary when a resource’s costs can be accurately verified prior to the market 

clearing process.

443 

204. However, the New Jersey Commission, Direct Energy, PG&E, TAPS, and 

Industrial Customers oppose including a ten percent adder in cost-based incremental 

energy offers above $1,000/MWh.

444 The New Jersey Commission argues that such an 

adder would simply afford the generators an additional ten percent margin of profit above 

their costs that consumers would fund.445 TAPS and Industrial Customers state that the 

ten percent adder should not be included in incremental energy offers above 

$1,000/MWh because the adder does not constitute an actual cost.446 

205. With respect to other short-run marginal cost components, the Pennsylvania 

Commission, CAISO, and Industrial Customers argue that a resource’s permissible shortrun marginal costs should not include unauthorized natural gas costs and natural gas 

pipeline penalties.447 CAISO requests that the Commission convene a technical 

 443 APPA, NRECA, and AMP Comments at 17.

444 Direct Energy Comments at 5; PG&E Comments at 3; New Jersey Commission

Comments at 17; TAPS Comments at 16; Industrial Customers Comments at 25-26 

(citing PJM Market Monitor Comments, Docket No. ER14-1144, at 2, n. 5 (filed Mar. 26, 

2015)).

445 New Jersey Commission Comments at 17.

446 TAPS Comments at 16; Industrial Customers Comments at 25-26 (citing PJM 

Market Monitor Comments, Docket No. ER14-1144, at p. 2, n. 5 (filed Mar. 26, 2015)).

447 Pennsylvania Commission Comments at 5, 10; CAISO Comments at 11-12; 

Industrial Customers Comments at 26.
Docket No. RM16-5-000 - 128 -

conference to discuss limitations in fuel markets and the appropriate parameters for 

determining prudently incurred costs.448 Industrial Customers recount the Commission’s 

reasoning that allowing recovery for costs and penalties of unauthorized gas consumption 

could jeopardize gas pipeline and transmission system reliability, and that generators 

would still have sufficient flexibility.449

206. The Commission also sought comment on whether the verification of physical 

offer components is necessary.450 The ISO-NE Market Monitor states that ISO-NE’s 

existing process to verify physical offer components takes significant time because such 

changes to physical offer parameters cannot be completed on the day that offers are 

due.451 The ISO-NE Market Monitor advises the Commission to avoid imposing time 

limitations that interfere with the ISO-NE Market Monitor’s ability to review and verify 

physical parameters before-the-fact.

452 The PJM Market Monitor requests that the 

Commission clarify that the cost-based offers contemplated in the NOPR include the 

same limits on offer parameters as all other cost-based offers.453 Potomac Economics 

 448 CAISO Comments at 12.

449 Industrial Customers Comments at 26-27 (citing N.Y. Indep. Sys. Operator, 

Inc., 154 FERC ¶ 61,111, at P 1 (2016)).

450 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 73.

451 ISO-NE Market Monitor Comments at 10. 

452 Id. at 11.

453 PJM Market Monitor Comments at 2-3.
Docket No. RM16-5-000 - 129 -

advises that any Final Rule not address physical parameters because additional 

verification of physical parameters is not needed, and the proposal only addressed 

incremental energy offers.454 Midcontinent Joint Consumer Advocates note that physical 

offer components such as generation minimum and maximum levels are already known 

and reviewed by the Market Monitoring Unit, and therefore, there is no need for 

additional verification of physical offer components.455

2. Determination

207. Several commenters state that adders above costs should be included in cost-based 

offers to account for cost uncertainty or risk.456 While we will not require RTOs/ISOs to 

include such an adder, if an RTO/ISO chooses to retain an adder above cost or proposes

to include a new adder above cost in cost-based incremental energy offers above 

$1,000/MWh, such adders may not exceed $100/MWh. On balance, we find that limiting 

adders above cost to $100/MWh is just and reasonable because as clarified above, the 

verification process may involve reviewing a resource’s expected, rather than actual,

costs, which could involve the use of imperfect information. Given that practical reality, 

we find that it is necessary to place an upper bound on the level of adders above cost 

when incremental energy offers exceed $1,000/MWh in order to ensure that cost-based 

 454 Potomac Economics Comments at 11 (citing Potomac Economics PostTechnical Workshop Comments. Docket No. AD14-14-000, at 5 (filed Feb. 24, 2015)).

455 Midcontinent Joint Consumer Advocates Comments at 6.

456 See supra P 203.
Docket No. RM16-5-000 - 130 -

incremental energy offers above $1,000/MWh reasonably and accurately reflect actual or 

expected short-run marginal cost.457 The Commission has previously found in PJM that 

adders above cost are unjust and unreasonable as applied to an after-the-fact review of 

documented costs because the costs are no longer uncertain.458 Applying that same 

reasoning here, if a resource receives uplift after-the-fact because that resource’s costbased incremental energy offer above $1,000/MWh could not be verified prior to the 

market clearing process or because its cost-based incremental energy offer exceeded 

$2,000/MWh, the uplift payments that the resource receives should not include any 

adders above costs. As noted above, after-the-fact uplift would be based on a resource’s 

actual costs.459

208. Based on the record before us, we will not require that additional information on 

short-run marginal cost components be provided to the RTO/ISO or Market Monitoring 

Unit. Furthermore, we will not prescribe the manner in which RTOs/ISOs or Market 

Monitoring Units verify cost-based incremental energy offers above $1,000/MWh. As 

indicated in the NOPR, RTOs/ISOs use different processes to develop and update the 

 457 The Commission notes that it previously accepted adders above costs in 

PJM that exceed $100/MWh. However, after reviewing the record before us in this 

proceeding, we find that it is just and reasonable to limit the adder to $100/MWh. 

See PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 31. 

458 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 31 (citing PJM 

Interconnection, L.L.C., 149 FERC ¶ 61,059 at P 13).

459 See supra P 146.
Docket No. RM16-5-000 - 131 -

incremental energy offers used for mitigation and differ in how they define the 

components of cost-based incremental energy offers.460 While we are taking no action 

at this time on these issues and comments, we do not prejudge what RTOs/ISOs may file 

with the Commission in the future. Accordingly, the Final Rule will not require 

verification of physical offer parameters or financial offer components other than the 

incremental energy offer.

B. Impact of Offer Cap Reforms on Other Market Elements

209. The Commission recognized in the NOPR that revising the offer cap may impact 

other RTO/ISO market elements that depend on the offer cap, such as shortage pricing 

levels or various penalty factors.461

1. Comments

210. Four RTOs/ISOs commented that RTO/ISO market elements other than the offer 

cap may need to be revised if the offer cap is revised. CAISO states that it will face 

significant implementation challenges if it changes its current $1,000/MWh offer cap 

because the administrative penalty prices CAISO uses in its market model to indicate that 

 460 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 61-62.

461 Id. P 72.
Docket No. RM16-5-000 - 132 -

constraints have been relaxed, such as the power balance constraint, are based on the 

offer cap.462

211. PJM states that it would likely need to adjust shortage pricing rules in PJM in light 

of any Final Rule on offer caps.463 SPP states that it would likely need to revise its 

scarcity prices and violation relaxation limits to prevent instances in which LMPs exceed 

scarcity values.464 MISO states that it may need to revise its Operating Reserve Demand 

Curve, $3,500/MWh LMP cap, and Transmission Constraint Demand Curves if MISO’s 

$1,000/MWh offer cap is revised.465

212. APPA, NRECA, and AMP and ODEC state that any Final Rule regarding offer 

caps should be restricted to changing the offer cap and not address potentially associated 

issues such as scarcity pricing.466 In contrast, PG&E recommends that before allowing 

the offer cap to rise above $1,000/MWh, the Commission and the individual RTOs/ISOs 

 462 CAISO Comments at 14-17. CAISO requests that, prior to issuing the Final 

Rule, the Commission conduct a technical conference to better understand the challenges 

of implementation. CAISO Comments at 3, 17.

463 PJM/SPP Comments at 28.

464 Id. at 29.

465 MISO Comments at 3-5.

466 ODEC Comments at 1; APPA, NRECA, and AMP Comments at 20-21.
Docket No. RM16-5-000 - 133 -

should determine all related changes to the markets that would be needed to ensure that 

the markets would function properly.467 

2. Determination

213. An RTO/ISO may file, pursuant to section 205 of the Federal Power Act, to 

propose modifications to shortage prices or other market elements that require revision 

in light of the offer cap reforms adopted in this Final Rule. However, we do not require 

such modifications to comply with this Final Rule. We find that it is not appropriate to 

determine in this Final Rule the changes that individual RTOs/ISOs should make to 

market elements that are not the subject of these reforms.

VII. Requests Beyond the Scope of this Proceeding

A. Comments

214. Commenters raised issues that are not discussed above and that are outside the 

scope of this rulemaking. Several commenters argue that the focus of the 

recommendations in the NOPR is too narrow. API recommends that the Commission 

look for ways to encourage the appropriate integration of new technologies, including 

quickly ramping gas-fired generation technology, to meet rapidly changing gridconditions and allow prices in real-time markets to better reflect the true state of grid 

reliability at a given moment while addressing any remaining concerns of market power 

 467 PG&E Comments at 2.
Docket No. RM16-5-000 - 134 -

abuse.468 API further recommends that the Commission initiate an examination of 

opportunity costs and risk premiums, inclusive of a wider range of resources, in 

wholesale energy market offer pricing and how they may or may not be considered by 

various RTO/ISO market rules.469 

215. The PJM Market Monitor argues that because gas is the only fuel likely to result 

in offers greater than $1,000/MWh, the removal of any cap on short run marginal cost 

therefore relies on the competitiveness of the gas markets.470 The PJM Market Monitor

suggests that a reconsideration of the structure and design of the gas market and the

potential for a gas market RTO/ISO is a longer term solution to address issues of 

transparency and market power in the gas market.471

216. The Pennsylvania Commission states that the Commission should direct PJM and 

other RTO/ISO stakeholders to develop a “circuit breaker” provision to cap energy 

market revenue during uncontrollable and sustained outage events.472 The Pennsylvania 

Commission states that during sustained outages, price signals in energy markets become 

irrelevant, and the main consideration is the time required to repair infrastructure as 

 468 API Comments at 2-3. 

469 Id. at 8. 

470 PJM Market Monitor Comments at 4.

471 Id. at 6.

472 Pennsylvania Commission Comments at 5-7.
Docket No. RM16-5-000 - 135 -

opposed to the economic theory behind energy markets.473 The Pennsylvania 

Commission also recommends that the Commission direct PJM to introduce some level 

of aggregate market power mitigation or impose a screen for aggregate market power in 

the PJM day-ahead and real-time markets.474 PJM Joint Consumer Advocates argue that 

shortage prices in PJM should be revised to represent customers’ willingness to pay,

475

and the Ohio Commission states that scarcity pricing may no longer be necessary in light 

of this Final Rule.476 

217. Industrial Customers argue that increases to the current $1,000/MWh offer cap 

should be explored simultaneously with the elimination of capacity markets, and that the 

Commission could act more methodically to explore ways to improve capacity market 

competitiveness and transparency.477

B. Determination

218. We appreciate the concerns raised by numerous commenters requesting that the 

Commission undertake various initiatives, as set forth above. However, we find that the 

requested initiatives go beyond the scope of this rulemaking, which only addresses 

 473 Id. at 8.

474 Id. at 13-14.

475 PJM Joint Consumer Advocates Comments at 5-6.

476 Ohio Commission Comments at 14-15.

477 Industrial Customers Comments at 29-30.
Docket No. RM16-5-000 - 136 -

incremental energy offers above $1,000/MWh. Accordingly, we will not address those 

concerns here. 

VIII. Information Collection Statement 

219. The Paperwork Reduction Act (PRA)478 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,479 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. 

220. 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) cap each resource’s incremental energy offer at the higher 

of $1,000/MWh or that resource’s verified cost-based incremental energy offer; and 

(2) when calculating LMPs, RTOs/ISOs shall cap verified cost-based incremental energy 

offers at $2,000/MWh. The reforms required in this Final Rule would require a one-time 

 478 44 U.S.C. 3501-3520.

479 5 CFR 1320 (2016).
Docket No. RM16-5-000 - 137 -

tariff filing with the Commission due 75 days after the effective date of this Final Rule 

to implement these reforms. We anticipate the reforms required in this Final Rule, once 

implemented, would not significantly change currently existing burdens on an ongoing 

basis. With regard to those RTOs/ISOs that believe that they already comply with the 

reforms required in this Final Rule, they could demonstrate their compliance in the 

compliance filing required 75 days after the effective date of this Final Rule in this 

proceeding. The Commission will submit the proposed reporting requirements to OMB 

for its review and approval under section 3507(d) of the Paperwork Reduction Act.480 

221. In the NOPR, the Commission sought comments on the accuracy of provided 

burden and cost estimates and any suggested methods for minimizing the respondents’ 

burdens, including the use of automated information techniques. Specifically, the 

Commission sought detailed comments on the potential cost and time necessary to 

implement aspects of the reforms proposed in the NOPR, including (1) software and 

business processes changes, including market power mitigation; (2) increased time spent 

validating cost-based incremental energy offers; and (3) processes for RTOs/ISOs to vet 

proposed changes amongst their stakeholders. The Commission also stated that although 

it did not expect other entities to incur compliance costs as a result of the reforms 

proposed in the NOPR, it sought detailed comments on whether other entities, such as 

 480 44 U.S.C. 3507(d).
Docket No. RM16-5-000 - 138 -

load-serving entities, would incur costs as a result of the reforms proposed in the NOPR. 

The Commission received no comments in response to these questions. 

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 

for the requirements contained in this NOPR follow.481 The Commission notes that these 

cost estimates below do not include costs for software or hardware or for increased time 

spent validating cost-based incremental energy offers above $1,000/MWh.482 Software 

or hardware upgrades may not be required.

 481 The RTOs/ISOs (CAISO, ISO-NE, MISO, NYISO, PJM, and SPP) are required 

to comply with the reforms in this Final Rule. 

482 The Commission expects that the validation of cost-based incremental energy 

offers above $1,000/MWh would be an infrequent occurrence. To the extent that the 

Market Monitoring Unit or the RTO/ISO spends time validating these offers, the 

Commission estimates such time to be de minimis. 
Docket No. RM16-5-000 - 139 -

FERC-516, as modified by Final Rule in Docket RM16-5-000

Number of 

Respondents

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total Number 

of Responses 

(1)×(2)=(3)

Average 

Burden 

(Hours) & 

Cost Per 

Response

(4)

Total 

Annual 

Burden 

Hours & 

Total 

Annual Cost

(3)×(4)=(5)

Cost per 

Respondent

($)

(5)÷(1)

One-Time

Tariff Filings 

(Year 1)

6 1 6

500 hrs.; 

$37,000483 3,000 hrs.; 

$222,000 $37,000

Cost to Comply: The Commission has projected the total cost of compliance, 

all within four months of a Final Rule plus initial implementation, to be $222,000. After 

Year 1, the reforms in this Final Rule, once implemented, would not significantly change 

existing burdens on an ongoing basis. 

 483 The estimated hourly cost (salary plus benefits) provided in this section is

based on the salary figures for May 2015 posted by the Bureau of Labor Statistics for the 

Utilities sector (available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000) and 

scaled to reflect benefits using the relative importance of employer costs in employee 

compensation from June 2016 (available at 

http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates for salary plus 

benefits are:

• Legal (code 23-0000), $128.94

• Computer and mathematical (code 15-0000), $60.54

• Information systems manager (code 11-3021), $91.63

• IT security analyst (code 15-1122), $63.55

• Auditing and accounting (code 13-2011), $53.78

• Information and record clerk (code 43-4199), $37.69

• Electrical Engineer (code 17-2071), $64.20

• Economist (code 19-3011), $74.43

• Management (code 11-0000), $88.94

The average hourly cost (salary plus benefits), weighting all of these skill sets evenly, is 

$73.74. The Commission rounds it to $74 per hour.
Docket No. RM16-5-000 - 140 -

The Commission notes that these estimates do not include costs for software or hardware. 

Software or hardware upgrades may not be required. 

Title: FERC-516C484, Electric Rate Schedules and Tariff Filings.

Action: Proposed revisions to an information collection.

OMB Control No. 1902-0287

Respondents for this Rulemaking: RTOs/ISOs.

Frequency of Information: One-time.

Necessity of Information: The Federal Energy Regulatory Commission approves 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.

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

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

 484 The RM16-5-000 Final Rule reporting requirements should be submitted to 

FERC-516 (OMB Control No. 1902-0096). Currently, that information collection is 

under review for an unrelated activity. The FERC-516C is a temporary information 

collection. The reporting requirements of the RM16-5-000 Final Rule are being 

submitted to FERC-516C to ensure timely submission to OMB.
Docket No. RM16-5-000 - 141 -

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 

Comments concerning the collection of information and the associated burden 

estimate(s), may also be sent to the Office of Information and Regulatory Affairs, Office 

of Management and Budget, 725 17th Street, NW, Washington, DC 20503 [Attention: 

Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-0710, 

fax (202) 395-7285]. Due to security concerns, comments should be sent electronically 

to the following e-mail address: oira_submission@omb.eop.gov. Comments submitted 

to OMB should include FERC-516C and OMB Control No. 1902-0287.

IX. Regulatory Flexibility Act Certification 

223. The Regulatory Flexibility Act of 1980 (RFA)485 generally requires a description 

and analysis of 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.

224. This rule would apply to six RTOs/ISOs (all of which are transmission 

organizations). The average estimated annual cost to each of the RTOs/ISOs is $37,000, 

all in Year 1. This one-time cost of filing and implementing these changes is not 

 485 5 U.S.C. 601-12.
Docket No. RM16-5-000 - 142 -

significant.486 Additionally, the RTOs/ISOs are not small entities, as defined by the 

RFA.487 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. 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 the reforms in this Final Rule would not have a significant economic impact 

on a substantial number of small entities. 

X. Environmental Analysis

225. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

 486 This estimate does not include costs for software or increased time spent 

validating cost-based incremental energy offers. As stated above, the Commission 

expects that the validation of cost-based incremental energy offers above $1,000/MWh 

would be an infrequent occurrence. To the extent that the Market Monitoring Unit or the 

RTO/ISO spends time validating these offers, the Commission expects such time to be

de minimis.

487 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. The 

Small Business Administrations’ regulations at 13 CFR 121.201 define the threshold for 

a small Electric Bulk Power Transmission and Control entity (NAICS code 221121) to be 

500 employees. See 5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 

15 U.S.C. 632.
Docket No. RM16-5-000 - 143 -

on the human environment.488 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.489

XI. Document Availability

226. In addition to publishing the full text of this document in the Federal Register, 

the Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

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

Washington, DC 20426.

227. 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 

 488 Regulations Implementing the National Environmental Policy Act of 1989, 

Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).

489 18 CFR 380.4(a)(15) (2016). 
Docket No. RM16-5-000 - 144 -

document in eLibrary, type the docket number of this document, excluding the last 

three digits, in the docket number field.

228. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from the Commission’s Online Support at 202-502-6652 (toll free 

at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room 

at public.referenceroom@ferc.gov.

XII. Effective Date and Congressional Notification

229. These regulations are effective 75 days from the date the rule is published in the 

Federal Register. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule 

is not a “major rule” as defined in section 351 of the Small Business Regulatory 

Enforcement Fairness Act of 1996.
Docket No. RM16-5-000 - 145 -

List of subjects in 18 CFR Part 35 

Electric power rates

Electric utilities

Non-discriminatory open access transmission tariffs

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM16-5-000 - 146 -

Regulatory Text 

In consideration of the foregoing, the Commission proposes to amend part 35, 

chapter I, title 18, Code of Federal Regulations, as follows: 

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS 

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

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

7352. 

2. Amend § 35.28 by:

Add a new paragraph (g)(9).

§ 35.28 Non-discriminatory open access transmission tariff.

* * * * *

(g) * * * 

(9) A resource’s incremental energy offer must be capped at the higher of $1,000/MWh 

or that resource’s cost-based incremental energy offer. For the purpose of calculating 

Locational Marginal Prices, Regional Transmission Organizations and Independent 

System Operators must cap cost-based incremental energy offers at $2,000/MWh. The 

costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh 

must be verified before that offer can be used for purposes of calculating Locational 

Marginal Prices. If a resource submits an incremental energy offer above $1,000/MWh 

and the costs underlying that offer cannot be verified before the market clearing process 

begins, that offer may not be used to calculate Locational Marginal Prices and the 
Docket No. RM16-5-000 - 147 -

resource would be eligible for a make-whole payment if that resource is dispatched and 

the resource’s costs are verified after-the-fact. A resource would also be eligible for a 

make-whole payment if it is dispatched and its verified cost-based incremental energy 

offer exceeds $2,000/MWh. All resources, regardless of type, are eligible to submit costbased incremental energy offers in excess of $1,000/MWh.

 
Docket No. RM16-5-000 - 148 -

APPENDIX: List of Short Names/Acronyms of Commenters 

Short Name/Acronym Commenter

AEMA Advanced Energy Management 

Alliance

AF&PA American Forest & Paper Association

APPA, NRECA, and AMP American Public Power Association, 

National Rural Electric Cooperative 

Association and American Municipal 

Power, Inc.

API American Petroleum Institute

CAISO California Independent System 

Operator Corporation

CEA Canadian Electricity Association

Competitive Suppliers Electric Power Supply Association , 

Independent Energy Producers 

Association, Independent Power 

Producers of New York Inc., New 

England Power Generators Association 

Inc., Western Power Trading Forum

Delaware Commission Delaware Public Service Commission

Direct Energy Direct Energy Business, LLC, on 

behalf of itself and its affiliate, Direct 

Energy Business Marketing, LLC

Dominion Dominion Resources Services, Inc.

EEI Edison Electric Institute

Exelon Exelon Corporation

Golden Spread Golden Spread Electric Cooperative, 

Inc.

Industrial Customers Electricity Consumers Resource 

Council, PJM Industrial

Customer Coalition, Coalition of 

MISO Transmission Customers, 

American Chemistry Council, 

Association of Businesses Advocating
Docket No. RM16-5-000 - 149 -

Tariff Equity, Connecticut Industrial 

Energy Consumers, Illinois Industrial 

Energy Consumers, Indiana Industrial 

Energy Consumers, Inc., Louisiana 

Energy Users Group, Minnesota Large

Industrial Group, Missouri Industrial 

Energy Consumers, Multiple 

Intervenors, New Jersey Large Energy 

Users Coalition, Wisconsin Industrial 

Energy Group, Inc.

Industrial Energy Consumers Industrial Energy Consumers of 

America

ISO-NE ISO New England, Inc.

ISO-NE Market Monitor ISO New England Inc. Internal Market 

Monitor

IRC ISO/RTO Council 

KEPCo/NCEMC Kansas Electric Power Cooperative, 

Inc. and North Carolina Electric 

Membership Corporation

Joseph Margolies Joseph Margolies

Midcontinent Joint Consumer 

Advocates

Indiana Office of Utility Consumer 

Counselor, Iowa Office of Consumer 

Advocate, Michigan Citizens Against 

Rate Excess, Minnesota Department of 

Commerce, Minnesota Attorney 

General’s Office

MISO Midcontinent Independent System 

Operator, Inc.

NEI Nuclear Energy Institute

NESCOE New England States Committee on 

Electricity

New Jersey Commission New Jersey Board of Public Utilities

NY Department of State New York State Department of State

Utility Intervention Unit

NYISO New York Independent System 

Operator, Inc.

New York Commission New York State Public Service 

Commission

NY Transmission Owners New York Transmission Owners 

(Central Hudson Gas & Electric 
Docket No. RM16-5-000 - 150 -

Corporation, Consolidated Edison 

Company of New York, Inc., New 

York Power Authority, New York 

State Electric & Gas Corporation, 

Niagara Mohawk Power Corporation 

d/b/a National Grid, Orange and 

Rockland Utilities, Inc., Power

Supply Long Island, Rochester Gas 

and Electric Corporation)

ODEC Old Dominion Electric Cooperative

OMS Organization of MISO States

OPSI Organization of PJM States, Inc.

Pennsylvania Commission Pennsylvania Public Utility 

Commission

PG&E Pacific Gas and Electric Company

PJM/SPP PJM Interconnection, L.L.C. and 

Southwest Power Pool, Inc. (Joint 

Comments)

PJM Joint Consumer Advocates Delaware Division of the Public 

Advocate, Office of People’s Counsel 

for the District of Columbia, Illinois 

Citizens Utility Board, Indiana Office 

of Utility Consumer Counselor, 

Kentucky Office of Rate Intervention, 

Office of Attorney General, Maryland 

Office of Peoples’ Counsel, New 

Jersey Division of Rate Counsel, 

Pennsylvania Office of Consumer 

Advocate, Consumer Advocate 

Division of the Public Service 

Commission of West Virginia

PJM Market Monitor Monitoring Analytics, LLC, acting in 

its capacity as the Independent Market 

Monitor for PJM

PJM Power Providers PJM Power Providers Group

Potomac Economics Potomac Economics, Ltd.

Powerex Powerex Corp.

Ohio Commission Public Utilities Commission of Ohio
Docket No. RM16-5-000 - 151 -

SCE Southern California Edison Company

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

Steel Producers’ Alliance Steel Producers’ Alliance

TAPS Transmission Access Policy Study 

Group