154 FERC ¶ 61,038

DEPARTMENT OF ENERGY

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM16-5-000]

Offer Caps in Markets Operated by Regional Transmission Organizations and 

Independent System Operators

(Issued January 21, 2016)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Proposed Rulemaking.

SUMMARY: The Federal Energy Regulatory Commission is proposing to revise its 

regulations to require that each regional transmission organization (RTO) and 

independent system operator (ISO) cap each resource’s incremental energy offer to the 

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

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

FEDERAL REGISTER].

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

ways: 

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

using word processing software should be filed in native applications or print-toPDF format and not in a scanned format.
Docket No. RM16-5-000 - 2 -

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

comments to: Federal Energy Regulatory Commission, Secretary of the 

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

Instructions: For detailed instructions on submitting comments and additional 

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

document.

FOR FURTHER INFORMATION CONTACT:

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
Docket No. RM16-5-000 - 3 -

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Offer Caps in Markets Operated by Regional 

Transmission Organizations and Independent System 

Operators 

Docket No. RM16-5-000

NOTICE OF PROPOSED RULEMAKING

TABLE OF CONTENTS

Paragraph Numbers

I. Background ....................................................................................................................... 6.

A. Offer Caps and Market Power Mitigation in RTOs/ISOs........................................... 8.

B. Offer Cap Waivers and Tariff Changes....................................................................... 12.

C. Comments about Offer Caps ...................................................................................... 18.

1. Need to Modify the Offer Cap................................................................................. 19.

2. Role of the Offer Cap in Market Power Mitigation ................................................ 23.

3. Alternative Offer Cap Designs ................................................................................ 27.

4. RTO/ISO Seams and the Offer Cap ........................................................................ 38.

5. Other Considerations............................................................................................... 40.

II. Need For Reform and Commission Proposal .................................................................. 42.

A. Need for Reform ......................................................................................................... 43.

B. Alternative Offer Cap Proposals Discussed in Comments.......................................... 49.

C. Commission Proposal.................................................................................................. 52.

1. Offer Cap Structure.................................................................................................. 53.

2. Cost-Based Incremental Energy Offer Verification ................................................ 56.

3. Resource Neutrality ................................................................................................. 69.

4. Seams Issues............................................................................................................ 70.

5. Other Considerations............................................................................................... 72.

6. Comments Sought on this Proposal......................................................................... 73.

III. Compliance..................................................................................................................... 74.

IV. Information Collection Statement ................................................................................ 76.

V. Regulatory Flexibility Act Certification ........................................................................ 80.
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VI. Environmental Analysis................................................................................................. 82.

VII. Comment Procedures.................................................................................................... 83.

VIII. Document Availability ................................................................................................ 87.

Regulatory Text

APPENDIX A: List of Short Names/Acronyms of Commenters
154 FERC ¶ 61,038

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Offer Caps in Markets Operated by Regional 

Transmission Organizations and Independent System 

Operators 

Docket No. RM16-5-000

NOTICE OF PROPOSED RULEMAKING

(Issued January 21, 2016)

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory 

Commission (Commission) is proposing to revise its regulations to require that each 

regional transmission organization (RTO) and independent system operator (ISO) cap 

each resource’s incremental energy offer1to the higher of $1,000/MWh or that resource’s 

verified cost-based incremental energy offer. Under this proposal, verified cost-based 

incremental energy offers above $1,000/MWh would be used for purposes of calculating 

Locational Marginal Prices (LMPs). 

2. The Commission preliminarily finds that the offer cap2on incremental energy 

offers (offer cap) may no longer be just and reasonable for several reasons. The offer cap 

may unjustly prevent a resource from recouping its costs by not permitting that resource 

 

1

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

that varies with the output of the generator. 

2

The offer cap for purposes of this NOPR refers to the $/MWh limit on day-ahead 

and real-time incremental energy offers, and not any limits or penalty rates that may 

apply in the capacity or ancillary services markets.
Docket No. RM16-5-000 - 2 -

to include all of its short-run marginal costs within its energy supply offer (supply offer). 

The offer cap may result in unjust and unreasonable rates because it can suppress LMPs 

to a level below the marginal cost of production. Further, because of the offer cap, a 

resource with short-run marginal costs above that cap may choose not to offer its supply 

to the RTO/ISO, even though the market may be willing to purchase that supply.3

Finally, when several resources have short-run marginal costs above the offer cap but are 

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

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

have access to the underlying costs associated with the multiple incremental energy offers 

above the offer cap.

3. To remedy these potential problems associated with the offer cap, the Commission 

proposes to require that each RTO/ISO cap each resource’s incremental energy offer to 

the higher of $1,000/MWh or an incremental energy offer based on that resource’s shortrun marginal cost (cost-based incremental energy offer). Under the proposal, the costs 

underlying each cost-based incremental energy offer above $1,000/MWh must be 

verified before that offer could be used for purposes of calculating LMPs. Under this 

proposal, the Market Monitoring Unit or the RTO/ISO, as prescribed in the RTO/ISO 

 

3 Resources that are subject to must-offer requirements, such as resources with a 

capacity supply obligation, are required to submit a supply offer to the energy market. 

Many resources are subject to must-offer requirements in either the day-ahead or realtime markets. The proposed reform would ensure that such a resource has an economic 

incentive that matches its tariff obligation. It would also provide an economic incentive 

to those resources that are not subject to a must-offer requirement.
Docket No. RM16-5-000 - 3 -

tariff and consistent with Order No. 719,4 must verify the costs within a cost-based 

incremental energy offer.

5

The proposed offer cap would be resource neutral, that is, any 

resource, regardless of fuel-type, would be eligible to submit a cost-based incremental 

energy offer above $1,000/MWh. 

4. The Commission proposes to make a generic change to the offer cap applicable to 

all RTOs/ISOs through a rulemaking to avoid exacerbating seams issues. Seams issues 

could arise if one RTO/ISO has an offer cap that materially differed from a neighboring 

RTO/ISO’s offer cap. Different offer caps in neighboring RTOs/ISOs could result in 

flows that depend on the level of the two offer caps as opposed to economics or reliability 

needs. 

5. The Commission seeks comment on these proposed reforms sixty (60) days after 

publication of this NOPR in the Federal Register. 

 

4 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) (2015). 

5

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) (2015). 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) (2015).
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I. Background

6. On June 19, 2014, the Commission initiated the price formation proceeding.6 In 

initiating that proceeding, the Commission stated that there may be opportunities for the 

RTOs/ISOs to improve the energy and ancillary service price formation process. Staff 

conducted outreach and convened technical workshops on the following four general 

issues: (1) use of uplift payments; (2) offer price mitigation and offer caps; (3) scarcity 

and shortage pricing; and (4) operator actions that affect prices.7 During the fall of 2014, 

Commission staff convened three technical workshops and Commission staff issued 

reports on these topics. At the October 28, 2014 technical workshop, Commission staff 

explored, among other topics, the $1,000/MWh offer cap, including the purpose of the 

offer cap and the role it plays in market power mitigation.

8 While this action proposes to 

address mitigation relevant to energy offers above $1,000/MWh in RTO/ISO markets, the 

Commission has also instructed staff to undertake a more comprehensive review of the 

market power mitigation rules in the RTO/ISO markets.

 

6

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). 

7

Id. at 1, 3-4. 

8

See Supplemental Notice of Workshop on Price Formation: Scarcity and 

Shortage Pricing, Offer Mitigation, and Offer Caps in RTO and ISO Markets, Docket 

No. AD14-14-000 (Oct. 10, 2014).
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7. Two of the Commission’s goals in the price formation proceeding are relevant 

here. First, clearing prices in the energy and ancillary services markets should ideally 

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

constraints.”9 Second, LMPs should “ensure that all suppliers have an opportunity to 

recover their costs.”10 Establishing LMPs that accurately reflect the marginal cost of 

production is a central goal of the price formation effort. This goal is important because 

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

cost of providing the next unit of energy. In the short-run, accurate price signals from 

LMPs are particularly important during high price periods because 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, accurate price signals from LMPs are 

important because they inform investment decisions. It is also important that RTOs/ISOs 

give resources the opportunity to recover their costs because failing to do so may 

discourage resources from participating in RTO/ISO energy markets. Adequate 

investment in resources and participation of resources in RTO/ISO energy markets are 

necessary to ensure economic and reliable energy for consumers.

 

9

Price Formation Notice at 2. 

10 See Price Formation in Energy and Ancillary Servs. Mkts. Operated by Reg’l 

Transmission Orgs. & Indep. Sys. Operators, 153 FERC ¶ 61,221, at P 2 (2015); see also

Price Formation Notice at 2. 
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A. Offer Caps and Market Power Mitigation in RTOs/ISOs

8. Supply offers in day-ahead and real-time energy markets consist of both physical 

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

describe the resource’s physical operating parameters, such as its minimum and 

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

denominated in MW, MWh, time, or some combination thereof. 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 to supply electricity in a given interval. 

The key financial components of a supply offer are the start-up cost, no-load cost, and 

incremental energy offers. A resource includes its costs that vary with output in its

incremental energy offer, which typically consists 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.11 

9. The LMP reflects the marginal cost of serving load at a specific location, given the 

set of generators that are dispatched and the limitations of the transmission system.12 The 

LMP is calculated by an RTO/ISO as the sum of three components: an energy charge, a 

congestion charge, and a charge for transmission losses. The energy and congestion

 

11 RTOs/ISOs typically restrict incremental energy supply curves to ten price and 

quantity pairs (i.e., ($/MWh, MW)). 

12 See Federal Energy Regulatory Commission, Division of Energy Market 

Oversight Office of Enforcement, Energy Primer, at 60 (Nov. 2015), 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
Docket No. RM16-5-000 - 7 -

components of the LMP are established based on several factors, including the marginal 

resource’s incremental energy offer, specifically the $/MWh price associated with the 

MW output of the marginal resource.

10. All six Commission-jurisdictional RTOs/ISOs have imposed a $1,000/MWh cap 

on incremental energy offers.13 The offer cap remains at $1,000/MWh in all RTOs/ISOs 

except PJM because, as discussed further below, the Commission recently approved 

PJM’s proposal to raise the offer cap on cost-based offers in PJM to $2,000/MWh.14 In 

each RTO/ISO, a resource’s incremental energy offer is subject not only to the offer cap, 

but also to market power mitigation provisions.15 The Market Monitoring Unit for each 

RTO/ISO currently oversees, and in some cases implements, the market power mitigation 

provisions. In general, when a resource’s incremental energy offer is mitigated, that offer

is replaced with an estimate of a competitive offer or an estimate of that resource’s short-

 

13 See, e.g., California Independent System Operator Corporation (CAISO), 

eTariff, § 39.6.1.1 (11.0.0); ISO New England Inc. (ISO-NE),Transmission, Markets and 

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

III.A.15.1(b) (27.0.0); Midcontinent Independent System Operator, Inc. (MISO), FERC 

Electric Tariff, §§ 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), NYISO Tariffs, NYISO Markets and Services Tariff, §§ 21.4 and 21.5.1 

(7.0.0); PJM Interconnection, L.L.C. (PJM), Intra-PJM Tariffs, OATT, Tariff Operating 

Agreement, Attachment K, Appendix, § 1.10.1A(d) (24.0.0); Southwest Power Pool, Inc. 

(SPP), OATT, Sixth Revised Volume No. 1, Attachment AE, Section 4.1.1 (2.0.0). 

14 PJM Interconnection L.L.C., 153 FERC ¶ 61,289, at P 25 (2015) (PJM 2015/16 

Offer Cap Order). The tariff provisions related to the offer cap do not have a sunset date.

15 See 18 CFR 35.28(g)(3)(iii)(B)-(D) (2015).
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run marginal cost.16 In most instances, once mitigated, a resource’s offer is eligible to set 

LMP.17 Mechanically, the RTOs/ISOs have adopted mitigation rules that either develop 

a proxy for a competitive offer or explicitly estimate short-run marginal cost. Because 

we expect that a competitive offer will closely track a resource’s short-run marginal cost, 

both methods for mitigating offers should arrive at roughly the same result. The Market 

Monitoring Units in CAISO, MISO, ISO-NE, and NYISO typically mitigate the 

resource’s incremental energy offer to the proxy of a competitive offer that is calculated 

by the Market Monitoring Unit.18 However, these RTOs/ISOs also have provisions 

whereby the Market Monitoring Unit, often after consultation with the resource itself, can 

estimate the resource’s short-run marginal cost, which will form the basis of that 

resource’s mitigated incremental energy offer. In PJM and SPP, resource owners develop 

cost-based incremental energy offers consistent with the requirements of these RTOs’

 

16 The RTOs/ISOs use different terms for a mitigated offer. ISO-NE, MISO, and 

NYISO mitigate supply offers to a “Reference Level.” See ISO-NE, Transmission 

Markets and Services Tariff, Market Rule 1, § III.A.7.2; MISO FERC Electric Tariff, 

§ 64.1.4 (30.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, 

§ 23.3.1.4 (11.0.0). CAISO mitigates supply offers to “Default Energy Bids.” See

CAISO, eTariff, § 39.7.1 (11.0.0). PJM mitigates supply offers to a “cost-based offer.” 

See PJM Operating Agreement, Schedule 1, §§ 1.10.1A (24.0.0) and 6.4.1 (7.0.0). SPP 

mitigates supply offers to a “Mitigated Energy Bid.” See SPP OATT, Sixth Revised 

Volume No. 1, Attachment AF, § 3.2 (7.0.0). For purposes of this NOPR, the offers 

RTOs/ISOs use for purposes of mitigation will be referred to as “cost-based offers.”

17 There are exceptions to this eligibility, for instance, when a resource is 

committed outside of the market clearing process.

18 See supra n.16.
Docket No. RM16-5-000 - 9 -

tariffs and business practice manuals and those cost-based offers are subject to review by 

the Market Monitoring Unit.

19

11. While the offer cap restricts incremental energy offers, the offer cap does not limit 

LMPs to the level of the offer cap (be it $1,000/MWh or $2,000/MWh) because the 

congestion and loss components of the LMP can cause the LMP to exceed the offer cap. 

Scarcity pricing and emergency purchases can also cause LMPs to exceed the offer cap 

even though incremental energy offers are limited by the offer cap. 

B. Offer Cap Waivers and Tariff Changes

12. The $1,000/MWh offer cap dates back to 1999 when PJM first launched its 

market.20 According to PJM’s market monitor, PJM’s offer cap was then set to a level 

that stakeholders considered “beyond the possible pale” of a resource’s short-run 

marginal cost.21 PJM states that its $1,000/MWh offer cap was never intended to limit 

incremental energy offers below a resource’s marginal cost to produce energy.22 

 

19 PJM resources develop cost-based offers pursuant to PJM Manual 15: Cost

Development Guidelines. SPP resources develop Mitigated Energy Bids pursuant to 

SPP’s Mitigated Offer Guidelines in the SPP Market Protocols.

20 See Docket Nos. OA97-261-000 and ER97-1082-000 (Apr. 1, 1997); 

Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ¶ 61,257 (1997). 

21 Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, 

Docket No. AD14-14-000, Tr. 209:18-22 (Oct. 28, 2014).

22 PJM Comments at 2. All comments cited herein were submitted in Docket 

No. AD14-14-000 on or about March 6, 2015. 
Docket No. RM16-5-000 - 10 -

13. Extreme weather during the winter of 2013/14, dubbed the “Polar Vortex,” caused 

PJM and NYISO to request tariff waivers associated with the $1,000/MWh offer cap. 

During the Polar Vortex, various weather-related conditions led to a significant increase 

in the price of natural gas.23 Natural gas prices at two key pricing points in PJM rose 

above $120 per million British Thermal Units (MMBtu), which could have caused some 

PJM resources with must-offer requirements to operate at a loss because their short-run

marginal costs were above the $1,000/MWh offer cap.24 

14. In response, on January 23, 2014, 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 costbased offers above $1,000/MWh receive uplift payments to recoup those costs.25

 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 offers in 

 

23 See, e.g., FERC Staff, Commission and Industry Actions Relevant to Winter 

2013-14 Weather Events (Oct. 16, 2014), https://www.ferc.gov/media/newsreleases/2014/2014-4/10-16-14-A-4-presentation.pdf.

24 PJM Interconnection, L.L.C., 146 FERC ¶ 61,041, at P 2, order on reh’g, 

149 FERC ¶ 61,059 (2014). For example, a natural gas resource with a heat rate of 

8,350 Btu/kWh could have short-run marginal fuel costs above $1,000/MWh if the 

natural gas price exceeds $120/MMBtu.

25 Id. P 1.
Docket No. RM16-5-000 - 11 -

excess of $1,000/MWh and cost-based offers were used for purposes of calculating

LMPs.26 

15. Similarly, high natural gas prices in New York prompted NYISO to file a waiver 

request related to its offer cap.

27

 Natural gas prices at the Transco Zone 6 NY hub in 

New York rose above $120/MMBtu in January 2014. In response, NYISO requested that 

resources be permitted to recover any unrecovered costs above $1,000/MWh through 

uplift payments. The Commission granted NYISO’s requested waiver for the 

January 22 - February 28, 2014 period.28

16. In the following winter of 2014/15, citing concerns about the potential for a repeat 

of the high natural gas prices experienced during the Polar Vortex, PJM and MISO 

submitted fillings to allow recovery of costs above $1,000/MWh during the winter 

months. Both PJM29 and MISO30 expressed concerns that the $1,000/MWh offer cap 

could prevent a resource from recouping its short-run marginal costs. The Commission 

accepted tariff provisions that temporarily raised PJM’s offer cap on cost-based offers to 

 

26 PJM Interconnection, L.L.C., 146 FERC ¶ 61,078, at PP 3-4 (2014).

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

28 Id. P 24.

29 PJM Interconnection L.L.C., 150 FERC ¶ 61,020, at P 5 (2015) (PJM 2014/15 

Offer Cap Order). 

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

(MISO 2014/15 Offer Cap Order). 
Docket No. RM16-5-000 - 12 -

$1,800/MWh during the January 16 – March 31, 2015 period.

31

 The Commission granted 

a waiver that permitted resources in MISO to include incremental energy costs in excess 

of $1,000/MWh in the no-load component of their supply offers during the December 20, 

2014 – April 30, 2015 period.

32

 When accepting PJM’s proposal and granting MISO’s 

waiver request, the Commission reasoned that market conditions during the previous 

2013/14 winter demonstrated that the $1,000/MWh offer cap could prevent resources 

from submitting incremental energy offers that reflect their marginal costs and could 

therefore force resources to offer to sell electricity below cost.33 Tariff provisions related 

to the offer cap in both MISO and PJM reverted back to their original form in spring 

2015. 

17. For the winter of 2015/16, PJM34 and MISO35 again filed requests to modify their 

respective offer caps. The Commission accepted tariff revisions in PJM that would raise 

the offer cap on cost-based offers to $2,000/MWh for purposes of calculating LMPs

 

31 PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020. 

32 MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083. 

33 See PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 34; MISO 2014/15 

Offer Cap Order, 150 FERC ¶ 61,083 at P 17. 

34 PJM, Proposed Tariff Revisions, Docket No. ER16-76-000 (filed Oct. 14, 

2015).

35 MISO, Request for Waiver, Docket No. ER16-248-000 (filed Nov. 2, 2015).
Docket No. RM16-5-000 - 13 -

going forward.

36

 In accepting the changes, the Commission reasoned that PJM’s 

proposal would send transparent market signals, promote efficient resource selection,

and address the risks caused by high natural gas prices while protecting consumers by 

requiring cost verification of incremental energy offers above $1,000/MWh.37 The 

Commission granted MISO’s request to waive provisions related to the offer cap for the 

January 1, 2016-April 30, 2016 period. The MISO waiver for the winter of 2015/16 was 

virtually identical to the waiver for the winter of 2014/15 and allowed MISO resources to 

include incremental energy costs in excess of $1,000/MWh in the no-load component of 

their offers.38

C. Comments about Offer Caps 

18. In its January 2015 notice inviting post-technical workshop comments in the price 

formation proceeding, the Commission asked specific questions about the $1,000/MWh 

 

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

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

37 Id. PP 25-26. Resources can submit cost-based offers above $2,000/MWh and 

PJM will use such offers for merit order dispatch, but incremental energy offers used for 

purposes of calculating LMP are capped at $2,000/MWh.

38 Midcontinent Indep. Sys. Operator, Inc., 154 FERC ¶ 61,006 (2015) (MISO 

2015/16 Offer Cap Order).
Docket No. RM16-5-000 - 14 -

offer cap and asked stakeholders to comment on various alternative offer cap designs.39 

Comments about the $1,000/MWh offer cap focus on the need to modify the offer cap, 

the role that the offer cap plays in market power mitigation, alternative offer cap designs, 

potential seams issues, and other considerations. 

1. Need to Modify the Offer Cap

19. Commenters differ about the need to raise or remove the $1,000/MWh offer cap. 

Several commenters argue that the $1,000/MWh offer cap should be raised or removed 

entirely, given recent occurrences of high natural gas prices. Some commenters cite the 

recent offer cap waiver orders as evidence that the current offer cap is not just and 

reasonable.40 Several commenters reference the Polar Vortex in the winter of 2013/14, 

when resources experienced marginal production costs in excess of $1,000/MWh, as 

evidence that the current offer cap is inappropriate.41 For example, OMS states that it is 

appropriate to consider an upward revision or removal of the offer cap to ensure supply 

 

39 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 2-3 

 

(Jan. 16, 2015). A list of commenters and the abbreviated names the Commission will 

use for them in this document appears in Appendix A.

40 ANGA Comments at 2; Brookfield Comments at 7; EPSA Comments at 24; 

Entergy Nuclear Power Marketing Comments at 11-12; Exelon Comments at 10-11; PJM 

Comments at 2-3; PJM Power Providers Comments at 2-4; SPP Comments at 1; Western 

Power Trading Forum Comments at 5-6.

41 EPSA Comments at 21-24; Exelon Comments at 10-12; OMS Comments at 2; 

PJM Comments at 2-3; PJM Power Providers Comments at 2. 
Docket No. RM16-5-000 - 15 -

adequacy during extreme events such as those that occurred during the winter of 

2013/14.42 

20. Several commenters also assert that the offer cap distorts price signals and creates 

market inefficiencies.43 Commenters state that the offer cap artificially suppresses 

clearing prices.44 Some commenters believe that the offer cap restricts market 

participants from receiving appropriate compensation for costs incurred legitimately.45 

21. Several commenters stress that the offer cap should be high enough to ensure that 

resources can reflect their actual costs in supply offers.46 EPSA maintains that the offer 

cap was never intended to suppress marginal cost bidding.47 MISO states that the offer 

cap should be modified to ensure that all resources are able to recover at least the costs 

they incur to produce energy.48 MISO and PJM contend that an offer cap that prevents 

 

42 OMS Comments at 2.

43 PJM Utilities Coalition Comments at 3-4; Western Power Trading Forum 

Comments at 5.

44 Direct Energy Comments at 2; EPSA Comments at 21.

45 ANGA Comments at 2-3; Xcel Comments at 2.

46 ANGA Comments at 2; Brookfield Comments at 7; Entergy Nuclear Power 

Marketing Comments at 11-12; ISO-NE Comments at 5; IRC Comments at 2-3; MISO 

Comments at 4; PJM Comments at 2; PJM Power Providers Group Comments at 2-4; 

Potomac Economics Comments at 3; Powerex Comments at 29-30; PSEG Companies 

Comments at 5-6; Western Power Trading Forum Comments at 5-6.

47 EPSA Comments at 21-22.

48 MISO Comments at 4. 
Docket No. RM16-5-000 - 16 -

resource cost recovery can increase the likelihood that resources will be unavailable to 

system operators.49 SPP and Western Power Trading Forum state that raising the offer 

cap might reduce out-of-market operator actions and uplift.50 

22. Some commenters oppose modifying the $1,000/MWh offer cap.51 CAISO, ISONE, and NYISO assert that, because resource marginal costs are well below 

$1,000/MWh, there is no evidence that the $1,000/MWh offer cap should be raised in 

their respective markets.52 CAISO opposes any effort to increase the offer cap until 

sufficient benefits are identified.

53

 NCPA, PG&E, and SCE state that the current offer 

cap ensures just and reasonable rates and mitigates market power in CAISO.54 NCPA 

and SCE state that the offer cap is sufficient in CAISO because generators there have 

never experienced costs above $1,000/MWh.55 SCE adds that the marginal cost of the 

least efficient CAISO resource at the highest natural gas price seen in the region is only 

 

49 Id.; PJM Comments at 2.

50 SPP Comments at 1; Western Power Trading Forum Comments at 5-6.

51 APPA and NRECA Comments at 30; CAISO Comments at 3; ELCON 

Comments at 6.

52 CAISO Comments at 3; ISO-NE Comments at 3 & n.2; NYISO Comments at 4.

53 CAISO Comments at 3. 

54 NCPA Comments at 2; PG&E Comments at 3; SCE Comments at 3; see also

California State Water Project Comments at 2; New York Transmission Owners 

Comments at 2.

55 NCPA Comments at 2-3; SCE Comments at 2. 
Docket No. RM16-5-000 - 17 -

$390/MWh.56 APPA and NRECA assert that there is insufficient justification to remove 

offer caps nationwide.57

2. Role of the Offer Cap in Market Power Mitigation

23. At the October 28, 2014 price formation technical workshop, several market 

monitors discussed the backstop role that the $1,000/MWh offer cap plays in market 

power mitigation. NYISO’s internal market monitor stated that the offer cap provided a 

“backstop” assurance to protect consumers in the event that NYISO’s market mitigation 

measures fail.

58

 Similarly, ISO-NE’s internal market monitor stated that the offer cap is a 

device that limits the potential damage to consumers or the market in the event that 

market power mitigation measures are unsuccessful.

59

 CAISO’s internal market monitor 

stated that the offer cap primarily functions as a “damage control cap” but also noted that 

the offer cap affects the penalty prices of constraints in CAISO’s market software.60 

Potomac Economics, which serves as an external market monitor for MISO, ISO-NE, and 

NYISO, stated that the offer cap is too high to address general market power concerns,

 

56 SCE Comments at 2. According to SCE, the $390/MWh figure assumes a heat 

rate of 17,000 Btu/kWh, slightly higher than the least efficient unit in CAISO, and a 

natural gas price of $23/MMBtu. 

57 APPA and NRECA Comments at 32.

58 Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps Workshop, 

Docket No. AD14-14-000, Tr. 205:6-15 (Oct. 28, 2014).

59 Id. at 206:24-207:7.

60 Id. at 210:14-23.
Docket No. RM16-5-000 - 18 -

but explained that the offer cap addresses gaming strategies that market participants may 

engage in to collect undue uplift payments.61

24. In response to the Commission’s request for comments on price formation topics, 

several commenters suggest that the offer cap’s purpose has been supplanted by 

improvements in market monitoring and mitigation and the Commission’s enforcement

activity.

62

 Wisconsin Electric asserts that the offer cap is irrelevant because RTO/ISO 

market monitors have effective mitigation measures in place and can refer suspected 

manipulation to the Commission’s Office of Enforcement.63 Direct Energy states that an 

offer cap is not necessary when resources cannot exercise market power because 

competition will discipline offers.64 GDF SUEZ argues that offer caps are the least 

efficient method of protection against uncompetitive offers because offer caps are 

indifferent to the specifics of a supply offer and do not reflect potentially changed 

circumstances since the offer cap level was established over ten years ago.65 

 

61 Id. at 211:25-212:14.

62 ANGA Comments at 2-3; Entergy Nuclear Power Marketing Comments at 11; 

EPSA Comments at 22-23; Exelon Comments at 11-12; Wisconsin Electric Comments at 

2-3; Xcel Comments at 2.

63 Wisconsin Electric Comments at 2.

64 Direct Energy Comments at 2.

65 GDF SUEZ Comments at 3.
Docket No. RM16-5-000 - 19 -

25. Several other commenters assert that the offer cap is a backstop measure to 

protect consumers against the exercise of market power during tight system conditions.66 

Other commenters emphasize the importance of strengthening market monitoring and 

mitigation provisions if offer caps are eliminated or increased.67 ISO-NE asserts that 

while the offer cap has become less important with market power mitigation, the offer 

cap still serves as a “fail-safe” mechanism to protect consumers in the unlikely event that 

the market is not competitive and market power mitigation fails to assure competitive 

supply offers.68 OMS warns that any effort to raise or remove the offer cap must be 

based on the Commission’s confidence not only in the ability of RTO/ISO market power 

mitigation provisions to prevent generator market power abuses, but also in whether the 

prices of input costs were developed in a competitive market.69 

26. Potomac Economics maintains that the offer cap is necessary to keep resources 

from exploiting any previously unknown flaws in market rules.70 Some commenters 

assert that due to load’s inelastic demand for electricity, offer caps are necessary to 

 

66 ISO-NE Comments at 4; MISO Comments at 5-6; New York Transmission 

Owners Comments at 2-3; NYISO Comments at 3; TAPS Comments at 10-11; California 

State Water Project Comments at 2-3. 

67 Direct Energy Comments at 2; MISO Comments at 9; NCPA Comments at 3; 

New York Transmission Owners Comments at 4; Wisconsin Electric Comments at 2-3.

68 ISO-NE Comments at 4.

69 OMS Comments at 2.

70 Potomac Economics Comments at 3-4.
Docket No. RM16-5-000 - 20 -

protect consumers from excessive prices and to maintain confidence that rate structures 

are fair and nondiscriminatory.71 TAPS states that on normal days when there are no 

generators with marginal costs “anywhere close to” $1,000/MWh, there are still 3,000 

to 4,000 MW offered at the offer cap.72 TAPS suggests that weakening the offer cap is 

particularly dangerous because energy markets cannot be halted, so if widespread abuse 

occurs, after-the-fact resettlements incur massive costs and diversion of resources.73 

APPA and NRECA assert that the offer cap should only be increased if RTOs/ISOs can 

guarantee that all offers are cost-based in order to guarantee appropriate prices and 

prevent the need to re-run markets after-the-fact.74

3. Alternative Offer Cap Designs

27. In its January 2015 notice inviting post-technical workshop comments in the price 

formation proceeding, the Commission sought comment on potential alternative offer cap 

designs, including (1) maintaining the $1,000/MWh offer cap and compensating 

resources for incremental energy costs above the $1,000/MWh offer cap through uplift;

 

71 ELCON Comments at 6; TAPS Comments at 10-11.

72 TAPS Comments at 12-13 (citing Scarcity and Shortage Pricing, Offer 

Mitigation and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 217:17-21 (Oct. 28, 

2014)).

73 TAPS Comments at 11 (citing Written Statement of Patrick T. Connors on 

Behalf of WPPI Energy and the Transmission Access Policy Study Group Regarding 

Impacts of Offer Caps and Market Power Mitigation, at 5 (Dec. 3, 2014)).

74 APPA and NRECA Comments at 31-32.
Docket No. RM16-5-000 - 21 -

(2) adopting a floating offer cap that changes with natural gas prices; (3) raising the offer 

cap to a higher fixed level; and (4) allowing resources to submit cost-based offers above 

$1,000/MWh and allowing verified cost-based offers above $1,000/MWh to set LMP.

a. Maintain Current Offer Cap with Uplift

28. Some commenters assert that infrequent events where production costs exceed 

$1,000/MWh can be addressed effectively through uplift payments without raising the 

offer cap or otherwise including such costs in the LMP.75 APPA and NRECA state they 

support generator recovery of legitimate and verified costs but assert that such costs 

should not necessarily be included in LMP.76 APPA and NRECA add that uplift will 

ensure cost recovery without risking market power abuse and what APPA and NRECA

say would be the attendant increased unjust and unreasonable rates.77 

29. APPA and NRECA assert that the market clearing process does not allow 

sufficient time to verify whether incremental energy offers above $1,000/MWh are in fact 

cost-based; thus, these commenters argue, such cost verification should occur after-thefact, with costs in excess of the offer cap recovered through uplift.78

 SCE and PG&E 

 

75 Id. at 29-31; California State Water Project Comments at 2-3; New York 

Transmission Owners Comments at 2-3.

76 APPA and NRECA Comments at 31.

77 Id. at 31.

78 Id. at 31-32.
Docket No. RM16-5-000 - 22 -

state that CAISO has tools to accommodate the rare instances when the $1,000/MWh 

offer cap is insufficient to recover a resource’s costs.79

b. Floating Offer Cap

30. Several commenters support a floating offer cap that changes with generator input 

costs, such as the price of natural gas. Calpine asserts that offer caps should be flexible 

and responsive to changes in natural gas prices,80 and recommends that the Commission 

encourage each RTO/ISO to implement a floating offer cap.81 Powerex suggests that the 

offer cap could equal the higher of $1,000/MWh or some multiple of a pre-defined 

regional natural gas index.82 SPP states that a seasonal fixed offer cap might be 

appropriate.83 Similarly, OMS maintains that the offer cap need not be constant 

throughout the year if resource costs vary throughout the year.84

31. ISO-NE and MISO, however, argue that a floating offer cap would be difficult to 

implement.85 ISO-NE opposes basing the offer cap on an index that attempts to track fuel 

prices, arguing that doing so would be complex and difficult to implement because intra-

 

79 PG&E Comments at 3-4; SCE Comments at 3.

80 Calpine Comments at 4-6.

81 Id. at 21.

82 Powerex Comments at 30.

83 SPP Comments at 1. 

84 OMS Comments at 3.

85 ISO-NE Comments at 4-6; MISO Comments at 5-7.
Docket No. RM16-5-000 - 23 -

day natural gas indices are opaque and day-ahead natural gas indices, while arguably 

less opaque, can become “stale” during the operating day.86 MISO argues that although 

it may consider a floating offer cap in the longer term, a transition to such an offer cap 

would likely require substantial system changes.87 ISO-NE asserts that if the 

Commission is concerned that a fixed offer cap lacks flexibility, the Commission should 

revisit the offer cap over time as the markets for the major fuels used in power generation 

continue to evolve.88 

c. Higher Fixed Offer Cap

32. Some commenters support raising the offer cap to a higher level. ANGA states 

that, at a minimum, the offer cap should be increased significantly to reduce unnecessary 

market distortions.89 Exelon argues that the current $1,000/MWh cap on market-based 

offers in PJM should be eliminated, but maintains that, if the offer cap remains in place, it 

should be raised to account for the highest reasonably expected offer, and that cost-based 

offers should be allowed to exceed the market-based offer cap.90 

 

86 ISO-NE Comments at 6.

87 MISO Comments at 5-6. 

88 ISO-NE Comments at 6-7.

89 ANGA Comments at 3.

90 Exelon Comments at 12.
Docket No. RM16-5-000 - 24 -

33. If the Commission chooses to raise the offer cap, ISO-NE urges using a simple 

numerical value rather than a more complicated formula.91 ISO-NE is neutral on 

raising the offer cap but suggests that any changes to the offer cap level be made in a 

straightforward manner so that participants know with certainty what the offer cap will be 

when they make advance fuel-supply arrangements.92 MISO does not oppose raising the 

offer cap but favors a fixed offer cap to a floating offer cap in the short term.

93

 MISO 

states that a fixed offer cap simplifies the process of implementing related market 

mechanisms such as scarcity or shortage pricing, ancillary services, and transmission 

demand curves and notes that MISO’s current market software systems were designed 

based upon a fixed offer cap.94 

34. TAPS asserts that permanently increasing the offer cap to allow incremental 

energy offers above $1,000/MWh “day-in and day-out” would sacrifice the benefits of 

the current offer cap as a “backstop” protection against market power abuse to address 

“extreme circumstances” that rarely, if ever, occur.95 APPA and NRECA argue that it is 

not necessary to increase the offer cap broadly because APPA and NRECA say there is 

 

91 ISO-NE Comments at 6.

92 Id. at 3-4.

93 MISO Comments at 4-5.

94 Id. at 5.

95 TAPS Comments at 13.
Docket No. RM16-5-000 - 25 -

no evidence that the $1,000/MWh offer cap is persistently flawed.96 APPA and NRECA 

add that resources’ incremental energy offers only exceeded $1,000/MWh in PJM on 

“just a few days in one month of one year.”97

d. Permitting Cost-Based Incremental Energy Offers Above 

$1,000/MWh

35. Some commenters argue that cost-based incremental energy offers should not be 

capped.98 PJM states that cost-based offers should not be subject to offer caps because 

offer caps impose arbitrary limits.99 PJM suggests that one approach may be to set a 

market-based offer cap on an annual basis at some percentage above the highest costbased incremental energy offer from previous time periods.100

 PJM Power Providers and 

PSEG Companies assert that cost-based offers should not be capped and should be 

eligible to set the LMP.101 APPA and NRECA state that if the Commission wishes to 

revise the offer cap, it should limit any increase in the offer cap to periods when 

production costs exceed $1,000/MWh and ensure that any changes to the offer cap are 

 

96 APPA and NRECA Comments at 30-31.

97 Id. at 30-31.

98 Direct Energy Comments at 2; Exelon Comments at 12; PJM Comments at 3; 

PJM Power Providers Comments at 3-4; PSEG Companies Comments at 5.

99 PJM Comments at 2-3.

100 Id. at 4.

101 PJM Power Providers Comments at 4; PSEG Companies Comments at 6.
Docket No. RM16-5-000 - 26 -

accompanied by assurances that protect consumers against market power abuse.

102

Although TAPS does not support increasing the $1,000/MWh offer cap, TAPS similarly 

states that if the Commission wants to take temporary or seasonal action, the Commission 

should at the very least require that any incremental energy offer above $1,000/MWh be 

verified by the market monitor to be cost-justified.103

36. APPA and NRECA, CAISO and NCPA, however, argue that cost-based 

incremental offers must be verified before the market clears in order to avoid potentially 

disruptive after-the-fact corrections to clearing prices, and these commenters raise

concerns that it is not feasible to do so.104 CAISO does not believe there is a firm basis to 

verify the natural gas price included in supply offers because market participants might 

not purchase natural gas before submitting offers and because natural gas quotes might

not be available. CAISO also states that natural gas prices and quotes may be subject to 

manipulation, thereby making fuel cost verification difficult.105 CAISO requests that if 

the Commission directs RTOs/ISOs to pay resources uplift for fuel costs above the offer 

cap, then only incremental fuel costs associated with the incremental energy offer be 

 

102 APPA and NRECA Comments at 30-32.

103 TAPS Comments at 13-14.

104 APPA and NRECA Comments at 32; CAISO Comments at 6-7, NCPA 

Comments at 2. 

105 CAISO Comments at 4-6.
Docket No. RM16-5-000 - 27 -

reimbursable. In contrast, CAISO states that costs such as natural gas pooling, imbalance 

penalties, or risk premiums should be recovered through capacity payments.106

37. TAPS contends that advance review and verification of cost-based incremental 

offers should be possible for most generators.107 Direct Energy states that RTOs/ISOs 

have sufficient time to verify natural gas costs in the day-ahead and real-time markets and 

suggests that LMPs can be “flagged” and revised after-the-fact should the RTOs/ISOs 

have any concerns.108 

4. RTO/ISO Seams and the Offer Cap

38. Most commenters state that offer caps should be the same for each RTO/ISO, 

to minimize potential seams issues.

109

 IRC, PJM, and PSEG Companies assert that 

transmission congestion and other market-to-market coordination will be disrupted if 

offer caps differ across markets.110 ISO-NE and NYISO contend that different offer caps 

in neighboring markets could create perverse interchange flows resulting from the level 

 

106 Id. at 6.

107 TAPS Comments at 14-15.

108 Direct Energy Comments at 3-4.

109 Brookfield Comments at 8; Calpine Comments at 5; EEI Comments at 9; EPSA 

Comments at 21; Exelon Comments at 13-14; IRC Comments at 2; ISO-NE Comments at 

6-7; MISO Comments at 8; New York Transmission Owners Comments at 3-4; NYISO 

Comments at 4; PJM Comments at 4; PJM Power Providers Comments at 5-6; PJM 

Utilities Coalition Comments at 6; PSEG Companies Comments at 6-7; Potomac 

Economics Comments at 5; Western Power Trading Forum Comments at 6; Wisconsin 

Electric Comments at 4.

110 IRC Comments at 2; PJM Comments at 4; PSEG Companies Comments at 6-7. 
Docket No. RM16-5-000 - 28 -

of the offer caps instead of based on economic merit or reliability needs.111 NYISO states 

that materially different offer caps between regions that depend on the same natural gas 

supply could require out-of-market operator actions to avoid reliability issues when 

natural gas prices are high.112 MISO maintains that consistent offer caps across 

RTOs/ISOs will also establish consistent shortage pricing between neighboring 

RTOs/ISOs.113 

39. In contrast, APPA and NRECA and NCPA state that offer cap levels should be set 

according to the needs of each individual RTO/ISO.114 APPA and NRECA assert that the 

Commission should only consider raising the offer cap on a region-by-region basis where 

the evidence demonstrates a need for a higher offer cap.

115

 Direct Energy and PJM 

Utilities Coalition, respectively, state that different offer caps may be appropriate if the 

RTOs/ISOs use the same methodology to determine the offer caps or where the different 

offer cap levels represent true differences in cost.116

 

111 ISO-NE Comments at 7; NYISO Comments at 5. 

112 NYISO Comments at 4-5.

113 MISO Comments at 8. 

114 APPA and NRECA Comments at 29-30; NCPA Comments at 3.

115 APPA and NRECA Comments at 32.

116 Direct Energy Comments at 4; PJM Utilities Coalition Comments at 6.
Docket No. RM16-5-000 - 29 -

5. Other Considerations

40. CAISO and MISO note that the offer cap level impacts other market parameters 

that affect LMPs, such as penalty prices associated with violating thermal or operating 

constraints that are contained in the RTO/ISO software used to calculate LMPs. SCE 

explains that when CAISO relaxes a transmission constraint, it uses the offer cap to set 

the congestion price.117 CAISO states it would have to increase constraint penalty prices, 

currently set to levels above the offer cap, to ensure that the market operators would 

dispatch economic offers prior to relaxing transmission constraints.118 MISO notes that 

some market parameters may be intrinsically tied to the maximum LMP in the energy 

market, including transmission constraint demand curves, emergency or scarcity pricing 

regimes, and some pricing of ancillary services.119 

41. IRC and New York Transmission Owners state that changing the offer cap could 

affect natural gas markets.120 New York Transmission Owners argue that allowing higher 

offers to set the LMP might increase the price generators will pay for spot natural gas 

beyond competitive levels since there is no mitigation procedure to test whether resources 

 

117 SCE Comments at 2.

118 CAISO Comments at 5.

119 MISO Comments at 5.

120 IRC Comments at 3; New York Transmission Owners Comments at 5.
Docket No. RM16-5-000 - 30 -

paid too much for natural gas.121 IRC states that the Commission should focus on 

ensuring transparency and flexibility in natural gas markets to assist RTOs/ISOs with gas 

price verification and to ameliorate natural gas price spikes.122 

II. Need For Reform and Commission Proposal

42. In the following section, the Commission first explains the need to reform the 

current offer caps. The Commission next summarizes the alternative proposals that the 

Commission considered but declined to adopt. Finally, the Commission describes its 

proposal and the three requirements that underlie it. 

A. Need for Reform 

43. As stated above, five of the six Commission-jurisdictional RTOs/ISOs currently 

have a $1,000/MWh offer cap.123 As noted previously, PJM currently has a $2,000/MWh 

offer cap on cost-based incremental energy offers used for purposes of calculating 

LMPs.124 When the Commission first accepted these offer caps, the Commission did so, 

in many instances, as temporary measures until larger market reforms were 

 

121 New York Transmission Owners Comments at 5.

122 IRC Comments at 3. 

123 See supra P 10.

124 See supra P 17.
Docket No. RM16-5-000 - 31 -

implemented.125 The offer caps have persisted, and are now viewed as a component of 

the market power mitigation measures adopted by RTOs/ISOs.126 The Commission has 

reviewed the offer caps and preliminarily finds that the offer caps currently in effect in all 

RTOs/ISOs are unjust and unreasonable for several reasons. 

44. First, the offer cap can prevent a resource from recouping its short-run marginal 

costs. With the current $1,000/MWh offer cap, a resource whose short-run marginal cost 

exceeds $1,000/MWh may operate at a loss. For example, in January 2014, resources in 

PJM faced high natural gas prices that caused their short-run marginal costs to exceed the 

$1,000/MWh offer cap in place at the time.127 Similarly, MISO states that high natural 

gas prices in January and March 2014 caused some MISO resources to experience costs 

in excess of the $1,000/MWh offer cap.128

45. Second, the offer cap can impair price formation because it can result in LMPs 

that are suppressed below the marginal cost of production. An LMP that is less than the 

marginal cost of production may not be just and reasonable because it sends an inaccurate 

signal to load about the actual cost of producing the electricity, and to resources about the 

 

125 See, e.g., Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC 

¶ 61,163, at PP 380-381, order on reh’g, 109 FERC ¶ 61,157 (2004), order on 

clarification, 111 FERC ¶ 61,367 (2005); N.Y. Indep. Sys. Operator, Inc., 97 FERC 

¶ 61,095, at 61,496-97 (2001); ISO New England, Inc., 97 FERC ¶ 61,090, at 61,471.

126 See supra PP 23-26.

127 PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 2. 

128 MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 2.
Docket No. RM16-5-000 - 32 -

value of the next increment of supply. For example, if the marginal resource at a given 

location has a $1,100/MWh short-run marginal cost but faces a $1,000/MWh cap, that 

resource’s incremental energy offer will be constrained to $1,000/MWh, and as a result, 

the energy component of LMP will be $100/MWh below the marginal cost of production. 

In a properly functioning market, the LMP should accurately reflect the costs of serving 

load and both customers and resources will be aware of that cost through an accurate and 

transparent price signal.

46. Third, the offer cap may discourage resources from offering their supply to the 

RTO/ISO when their short-run marginal costs exceed the offer cap, even though market

participants may be willing to purchase that supply. For example, a resource may not be 

subject to a must-offer requirement, and thus be under no obligation to offer its supply to 

the energy market and therefore simply decide not to offer its supply to the market if its 

short-run marginal cost exceeds the offer cap. Both PJM and MISO state that an offer 

cap that prevents cost recovery can reduce the likelihood that resources with short-run 

marginal costs above the cap will offer their supply to the RTO/ISO.129 

47. Fourth and finally, if several resources have short-run marginal costs above 

$1,000/MWh, the $1,000/MWh offer cap requires those resources to submit incremental 

energy offers equal to $1,000/MWh, even if the resources face different costs. Under this 

scenario, the $1,000/MWh offer cap will prevent the RTO/ISO from observing the cost 

 

129 MISO Comments at 4; PJM Comments at 2.
Docket No. RM16-5-000 - 33 -

differences among these resources and the RTO/ISO will not be able to select the most 

efficient resources because the resources with costs above $1,000/MWh were not able to 

submit incremental energy offers consistent with their short-run marginal cost. For these 

reasons, the Commission preliminarily finds that the current offer caps result in rates that 

are unjust and unreasonable. In addition, these reasons illustrate that the current offer 

caps may not achieve the price formation goals discussed above. 

48. The Commission considered several alternatives to achieve the price formation 

goals. On balance, the Commission has preliminarily determined that the alternative that 

best achieves the price formation goals is to retain the existing $1,000/MWh offer cap 

except in circumstances when a resource has verifiable short-run marginal costs in excess 

of $1,000/MWh. The discussion at the technical workshop and subsequent comments 

received suggest that the $1,000/MWh offer cap is appropriate in most circumstances and 

serves as an appropriate backstop to the existing market power mitigation rules. 

However, recent experience also suggests that some resources may face short-run 

marginal costs greater than $1,000/MWh and, in such infrequent circumstances, the 

$1,000/MWh offer cap inappropriately limits those resources’ incremental energy offers 

and the resulting LMP. To the extent incremental energy offers can be verified, we 

believe a generic reform to allow offers and LMPs to exceed $1,000/MWh will enhance 

market efficiency and mitigate the potential for seams issues.

B. Alternative Offer Cap Proposals Discussed in Comments

49. This section briefly discusses why the Commission has not proposed the other 

alternative offer cap designs. The Commission is not proposing the alternative that uses 
Docket No. RM16-5-000 - 34 -

uplift payments to compensate resources with costs above the offer cap because, while 

uplift payments may ensure that a resource recoups its costs, such a proposal would not 

ensure that LMPs accurately reflect the marginal cost of production - a key goal of the 

price formation effort.130 

50. The Commission is not proposing a floating offer cap that would change with 

natural gas prices. This alternative proposal would be unduly preferential to natural gasfueled resources and discriminatory towards resources that do not use natural gas as fuel

because such a cap would only vary with the cost inputs of resources that use natural gas 

as fuel. As such, this alternative proposal could prevent a resource that does not use 

natural gas as a fuel to generate electricity from submitting a legitimate cost-based 

incremental energy offer if that offer is above the natural gas-based floating cap. 

Although natural gas fueled resources are currently the most likely resources to have 

short-run marginal costs above $1,000/MWh, this may not always be the case. 

Furthermore, setting the offer cap for all resources based on the price of natural gas 

would allow non-natural gas resources to submit offers above $1,000/MWh and below 

the natural-gas based offer cap with no cost basis for doing so, thereby potentially 

allowing them to exercise market power when natural gas prices rise but when these 

resources’ costs do not similarly rise. 

 

130 Price Formation in Energy and Ancillary Services Markets Operated by 

Regional Transmission Organizaztions and Independent System Operators, Notice 

Inviting Post-Technical Workshop Comments, Docket No. AD14-14-000, at 2 

(Jan. 16, 2015).
Docket No. RM16-5-000 - 35 -

51. Finally, the Commission is not proposing to raise the offer cap to a higher fixed 

level. A higher fixed offer cap could still limit a resource’s incremental energy offer 

below its short-run marginal cost and potentially suppress LMPs if that resource’s costs 

rose above the fixed offer cap. Additionally, like the floating offer cap, a higher fixed 

offer cap could raise market power concerns. 

C. Commission Proposal

52. To remedy any potentially unjust and unreasonable rates, the Commission 

proposes, pursuant to section 206 of the Federal Power Act (FPA),131 to revise its 

regulations to require that each RTO/ISO cap a resource’s incremental energy offer used 

for purposes of setting LMPs to the higher of $1,000/MWh or that resource’s verified 

cost-based incremental energy offer. Under the proposal, consistent with Order 

No. 719132 and as prescribed in the RTO/ISO tariffs, the Market Monitoring Unit or the 

RTO/ISO would verify the costs within such a cost-based incremental energy offer before 

that offer could be used to calculate LMPs. The proposed offer cap would apply to 

incremental energy offers in both the day-ahead and real-time energy markets. Under the 

proposal, each RTO/ISO must comply with the following three requirements: an offer 

cap structure, cost-based incremental energy offer verification, and resource neutrality, 

 

131 16 U.S.C. 824e(b).

132 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). 
Docket No. RM16-5-000 - 36 -

discussed in detail below. The Commission would not prescribe the precise manner in 

which the RTO/ISO must comply with the requirements in implementing the proposal. 

Each requirement, as established in the proposed regulations, is discussed in turn below. 

1. Offer Cap Structure

53. The first proposed requirement is as follows:

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. 

This requirement would ensure that a resource is given the opportunity to recoup its 

short-run marginal costs during intervals when those costs exceed $1,000/MWh because 

the resource could include such costs within its cost-based incremental energy offer. 

Additionally, this requirement would ensure that LMPs are no longer suppressed by the 

offer cap when marginal production costs exceed $1,000/MWh. This requirement would 

permit RTOs/ISOs to accept cost-based incremental energy offers above $1,000/MWh 

and use those offers in the market clearing process that calculates LMPs, but only when 

such offers are cost-based. Accordingly, all incremental energy offers above 

$1,000/MWh would be subject to market power mitigation and the attendant requirement 

that the offer be equal to the short-run marginal cost of the associated resource. 

Incremental energy offers at or below $1,000/MWh will continue to be subject to existing 

market power mitigation provisions. 

54. The Commission preliminarily finds that it is necessary to permit resources to 

submit cost-based incremental energy offers above $1,000/MWh, because as PJM and 
Docket No. RM16-5-000 - 37 -

MISO indicated in recent filings, the $1,000/MWh offer cap appears to have limited 

some resources’ incremental energy offers to a level below their short-run marginal cost 

during intervals with high natural gas prices.133 In addition, allowing all resources to 

offer consistent with short-run marginal cost will enhance an RTO/ISO’s ability to 

dispatch the lowest cost resources, particularly when multiple resources have short-run 

marginal cost greater than $1,000/MWh. Furthermore, allowing a resource to submit a 

cost-based incremental energy offer above $1,000/MWh would help ensure that resources 

with short-run marginal costs above $1,000/MWh have an incentive to offer electricity 

into the market during high price periods, when their electricity may be needed. 

Allowing LMPs to reflect a given RTO/ISO’s marginal cost of production could result in 

more economic power flows across seams because electricity would flow to where it is 

most valued. 

55. The Commission, however, does not propose to eliminate the $1,000/MWh offer 

cap entirely because the $1,000/MWh functions as a backstop for existing market power 

mitigation rules. Several market monitors at the Scarcity and Shortage Pricing, Offer 

Mitigation and Offer Caps Workshop held on October 28, 2014,134 as well as many 

 

133 PJM 2015/16 Offer Cap Order, 153 FERC ¶ 61,289, at PP 2-3 (2015); MISO,

Transmittal at 4, Docket No. ER16-248-000 (filed Nov. 2, 2015); MISO 2015/16 Offer 

Cap Order, 154 FERC ¶ 61,006. 

134 Scarcity and Shortage Pricing, Offer Mitigation and Offer Price Caps 

Workshop, Docket No. AD14-14-000, Tr. 205:11-19, 206:24-207:7, 210:14-211:8, 

212:12-213:3 (Oct. 28, 2015).
Docket No. RM16-5-000 - 38 -

commenters135 noted this function of the offer cap. For example, ISO-NE states that the 

$1,000/MWh offer cap still serves as a “fail-safe” mechanism to protect consumers in the 

unlikely event that the market is not competitive and market power mitigation fails to 

assure competitive supply offers.136 Additionally, ISO-NE, NYISO, and CAISO indicate 

that the $1,000/MWh offer cap is currently above the short-run marginal cost of resources 

in those RTOs/ISOs (i.e., the offer cap does not currently force a resource to submit an 

incremental energy offer below its short-run marginal cost).137 Under this proposal, 

verified cost-based incremental energy offers are not capped. The Commission recently 

approved tariff revisions in PJM that required all incremental energy offers above 

$1,000/MWh to be cost-based and also placed a $2,000/MWh hard cap on cost-based 

incremental energy offers used for purposes of calculating LMPs.

138

 The Commission 

seeks comment on whether such a hard cap 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.

 

135 See supra PP 25-26.

136 ISO-NE Comments at 4.

137 CAISO Comments at 3; ISO-NE Comments at 3; NYISO Comments at 4.

138 See supra n.36.
Docket No. RM16-5-000 - 39 -

2. Cost-Based Incremental Energy Offer Verification

56. The second proposed requirement is as follows:

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.

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. 

57. The Commission preliminarily finds that verification of the costs underlying costbased incremental energy offers above $1,000/MWh is warranted to reduce the potential 

exercise of market power. Without such verification, a resource may be able to submit an 

offer above $1,000/MWh not because its costs exceed $1,000/MWh, but rather because it 

recognizes that its energy is necessary to serve load and that it does not face competition 

from other resources. Using such an uncompetitive offer to calculate LMPs could result 

in unjust and unreasonable rates. 
Docket No. RM16-5-000 - 40 -

58. Under the proposal, the Market Monitoring Unit or the RTO/ISO would be 

required to verify that each cost-based incremental energy offer above $1,000/MWh is 

in fact cost-based. The Market Monitoring Unit or the RTO/ISO would verify that a 

resource’s cost-based offer is an accurate reflection of that resource’s short-run marginal 

cost. The Commission notes that for purposes of mitigation, the RTO/ISO tariffs use 

different terminology to describe the market power mitigation process, short-run 

marginal costs, and mitigated offers.139 The Market Monitoring Units in some 

RTOs/ISOs currently have processes whereby the Market Monitoring Unit or the market 

participant itself can derive cost-based incremental energy offers that are specific to a 

given resource.

140

 Additionally, ISO-NE and NYISO currently have processes in place 

where a resource can contact, before the close of the day-ahead or real-time markets, the 

Market Monitoring Unit to update the resource’s cost-based incremental energy offer

(e.g., due to a change in fuel prices).

141

 These updates are subject to verification by the 

Market Monitoring Unit.

 

139 See supra n.16. 

140 Id. 

141 ISO-NE, Markets and Services Tariff, Market Rule 1, § III.A.3.1 (43.0.0); 

NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, § 23.3.1.4.6.7 (11.0.0). 

Resources in SPP may also contact the Market Monitoring Unit during the operating day 

and request a mitigation exception pursuant to SPP, OATT, Sixth Revised Volume No. 1, 

Attachment AF, § 3.8 (7.0.0). Additionally, in MISO resources may consult with the 

Market Monitoring Unit to change reference levels as soon as practicable. MISO, FERC 

Electric Tariff, § 64.1.4.h (30.0.0). 
Docket No. RM16-5-000 - 41 -

59. Under the proposal, the Market Monitoring Unit or the RTO/ISO must verify the 

costs within a cost-based incremental energy offer above $1,000/MWh before that offer 

is used for purposes of calculating LMPs. The Commission seeks comment regarding the

Market Monitoring Unit’s or the RTO/ISO’s ability to timely verify the costs within 

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. The Commission seeks comment on whether the Market Monitoring Unit or 

RTO/ISO 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. For example, cost-based 

offers in PJM include a ten percent adder, which may account for such cost components. 

To the extent that RTOs/ISOs currently include an adder above cost in cost-based 

incremental energy offers, is such an adder appropriate for incremental energy offers 

above $1,000/MWh? The Commission also seeks comment on whether the Market 

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

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

cost-based incremental energy offer is an accurate reflection of a resource’s short-run 

marginal cost. 

60. Under this proposal, each RTO/ISO would be required to include in its tariff a 

process by which the Market Monitoring Unit or RTO/ISO verifies the costs included in 

cost-based incremental energy offers above $1,000/MWh. To create such a verification 

process, the Commission expects that the Market Monitoring Unit or RTO/ISO would 
Docket No. RM16-5-000 - 42 -

build on its existing mitigation processes for calculating or updating cost-based 

incremental energy offers. The Commission notes that the nature of before-the-fact and 

after-the-fact cost verification processes often differ. The Commission expects that a 

market participant that seeks to submit a cost-based incremental energy offer above 

$1,000/MWh must provide appropriate documentation to the Market Monitoring Unit or 

the RTO/ISO. The Market Monitoring Unit or RTO/ISO should then have a before-thefact verification process that would allow for timely cost verification such that an offer 

submitted in a reasonable period of time could be used for purposes of calculating LMPs.

As noted already, the Commission emphasizes that this before-the-fact verification

should build upon existing procedures. 

61. Currently, RTOs/ISOs use different processes to develop and update offers for 

mitigation purposes. Under this proposal, the Commission would not require RTOs/ISOs 

to adopt the same approach to implement the cost-based incremental energy offer 

verification requirement.

62. RTOs/ISOs also differ in how they define the components of cost-based 

incremental energy offers for purposes of mitigation.142 Each RTO/ISO has tariff 

provisions that set out the elements of a resource’s short-run marginal cost for purposes 

 

142 For example, CAISO and PJM mitigate resources to cost-based offers that 

include a ten percent adder, while the standard cost-based offers in MISO, ISO-NE, and 

NYISO do not include an adder above cost.
Docket No. RM16-5-000 - 43 -

of mitigation.143 The Commission expects each RTO/ISO to use the elements set forth in 

its tariff provisions for purposes of determining a resource’s cost-based incremental 

energy offer. Thus, the Commission is not proposing to define the elements of a shortrun marginal cost as part of this proceeding.

63. Given that the verification process for cost-based incremental energy offers is 

intended to build on an RTO/ISO’s existing mitigation processes, as proposed, 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 apply to internal resources 

alone. However, the Commission would consider RTO/ISO proposals to develop costbased incremental energy offers for external transactions in their respective compliance 

filings for any final rule in this proceeding.

144

 The Commission seeks comments on 

whether the offer cap proposal should apply to imports and whether a cost verification 

process for import transactions is feasible.

64. The Commission preliminarily finds that, as financial instruments, virtual 

transactions have no short-run marginal production costs and, thus, could not provide a 

cost-basis for a virtual transaction above $1,000/MWh. Accordingly, virtual transactions 

 

143 See supra n.16

144 Any proposal to develop cost-based incremental energy offers for external 

transactions could address external resources generically or address certain scheduling 

practices (e.g., dynamic or pseudo tie schedules). 
Docket No. RM16-5-000 - 44 -

in RTOs/ISOs which currently limit virtual transaction bid/offer caps to existing 

incremental energy offer caps, could not exceed $1,000/MWh under the proposal.145 

The Commission seeks comment on 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. 

Additionally, the Commission seeks comment on alternatives which would allow virtual 

increment offers and decrement bids to be submitted and cleared at prices above 

$1,000/MWh.146

65. The cost-based incremental energy offer verification requirement also ensures 

that a resource with short-run marginal costs above $1,000/MWh recoups its costs in the 

event that the Market Monitoring Unit or RTO/ISO cannot verify that resource’s costs 

prior to the market clearing process. The Commission emphasizes that RTOs/ISOs 

would be expected to adopt a verification process that allows timely submitted and 

appropriately documented cost-based incremental energy offers to be used to calculate 

LMPs; compensating resources through make-whole payments should be treated only as 

a backstop. Under this proposal, the RTO/ISO would adopt a procedure to include the 

 

145 To the extent they currently exist, this proposal would not affect existing 

RTO/ISO tariff provisions that permit virtual transactions to exceed $1,000/MWh.

146 The Commission found it just and reasonable for virtual increment offers and 

decrement bids in PJM to clear up to $2,700/MWh, equal to the newly established energy 

and reserve market aggregate price cap. PJM Interconnection, L.L.C., 139 FERC 

¶ 61,057, at PP 123-143 (2012).
Docket No. RM16-5-000 - 45 -

offer, modified as discussed below, in its market clearing process. Accordingly, if such 

an offer clears the energy market, that resource may be entitled to a make-whole payment 

if the Market Monitoring Unit or RTO/ISO can verify after-the-fact that the resource’s 

short-run marginal cost was above $1,000/MWh. The basis of the make-whole payment 

would be the difference between a given resource’s energy market revenues and that 

resource’s total offer costs, including the cost-based incremental energy offer.147

66. The Commission’s proposal would permit regional variation in the process for 

treating incremental energy offers above $1,000/MWh that the Market Monitoring Unit 

or RTO/ISO 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 and to mitigate that offer further to a level below $1,000/MWh pursuant to 

other applicable market power mitigation provisions. The Commission continues to find 

that regional variation is acceptable here because incremental energy offers are currently 

subject to the existing RTO/ISO mitigation procedures that vary across RTOs/ISOs to 

appropriately account for regional differences. Further, RTO/ISO mitigation procedures 

only affect resources within the RTO/ISO. However, as discussed below, the offer cap 

also affects inter-regional trading such that generic action is required to avoid 

exacerbating seams. 

 

147 Under this proposal, any make-whole payments associated with such an afterthe-fact cost verification would not be duplicative or overcompensate a resource for the 

costs included in its energy supply offer. 
Docket No. RM16-5-000 - 46 -

67. Existing Commission regulations, as described below, already create a framework 

that ensures cost-based incremental energy offers submitted as part of a supply offer are 

based on legitimate costs.

148

 In existing mitigation processes, a resource must submit 

accurate cost information to the market monitor. In submitting a cost-based incremental 

energy offer above $1,000/MWh, a resource that misrepresents its costs would be in 

violation of the Commission’s regulations requiring accurate statements. 

Section 35.41(b) of the Commission’s regulations requires market participants to provide 

“accurate and factual information and not submit false or misleading information, or omit 

material information, in any communication with the Commission, Commissionapproved market monitors . . . [or] Commission-approved independent system 

operators.”149 Additionally, a resource that intentionally misrepresents its costs could 

violate the Commission’s Anti-Manipulation Rule. That rule prohibits a market 

participant from intentionally making “any untrue statement of a material fact or to 

omit[ting] to state a material fact necessary in order to make the statements made, in the 

light of the circumstances under which they were made, not misleading.”150 Thus, any 

 

148 Several RTOs/ISOs also rely on procedures to temporarily strip resources of 

the opportunity to make fuel price related adjustments to their reference levels in the 

event after-the-fact verification processes fail to confirm the need for the reference level 

update. See ISO-NE, Transmission Markets and Services Tariff, Market Rule 1, 

§III.A.3.4(c) (43.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, 

§23.3.1.4.6.8 (11.0.0).

149 18 CFR 35.41(b) (2015).

150 18 CFR 1c.2(a)(2) (2015).
Docket No. RM16-5-000 - 47 -

resource that misrepresents its costs may be in violation of the Commission’s regulations, 

even if its offer does not clear the day-ahead or real-time energy market. 

68. Some commenters express concern that verification of cost-based incremental 

energy offers prior to the market clearing process may require RTOs/ISOs to re-run the 

market if the Market Monitoring Unit or RTO/ISO initially accepts a cost-based 

incremental energy offer above $1,000/MWh and subsequently determines through an 

after-the-fact review that the offer that established the LMP was not in fact cost-based.151 

The Commission preliminarily finds that the verification requirement in this proposal 

addresses this concern because cost-based incremental energy offers above $1,000/MWh 

should result in LMPs that are appropriate because they will accurately reflect the 

marginal cost of production. Accordingly, such LMPs will not require recalculation

after-the-fact. 

3. Resource Neutrality

69. The third proposed requirement is as follows:

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

energy offers in excess of $1,000/MWh. 

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. During the Polar Vortex, natural gas prices reached levels 

 

151 CAISO Comments at 6-7.
Docket No. RM16-5-000 - 48 -

that caused the short-run marginal cost of natural gas-fueled resources that purchased 

gas on the natural gas spot market to exceed $1,000/MWh. However, limiting the 

opportunity to submit cost-based incremental energy offers in excess of $1,000/MWh 

to a particular resource type, such as natural-gas fueled resources, would be unduly 

preferential to those resources.152 Even though natural gas resources are currently 

most likely to have cost-based incremental energy offers above $1,000/MWh, market 

conditions may change causing other resource types to have short-run marginal costs 

above $1,000/MWh. Accordingly, the Commission proposes that all resource types 

be eligible to submit a cost-based incremental energy offer above $1,000/MWh. The 

resource neutrality requirement is consistent with prior Commission orders related to 

the offer cap in PJM and MISO.153 

4. Seams Issues

70. The Commission proposes to make a generic change to the offer cap applicable to 

all RTOs/ISOs through a rulemaking to avoid exacerbating seams issues. Seams issues 

could arise if one RTO/ISO has an offer cap that materially differed from a neighboring 

RTO/ISO’s offer cap. For example, NYISO states that offer caps that are materially 

different in neighboring RTOs/ISOs that rely on the same natural gas market could 

 

152 PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 39.

153 See 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; PJM 2015/16 Offer Cap Order, 153 FERC 

¶ 61,289; MISO 2015/16 Offer Cap Order, 154 FERC ¶ 61,006.
Docket No. RM16-5-000 - 49 -

require out-of-market operator actions to avoid reliability concerns.154 ISO-NE and 

NYISO also note that different offer caps in neighboring RTOs/ISOs could result in 

flows that depend on the level of the two offer caps as opposed to economics or reliability 

needs.155 The Commission also has indicated in prior orders approving temporary 

waivers or tariff changes related to MISO and PJM’s respective offer caps that the 

Commission would address seams issues related to the offer cap beyond the winter of 

2014/15 in the price formation proceeding.156 Therefore, this proposal would revise the 

market rules in all RTOs/ISOs in a similar manner to ensure that market prices accurately 

reflect the marginal cost of production. 

71. Some commenters have expressed concern that different offer caps in neighboring 

markets could create seams issues. The Commission acknowledges that the instant 

proposal 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 

other neighboring markets due to different resources with different short-run marginal 

costs being on the margin. Nonetheless, the Commission believes these differences will 

not adversely affect seams because these differences would be driven by actual costs and 

not by offer caps artificially suppressing LMPs. Therefore, the associated differences in 

 

154 NYISO Comments at 4-5.

155 ISO-NE Comments at 7; NYISO Comments at 5.

156 See PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 42; MISO 2014/15 

Offer Cap Order, 150 FERC ¶ 61,083 at P 19.
Docket No. RM16-5-000 - 50 -

LMPs will encourage efficient interchange transactions. The Commission seeks 

comment on this preliminary finding and other seams issues related to this proposal.

5. Other Considerations

72. In several RTO/ISOs, factors affecting LMPs and other market outcomes depend 

on the offer cap. For example, CAISO’s shortage pricing and penalty factors that apply 

when transmission constraints are relaxed are based on the $1,000/MWh offer cap.157 

Such relationships may have to be revised because they may require that the value of the 

offer cap be known prior to the market clearing process. Under this proposal, the 

ultimate value of the offer cap may not be known in advance in periods when marginal 

production costs exceed $1,000/MWh. Accordingly, given this proposal, RTOs/ISOs 

may wish to revise certain market features that relate to or are affected by the offer cap. 

RTOs/ISOs and their stakeholders may also wish to consider additional tariff revisions, 

such as changes to scarcity or shortage pricing, raising or removing caps on pricesensitive demand bids, and other means by which load can express its willingness to pay 

for electricity. Although they are not required to do so, the Commission would consider 

other market design changes, such as changes to scarcity or shortage pricing or other 

penalty prices, associated with adopting this proposal in the compliance filing.

 

157 CAISO Comments at 8.
Docket No. RM16-5-000 - 51 -

6. Comments Sought on this Proposal

73. The Commission seeks comment on its proposal as described herein. Specifically, 

the Commission seeks comment on the following items: (1) whether a hard cap on costbased 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 to timely verify the costs within 

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 that are difficult to 

quantify, such as certain opportunity costs, are accurately reflected in a resource’s costbased incremental energy offer and 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; (4) whether the Market 

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

require revisions or corrections to a cost-based incremental energy offer to ensure that a 

resource’s cost-based incremental energy offer is an accurate reflection of that 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, create market inefficiencies, or have other undesirable 

consequences, and whether alternatives exist which would allow virtual increment offers 
Docket No. RM16-5-000 - 52 -

and decrement bids to be submitted and cleared at prices above $1,000/MWh; and 

(7) the impact the proposal would have on seams. Comments must be submitted 

within sixty (60) days of publication of this NOPR in the Federal Register.

III. Compliance

74. The Commission proposes to require that each RTO/ISO submit a compliance 

filing no later than four months from the effective date of the final rule in this proceeding 

to demonstrate that it meets the proposed requirements set forth in the final rule. The 

Commission will accept RTO/ISO proposals that satisfy the three requirements described 

above and notes that proposals may vary regionally based on the existing RTO/ISO tariff 

provisions that are used to develop cost-based incremental energy offers and to 

implement market power mitigation provisions that are to be used as a basis for 

implementing this proposal. As noted previously, the Commission is also willing to 

consider proposed revisions to other market design features that may require revision in 

light of this proposal, such as changes to scarcity or shortage pricing or other market 

parameters. 

75. To the extent that any RTO/ISO believes that it already complies with the reforms 

adopted in a final rule in this proceeding, the RTO/ISO would be required to demonstrate, 

in the compliance filing, how it complies.
Docket No. RM16-5-000 - 53 -

IV. Information Collection Statement 

76. The Paperwork Reduction Act (PRA)158 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,159 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. 

77. The reforms proposed in this NOPR would amend the Commission’s regulations 

to improve the operation of organized wholesale electric power markets operated by 

RTOs/ISOs. The Commission proposes to require that each RTO/ISO cap a resource’s 

incremental energy offer used for purposes of calculating LMPs in energy markets to the

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

by the Market Monitoring Unit or the RTO/ISO. The reforms proposed in this NOPR 

would require one-time filings of tariffs with the Commission and potential software 

upgrades to implement the reforms proposed in this NOPR. The Commission anticipates 

 

158 44 U.S.C. 3501-3520.

159 5 CFR 1320 (2015).
Docket No. RM16-5-000 - 54 -

the reforms proposed in this NOPR, 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 proposed in this NOPR, they could 

demonstrate their compliance in the compliance filing required four months after the 

effective date of the 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.160 

78. While the Commission expects the adoption of the reforms proposed in this 

NOPR to provide significant benefits, the Commission understands implementation can 

be a complex endeavor. The Commission solicits 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 seeks detailed comments on the potential cost and time necessary to 

implement aspects of the reforms proposed in this 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. 

 

160 44 U.S.C. 3507(d).
Docket No. RM16-5-000 - 55 -

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.161

 

161 The RTOs and ISOs (CAISO, ISO-NE, MISO, NYISO, PJM, and SPP) are 

required to comply with the reforms proposed in this NOPR. 
Docket No. RM16-5-000 - 56 -

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.

162 Software or hardware upgrades may not be required. FERC-516, as 

modified by NOPR 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.; 

$36,000163 3,000 hrs.; 

$216,000 $36,000

Cost to Comply: The Commission has projected the total cost of compliance, all 

 

162 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. 

163 The estimated hourly cost (salary plus benefits) provided in this section are 

based on the salary figures for May 2014 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 March 2015 (available at 

http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates for salary plus 

benefits are:

 Legal (code 23-0000), $129.87

 Computer and mathematical (code 15-0000), $58.25

 Information systems manager (code 11-3021), $94.55

 IT security analyst (code 15-1122), $63.55

 Auditing and accounting (code 13-2011), $51.11

 Information and record clerk (code 43-4199), $37.50

 Electrical Engineer (code 17-2071), $66.45

 Economist (code 19-3011), $73.04

 Management (code 11-0000), $78.04

The average hourly cost (salary plus benefits), weighting all of these skill sets evenly, is 

$72.48. The Commission rounds it to $72 per hour. 
Docket No. RM16-5-000 - 57 -

within four months of a Final Rule plus initial implementation, to be $216,000. After 

Year 1, the reforms proposed in this NOPR, once implemented, would not significantly 

change existing burdens on an ongoing basis. 

The Commission notes that these estimates do not include costs for software or hardware. 

Software or hardware upgrades may not be required. 

Title: FERC-516, Electric Rate Schedules and Tariff Filings.

Action: Proposed revisions to an information collection.

OMB Control No. 1902-0096

Respondents for this Rulemaking: RTOs/ISOs.

Frequency of Information: One-time during.

Necessity of Information: The Federal Energy Regulatory Commission proposes this 

rule to improve competitive wholesale electric markets in the RTO/ISO regions. 

Internal Review: The Commission has reviewed the proposed 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.

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

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 
Docket No. RM16-5-000 - 58 -

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-516 and OMB Control No. 1902-0096.

V. Regulatory Flexibility Act Certification 

80. The Regulatory Flexibility Act of 1980 (RFA)164 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.

81. 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 $36,000, 

all in Year 1. This one-time cost of filing and implementing these changes is not 

 

164 5 U.S.C. 601-12.
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significant.165 Additionally, the RTOs/ISOs are not small entities, as defined by the 

RFA.166 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, the 

Commission certifies that the reforms proposed in this NOPR would not have a 

significant economic impact on a substantial number of small entities. The Commission 

does not expect other entities to incur compliance costs as a result of the reforms 

proposed in this NOPR, but seeks detailed comments on whether other entities, such as 

load-serving entities, would incur costs as a result of the reforms proposed in this NOPR.

 

165 This estimate does not include costs for software or increased time spent 

validating cost-based incremental energy offers, for which the Commission requests 

comment. 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.

166 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. The 

Small Business Administrations’ regulations at 13 CFR 121.201 define the threshold for 

a small Electric Bulk Power Transmission and Control entity (NAICS code 221121) to be 

500 employees. See 5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 

15 U.S.C. 632.
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VI. Environmental Analysis

82. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.167 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this NOPR 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 FPA 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.168

VII. Comment Procedures

83. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [60 days after 

publication in the FEDERAL REGISTER]. Comments must refer to Docket 

No. RM16-5-000, and must include the commenter’s name, the organization they 

represent, if applicable, and their address.

 

167 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).

168 18 CFR 380.4(a)(15) (2015). 
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84. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing.

85. Commenters that are not able to file comments electronically must send an 

original of their comments to: Federal Energy Regulatory Commission, Secretary of the 

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

86. All comments will be placed in the Commission’s public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters.

VIII. Document Availability

87. 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.

88. 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 
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Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number of this document, excluding the last three 

digits, in the docket number field.

89. 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.

List of subjects in 18 CFR Part 35 

Electric power rates

Electric utilities

Non-discriminatory open access transmission tariffs

By direction of the Commission.

Nathaniel J. Davis, Sr.,

Deputy Secretary.
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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) Incremental energy offer caps. 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. 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 
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be eligible for a make-whole payment if that resource clears the energy market and the 

resource’s costs are verified after-the-fact. All resources, regardless of type, are eligible 

to submit cost-based incremental energy offers in excess of $1,000/MWh. 

 
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APPENDIX A: List of Short Names/Acronyms of Commenters

Short Name/Acronym Commenter

APPA and NRECA

American Public Power Association 

and National Rural Electric 

Cooperative Association

ANGA America's Natural Gas Alliance

Brookfield

Brookfield Renewable Energy 

Marketing LP

California State Water Project

California Department of Water 

Resources State Water Project

CAISO

California Independent System 

Operator Corporation

Calpine Calpine Corporation

Direct Energy

Direct Energy Business Marketing, 

LLC, Direct Energy Business, LLC 

and affiliated companies

EEI Edison Electric Institute

EPSA Electric Power Supply Association

ELCON

Electricity Consumers Resource 

Council

Entergy Nuclear Power Marketing

Entergy Nuclear Power Marketing, 

LLC

Exelon Exelon Corporation

GDF SUEZ GDF SUEZ North America, Inc.

ISO-NE ISO New England, Inc.

IRC ISO/RTO Council 

MISO

Midcontinent Independent System 

Operator, Inc.

NYISO

New York Independent System 

Operator, Inc.
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New York Transmission Owners

New York Transmission Owners 

(Central Hudson Gas & Electric 

Corporation, Consolidated Edison 

Company of New York, Inc., Power 

Supply of Long Island, New York 

Power Authority, New York State 

Electric & Gas Corporation, Niagara 

Mohawk Power Corporation d/b/a 

National Grid, Orange and Rockland 

Utilities, Inc., and Rochester Gas and 

Electric Corporation)

NCPA Northern California Power Agency

OMS Organization of MISO States

PG&E Pacific Gas and Electric Company

PJM PJM Interconnection, L.L.C.

PJM Power Providers PJM Power Providers Group

PJM Utilities Coalition

PJM Utilities Coalition (American 

Electric Power Service Corporation, 

the Dayton Power and Light Company, 

FirstEnergy Service Company, 

Buckeye Power, Inc., and East 

Kentucky Power Cooperative)

Potomac Economics Potomac Economics, Ltd.

Powerex Powerex Corp.

PSEG Companies

PSEG Companies (Public Service 

Electric and Gas Company, PSEG 

Power LLC and PSEG Energy 

Resources & Trade LLC)

SCE Southern California Edison Company

SPP Southwest Power Pool, Inc.

TAPS

Transmission Access Policy Study 

Group

Western Power Trading Forum Western Power Trading Forum

Wisconsin Electric Wisconsin Electric Power Company
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Xcel Xcel Energy Services Inc.