Federal Register / Vol. 81, No. 23 / Thursday, February 4, 2016 / Proposed Rules 5951 

Paragraph 5000 Class D Airspace. 

AEA MD D Hagerstown, MD [Amended] 

Hagerstown Regional Airport-Richard A. 

Henson Field, MD 

(Lat. 39°42′31′′ N., long. 77°43′35′′ W.) 

That airspace extending upward from the 

surface to and including 3,200 feet MSL 

within a 4.1-mile radius of Hagerstown 

Regional Airport-Richard A. Henson Field. 

This Class D airspace area is effective during 

the specific dates and times established in 

advance by Notice to Airmen. The effective 

date and time will thereafter be continuously 

published in the Airport/Facility Directory. 

Paragraph 6002 Class E Surface Area 

Airspace. 

* * * * * 

AEA MD E2 Hagerstown, MD [Amended] 

Hagerstown Regional Airport-Richard A. 

Henson Field, MD 

(Lat. 39°42′31′′ N., long.77°43′35′′ W.) 

That airspace extending upward from the 

surface to and including 3,200 feet MSL 

within a 4.1-mile radius of Hagerstown 

Regional Airport-Richard A. Henson Field. 

This Class E2 airspace area is effective during 

the specific dates and times when the Class 

D airspace area, as published in the Airport/ 

Facility Directory, is not in effect. 

Paragraph 6004 Class E Airspace 

Designated as an Extension to a Class D 

Surface Area. 

* * * * * 

AEA MD E4 Hagerstown, MD [Amended] 

Hagerstown Regional Airport-Richard A. 

Henson Field, MD 

(Lat. 39°42′31′′ N., long. 77°43′35′′ W.) 

Hagerstown VOR 

(Lat. 39°41′52′′ N., long. 77°51′21′′ W.) 

Hagerstown Regional Airport-Richard A. 

Henson Field ILS Runway 27 Localizer 

(Lat. 39°42′22′′ N., long. 77°44′41′′ W.) 

That airspace extending upward from the 

surface within 2.7 miles each side of the 

Hagerstown VOR 237° radial and 057° radial 

extending from 7.4 miles southwest of the 

VOR to 1.8 miles northeast of the VOR and 

within 2.7 miles each side of the Hagerstown 

VOR 082° radial extending from the 4.1-mile 

radius of Hagerstown Regional AirportRichard A. Henson Field to the VOR, and 

within 4 miles each side of the Hagerstown 

Regional Airport-Richard A. Henson Field 

ILS Runway 27 localizer course extending 

from the localizer to 11.8 miles east of the 

localizer, excluding that portion within 

Prohibited Area P–40. 

Paragraph 6005 Class E Airspace Areas 

Extending Upward From 700 Feet or More 

Above the Surface of the Earth. 

* * * * * 

AEA MD E5 Hagerstown, MD [Amended] 

Hagerstown Regional Airport-Richard A. 

Henson Field, MD 

(Lat. 39°42′31′′ N., long. 77°43′35′′ W.) 

Hagerstown VOR 

(Lat. 39°41′52′′ N., long. 77°51′21′′ W.) 

St. Thomas VORTAC 

(Lat. 39°56′00′′ N., long. 77°57′03′′ W.) 

Hagerstown Regional Airport-Richard A. 

Henson Field ILS Runway 27 Localizer 

(Lat. 39°42′22′′ N., long. 77°44′41′′ W.) 

That airspace extending upward from 700 

feet above the surface within a 6.6-mile 

radius of the Hagerstown Regional AirportRichard A. Henson Field and within 3.1 

miles each side of the Hagerstown VOR 237° 

radial and 057° radial extending from 9.6 

miles southwest of the VOR to 2.7 miles 

northeast of the VOR and within 4.4 miles 

each side of the Hagerstown Regional 

Airport-Richard A. Henson Field ILS Runway 

27 localizer course extending from the 

localizer to 12.6 miles east of the localizer 

and within 4.4 miles each side of the St. 

Thomas VORTAC 141° radial extending from 

the 6.6-mile radius to the St. Thomas 

VORTAC, excluding that portion within 

Prohibited Area P–40. 

Issued in College Park, Georgia, on January 

27, 2016. 

Ryan W. Almasy, 

Acting Manager, Operations Support Group, 

Eastern Service Center, Air Traffic 

Organization. 

[FR Doc. 2016–02023 Filed 2–3–16; 8:45 am] 

BILLING CODE 4910–13–P 

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 

AGENCY: Federal Energy Regulatory 

Commission, Energy. 

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 costbased incremental energy offer. 

DATES: Comments are due April 4, 2016. 

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-to-PDF format and 

not in a scanned format. 

• Mail/Hand Delivery: Those unable 

to file electronically may mail or handdeliver 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. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph Nos. 

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. 


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1The incremental energy offer is the portion of a 

resource’s energy supply offer that varies with the 

output of the generator. 

2The 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. 

3Resources 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 dayahead or real-time 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. 

4Wholesale 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). 

5Pursuant 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). 

6Price 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. 

8See Supplemental Notice of Workshop on Price 

Formation: Scarcity and Shortage Pricing, Offer 

Paragraph Nos. 

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. 

VI. Environmental Analysis ......................................................................................................................................................... 82. 

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

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

Appendix A: .................................................................................................................................................................................

List of Short Names/Acronyms of Commenters.

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 offer 1 to 

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 cap 2 on 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 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 short-run 

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 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. 

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


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Mitigation, and Offer Caps in RTO and ISO Markets, 

Docket No. AD14–14–000 (Oct. 10, 2014). 

9Price Formation Notice at 2. 

10See 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. 

11RTOs/ISOs typically restrict incremental 

energy supply curves to ten price and quantity pairs 

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

12See 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/energyprimer.pdf. 

13See, 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). 

14PJM 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. 

15See 18 CFR 35.28(g)(3)(iii)(B)–(D) (2015). 

16The 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.’’ 

17There are exceptions to this eligibility, for 

instance, when a resource is committed outside of 

the market clearing process. 

18See supra n.16. 

19PJM 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. 

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. 

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. 

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, noload 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 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-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’ 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 


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20See Docket Nos. OA97–261–000 and ER97– 

1082–000 (Apr. 1, 1997); Pennsylvania-New JerseyMaryland Interconnection, 81 FERC ¶ 61,257 

(1997). 

21Scarcity and Shortage Pricing, Offer Mitigation 

and Offer Caps Workshop, Docket No. AD14–14– 

000, Tr. 209:18–22 (Oct. 28, 2014). 

22PJM Comments at 2. All comments cited herein 

were submitted in Docket No. AD14–14–000 on or 

about March 6, 2015. 

23See, 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. 

24PJM 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. 

26PJM Interconnection, L.L.C., 146 FERC 

¶ 61,078, at PP 3–4 (2014). 

27N.Y. Indep. Sys. Operator, Inc., 146 FERC 

¶ 61,061, at PP 2–4 (2014). 

28 Id. P 24. 

29PJM 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). 

31PJM 2014/15 Offer Cap Order, 150 FERC 

¶ 61,020. 

32MISO 2014/15 Offer Cap Order, 150 FERC 

¶ 61,083. 

33See 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. 

34PJM, Proposed Tariff Revisions, Docket No. 

ER16–76–000 (filed Oct. 14, 2015). 

35MISO, Request for Waiver, Docket No. ER16– 

248–000 (filed Nov. 2, 2015). 

36PJM 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). 

39Price 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. 

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

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 cost-based 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 costbased offers in 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 PJM 29 and MISO 30 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 $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, PJM 34

and MISO 35 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 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 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. 


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40ANGA 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. 

41EPSA Comments at 21–24; Exelon Comments at 

10–12; OMS Comments at 2; PJM Comments at 2– 

3; PJM Power Providers Comments at 2. 

42OMS Comments at 2. 

43PJM Utilities Coalition Comments at 3–4; 

Western Power Trading Forum Comments at 5. 

44 Direct Energy Comments at 2; EPSA Comments 

at 21. 

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

46ANGA 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. 

47EPSA Comments at 21–22. 

48MISO Comments at 4. 

49 Id.; PJM Comments at 2. 

50SPP Comments at 1; Western Power Trading 

Forum Comments at 5–6. 

51APPA and NRECA Comments at 30; CAISO 

Comments at 3; ELCON Comments at 6. 

52CAISO Comments at 3; ISO–NE Comments at 

3 & n.2; NYISO Comments at 4. 

53CAISO Comments at 3. 

54NCPA 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. 

55NCPA Comments at 2–3; SCE Comments at 2. 

56SCE 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. 

57APPA and NRECA Comments at 32. 

58Scarcity 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. 

61 Id. at 211:25–212:14. 

62ANGA 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. 

63Wisconsin Electric Comments at 2. 

64 Direct Energy Comments at 2. 

65 GDF SUEZ Comments at 3. 

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. 

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 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 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, ISO–NE, 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 $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, 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

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 


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69OMS Comments at 2. 

70Potomac Economics Comments at 3–4. 

71ELCON Comments at 6; TAPS Comments at 10– 

11. 

72TAPS 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)). 

73TAPS 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)). 

74APPA and NRECA Comments at 31–32. 

75 Id. at 29–31; California State Water Project 

Comments at 2–3; New York Transmission Owners 

Comments at 2–3. 

76APPA and NRECA Comments at 31. 

77 Id. at 31. 

78 Id. at 31–32. 

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

80Calpine Comments at 4–6. 

81 Id. at 21. 

82Powerex Comments at 30. 

83SPP Comments at 1. 

84OMS Comments at 3. 

85 ISO–NE Comments at 4–6; MISO Comments at 

5–7. 

86 ISO–NE Comments at 6. 

87MISO Comments at 5–6. 

88 ISO–NE Comments at 6–7. 

89ANGA Comments at 3. 

90Exelon Comments at 12. 

91 ISO–NE Comments at 6. 

92 Id. at 3–4. 

93MISO Comments at 4–5. 

94 Id. at 5. 

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 

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 afterthe-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; (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-the-fact, 

with costs in excess of the offer cap 

recovered through uplift.78 SCE and 

PG&E 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-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 marketbased 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 costbased offers should be allowed to 

exceed the market-based offer cap.90

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, 


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95TAPS Comments at 13. 

96APPA 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. 

99PJM Comments at 2–3. 

100 Id. at 4. 

101PJM Power Providers Comments at 4; PSEG 

Companies Comments at 6. 

102APPA and NRECA Comments at 30–32. 

103TAPS Comments at 13–14. 

104APPA and NRECA Comments at 32; CAISO 

Comments at 6–7, NCPA Comments at 2. 

105CAISO Comments at 4–6. 

106 Id. at 6. 

107TAPS Comments at 14–15. 

108 Direct Energy Comments at 3–4. 

109Brookfield 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. 

111 ISO–NE Comments at 7; NYISO Comments at 

5. 

112NYISO Comments at 4–5. 

113MISO Comments at 8. 

114APPA and NRECA Comments at 29–30; NCPA 

Comments at 3. 

115APPA and NRECA Comments at 32. 

116 Direct Energy Comments at 4; PJM Utilities 

Coalition Comments at 6. 

117SCE Comments at 2. 

118CAISO Comments at 5. 

119MISO Comments at 5. 

120 IRC Comments at 3; New York Transmission 

Owners Comments at 5. 

121New York Transmission Owners Comments at 

5. 

occur.95 APPA and NRECA argue that it 

is not necessary to increase the offer cap 

broadly because APPA and NRECA say 

there is 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 costbased incremental energy offers should 

not be capped.98 PJM states that costbased 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 cost-based 

incremental energy offer from previous 

time periods.100 PJM Power Providers 

and PSEG Companies assert that costbased 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 

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 costjustified.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-thefact 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 

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 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

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 paid too much for natural 

gas.121 IRC states that the Commission 

should focus on ensuring transparency 

and flexibility in natural gas markets to 


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122 IRC Comments at 3. 

123See supra P 10. 

124See supra P 17. 

125See, 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. 

126See supra PP 23–26. 

127PJM 2014/15 Offer Cap Order, 150 FERC 

¶ 61,020 at P 2. 

128MISO 2014/15 Offer Cap Order, 150 FERC 

¶ 61,083 at P 2. 129MISO Comments at 4; PJM Comments at 2. 

130Price 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 (Jan. 16, 2015). 

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 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 shortrun 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 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 

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 shortrun 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 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 gas-fueled 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 


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

132Wholesale 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). 

133PJM 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. 

134Scarcity 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). 

135See supra PP 25–26. 

136 ISO–NE Comments at 4. 

137CAISO Comments at 3; ISO–NE Comments at 

3; NYISO Comments at 4. 

138See supra n.36. 

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. 

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 shortrun 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. 

719 132 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, 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 costbased 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 costbased. 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 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 costbased 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 

commenters 135 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 shortrun 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 shortrun 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. 

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 make-whole payment if 

that resource clears the energy market 

and the resource’s costs are verified 

after-the-fact. 


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139See 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). 

142For 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. 

143See supra n.16 

144Any 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). 

145To the extent they currently exist, this 

proposal would not affect existing RTO/ISO tariff 

provisions that permit virtual transactions to exceed 

$1,000/MWh. 

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 cost-based 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. 

58. Under the proposal, the Market 

Monitoring Unit or the RTO/ISO would 

be required to verify that each costbased 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, shortrun 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. 

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 dayahead 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 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 costbased 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-the-fact 

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 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 short-run 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 cost-based 

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 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 


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146The 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). 

147Under this proposal, any make-whole 

payments associated with such an after-the-fact cost 

verification would not be duplicative or 

overcompensate a resource for the costs included in 

its energy supply offer. 

148Several 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). 

151CAISO Comments at 6–7. 

152PJM 2014/15 Offer Cap Order, 150 FERC ¶ 

61,020 at P 39. 

153See 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. 

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 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. 

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 costbased 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, 

Commission-approved market monitors 

. . . [or] Commission-approved 

independent system operators.’’ 149

Additionally, a resource that 

intentionally misrepresents its costs 

could violate the Commission’s AntiManipulation 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 

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 

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 


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154NYISO Comments at 4–5. 

155 ISO–NE Comments at 7; NYISO Comments at 

5. 

156See 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. 

157CAISO Comments at 8. 

158 44 U.S.C. 3501–3520. 

159 5 CFR 1320 (2015). 

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 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 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. 

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 cost-based 

incremental energy offers used for 

purposes of calculating LMPs should be 

included in any final rule in this 

proceeding and, if so, whether the hard 

cap should equal $2,000/MWh or 

another value; (2) the ability 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 cost-based 

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 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 costbased 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. 

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 


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Federal Register / Vol. 81, No. 23 / Thursday, February 4, 2016 / Proposed Rules 5963 

160 44 U.S.C. 3507(d). 161The RTOs and ISOs (CAISO, ISO–NE., MISO, 

NYISO, PJM, and SPP) are required to comply with 

the reforms proposed in this NOPR. 

162The 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. 

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 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. 

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

SOFTWARE OR HARDWARE UPGRADES MAY NOT BE REQUIRED

[FERC–516, as modified by NOPR in Docket RM16–5–000] 

Number of 

respondents 

Annual 

number of 

responses per 

respondent 

Total number 

of responses 

Average burden (hours) 

& cost per response 

Total annual burden 

hours & total annual cost 

Cost per 

respondent 

($) 

(1) (2) (1) × (2) = (3) (4) (3) × (4) = (5) (5) ÷ (1) 

One-Time Tariff Filings (Year 1).6 1 6 500 hrs.; $36,000 163 ..... 3,000 hrs.; $216,000 ...... $36,000 

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

Cost to Comply: The Commission has 

projected the total cost of compliance, 

all within four months of a Final Rule 

plus initial implementation, to be 

$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], 

email: 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 

email address: oira_submission@

omb.eop.gov. Comments submitted to 

OMB should include FERC–516 and 

OMB Control No. 1902–0096. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
5964 Federal Register / Vol. 81, No. 23 / Thursday, February 4, 2016 / Proposed Rules 

163The 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. 

164 5 U.S.C. 601–12. 

165This estimate does not include costs for 

software or increased time spent validating costbased incremental energy offers, for which the 

Commission requests comment. As stated above, 

the Commission expects that the validation of costbased 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. 

166The 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. 

167Regulations 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). 

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 

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. 

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 April 4, 2016. 

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. 

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 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 Web site 

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. Email 

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. 

Issued: January 21, 2016. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

In consideration of the foregoing, the 

Commission proposes to amend part 35, 

chapter I, title 18, Code of Federal 

Regulations, as follows: 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 81, No. 23 / Thursday, February 4, 2016 / Proposed Rules 5965 

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 adding paragraph 

(g)(9) to read as follows: 

§ 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 be eligible for a makewhole 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. 

The following appendix will not 

appear in the Code of Federal 

Regulations. 

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. 

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. 

Xcel ........................................................................................................... Xcel Energy Services Inc. 

[FR Doc. 2016–01813 Filed 2–3–16; 8:45 am] 

BILLING CODE 6717–01–P 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS