Document ID: FERC-2016-0177-0001
Agency: ferc
Document Type: Proposed Rule
Title: Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators
Posted Date: 2016-02-04T05:00Z

[Federal Register Volume 81, Number 23 (Thursday, February 4, 2016)]
[Proposed Rules]
[Pages 5951-5965]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-01813]

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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.

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SUMMARY: The Federal Energy Regulatory Commission is proposing to 
revise its regulations to require that each regional transmission 
organization (RTO) and independent system operator (ISO) cap each 
resource's incremental energy offer to the higher of $1,000/MWh or that 
resource's verified cost-based incremental energy offer.

DATES:  Comments are due 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 hand-deliver comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT: 
Emma Nicholson (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-8846, emma.nicholson@ferc.gov.
Pamela Quinlan (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-6179, pamela.quinlan@ferc.gov.
Anne Marie Hirschberger (Legal Information), Office of the General 
Counsel, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-8387, annemarie.hirschberger@ferc.gov.

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                         Paragraph Nos.
 
I. Background........................................                 6.
    A. Offer Caps and Market Power Mitigation in RTOs/                8.
     ISOs............................................
    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                     23.
         Mitigation..................................
        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.

[[Page 5952]]

 
    B. Alternative Offer Cap Proposals Discussed in                  49.
     Comments........................................
    C. Commission Proposal...........................                52.
        1. Offer Cap Structure.......................                53.
        2. Cost-Based Incremental Energy Offer                       56.
         Verification................................
        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).
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    \1\ The incremental energy offer is the portion of a resource's 
energy supply offer that varies with the output of the generator.
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    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.
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    \2\ The offer cap for purposes of this NOPR refers to the $/MWh 
limit on day-ahead and real-time incremental energy offers, and not 
any limits or penalty rates that may apply in the capacity or 
ancillary services markets.
    \3\ Resources that are subject to must-offer requirements, such 
as resources with a capacity supply obligation, are required to 
submit a supply offer to the energy market. Many resources are 
subject to must-offer requirements in either the day-ahead or 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.
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    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.
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    \4\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at PP 370-375 
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 
31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ] 61,252 
(2009). See also 18 CFR 35.28(g)(3)(iii)(B) (2015).
    \5\ Pursuant to 18 CFR 35.28(g)(3)(iii)(B), either the internal 
or external market monitor can ``provide the inputs required to 
conduct prospective mitigation . . . including, but not limited to 
reference levels, identification of system constraints, and cost 
calculations.'' 18 CFR 35.28(g)(3)(iii)(B) (2015). However, 
prospective mitigation may only be carried out by an internal market 
monitor if the RTO/ISO has a hybrid Market Monitoring Unit 
structure. 18 CFR 35.28(g)(3)(iii)(D) (2015).
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    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\

[[Page 5953]]

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.
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    \6\ Price Formation in Energy and Ancillary Services Markets 
Operated by Regional Transmission Organizations and Independent 
System Operators, Notice, Docket No. AD14-14-000 (June 19, 2014) 
(Price Formation Notice).
    \7\ Id. at 1, 3-4.
    \8\ See Supplemental Notice of Workshop on Price Formation: 
Scarcity and Shortage Pricing, Offer Mitigation, and Offer Caps in 
RTO and ISO Markets, Docket No. AD14-14-000 (Oct. 10, 2014).
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    7. Two of the Commission's goals in the price formation proceeding 
are relevant here. First, clearing prices in the energy and ancillary 
services markets should ideally ``reflect the true marginal cost of 
production, taking into account all physical system constraints.'' \9\ 
Second, LMPs should ``ensure that all suppliers have an opportunity to 
recover their costs.'' \10\ Establishing LMPs that accurately reflect 
the marginal cost of production is a central goal of the price 
formation effort. This goal is important because LMPs are an effective 
way to communicate information to market participants about the cost of 
providing the next unit of energy. In the short-run, accurate price 
signals from LMPs are particularly important during high price periods 
because they provide a signal to customers to reduce consumption and a 
signal to suppliers to increase production or to offer new supplies to 
the market. In the long-run, accurate price signals from LMPs are 
important because they inform investment decisions. It is also 
important that RTOs/ISOs give resources the opportunity to recover 
their costs because failing to do so may discourage resources from 
participating in RTO/ISO energy markets. Adequate investment in 
resources and participation of resources in RTO/ISO energy markets are 
necessary to ensure economic and reliable energy for consumers.
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    \9\ Price Formation Notice at 2.
    \10\ See Price Formation in Energy and Ancillary Servs. Mkts. 
Operated by Reg'l Transmission Orgs. & Indep. Sys. Operators, 153 
FERC ] 61,221, at P 2 (2015); see also Price Formation Notice at 2.
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A. Offer Caps and Market Power Mitigation in RTOs/ISOs

    8. Supply offers in day-ahead and real-time energy markets consist 
of both physical components and financial components. The physical 
components of a supply offer describe the resource's physical operating 
parameters, such as its minimum and maximum operating limits in a given 
day-ahead or real-time interval, and are denominated in MW, MWh, time, 
or some combination thereof. The financial components of a supply offer 
are denominated in dollars (e.g., $/start and $/MWh) and represent the 
costs underlying a resource's offer to supply electricity in a given 
interval. The key financial components of a supply offer are the start-
up cost, no-load cost, and incremental energy offers. A resource 
includes its costs that vary with output in its incremental energy 
offer, which typically consists of a supply curve made up of multiple 
(price, quantity) pairs that indicate the price, expressed in $/MWh, 
that a resource is willing to accept to produce a given quantity of 
energy.\11\
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    \11\ RTOs/ISOs typically restrict incremental energy supply 
curves to ten price and quantity pairs (i.e., ($/MWh, MW)).
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    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.
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    \12\ See Federal Energy Regulatory Commission, Division of 
Energy Market Oversight Office of Enforcement, Energy Primer, at 60 
(Nov. 2015), http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
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    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\
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    \13\ See, e.g., California Independent System Operator 
Corporation (CAISO), eTariff, 39.6.1.1 (11.0.0); ISO New England 
Inc. (ISO-NE), Transmission, Markets and Services Tariff, Market 
Rule 1, III.1.10.1A(d)(ix), III,1.10.IA(c)(iv), III.2.6(b)(i), and 
III.A.15.1(b) (27.0.0); Midcontinent Independent System Operator, 
Inc. (MISO), FERC Electric Tariff, 39.2.5 (35.0.0), 39.2.5A 
(34.0.0), 39.2.5B (34.0.0), 40.2.5 (35.0.0), 40.2.6 (35.0.0) and 
40.2.7 (33.0.0); New York Independent System Operator, Inc. (NYISO), 
NYISO Tariffs, NYISO Markets and Services Tariff, 21.4 and 21.5.1 
(7.0.0); PJM Interconnection, L.L.C. (PJM), Intra-PJM Tariffs, OATT, 
Tariff Operating Agreement, Attachment K, Appendix, 1.10.1A(d) 
(24.0.0); Southwest Power Pool, Inc. (SPP), OATT, Sixth Revised 
Volume No. 1, Attachment AE, Section 4.1.1 (2.0.0).
    \14\ PJM Interconnection L.L.C., 153 FERC ] 61,289, at P 25 
(2015) (PJM 2015/16 Offer Cap Order). The tariff provisions related 
to the offer cap do not have a sunset date.
    \15\ See 18 CFR 35.28(g)(3)(iii)(B)-(D) (2015).
    \16\ The RTOs/ISOs use different terms for a mitigated offer. 
ISO-NE., MISO, and NYISO mitigate supply offers to a ``Reference 
Level.'' See ISO-NE., Transmission Markets and Services Tariff, 
Market Rule 1, III.A.7.2; MISO FERC Electric Tariff, 64.1.4 
(30.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services Tariff, 
23.3.1.4 (11.0.0). CAISO mitigates supply offers to ``Default Energy 
Bids.'' See CAISO, eTariff, 39.7.1 (11.0.0). PJM mitigates supply 
offers to a ``cost-based offer.'' See PJM Operating Agreement, 
Schedule 1, 1.10.1A (24.0.0) and 6.4.1 (7.0.0). SPP mitigates supply 
offers to a ``Mitigated Energy Bid.'' See SPP OATT, Sixth Revised 
Volume No. 1, Attachment AF, 3.2 (7.0.0). For purposes of this NOPR, 
the offers RTOs/ISOs use for purposes of mitigation will be referred 
to as ``cost-based offers.''
    \17\ There are exceptions to this eligibility, for instance, 
when a resource is committed outside of the market clearing process.
    \18\ See supra n.16.
    \19\ PJM resources develop cost-based offers pursuant to PJM 
Manual 15: Cost Development Guidelines. SPP resources develop 
Mitigated Energy Bids pursuant to SPP's Mitigated Offer Guidelines 
in the SPP Market Protocols.
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    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

[[Page 5954]]

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\
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    \20\ See Docket Nos. OA97-261-000 and ER97-1082-000 (Apr. 1, 
1997); Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ] 
61,257 (1997).
    \21\ Scarcity and Shortage Pricing, Offer Mitigation and Offer 
Caps Workshop, Docket No. AD14-14-000, Tr. 209:18-22 (Oct. 28, 
2014).
    \22\ PJM Comments at 2. All comments cited herein were submitted 
in Docket No. AD14-14-000 on or about March 6, 2015.
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    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\
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    \23\ See, e.g., FERC Staff, Commission and Industry Actions 
Relevant to Winter 2013-14 Weather Events (Oct. 16, 2014), https://www.ferc.gov/media/news-releases/2014/2014-4/10-16-14-A-4-presentation.pdf.
    \24\ PJM Interconnection, L.L.C., 146 FERC ] 61,041, at P 2, 
order on reh'g, 149 FERC ] 61,059 (2014). For example, a natural gas 
resource with a heat rate of 8,350 Btu/kWh could have short-run 
marginal fuel costs above $1,000/MWh if the natural gas price 
exceeds $120/MMBtu.
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    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 cost-based offers in excess of $1,000/MWh and cost-based 
offers were used for purposes of calculating LMPs.\26\
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    \25\ Id. P 1.
    \26\ PJM Interconnection, L.L.C., 146 FERC ] 61,078, at PP 3-4 
(2014).
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    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\
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    \27\ N.Y. Indep. Sys. Operator, Inc., 146 FERC ] 61,061, at PP 
2-4 (2014).
    \28\ Id. P 24.
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    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.
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    \29\ PJM Interconnection L.L.C., 150 FERC ] 61,020, at P 5 
(2015) (PJM 2014/15 Offer Cap Order).
    \30\ Midcontinent Indep. Sys. Operator, Inc., 150 FERC ] 61,083, 
at P 3 (2015) (MISO 2014/15 Offer Cap Order).
    \31\ PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020.
    \32\ MISO 2014/15 Offer Cap Order, 150 FERC ] 61,083.
    \33\ See PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P 34; 
MISO 2014/15 Offer Cap Order, 150 FERC ] 61,083 at P 17.
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    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\
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    \34\ PJM, Proposed Tariff Revisions, Docket No. ER16-76-000 
(filed Oct. 14, 2015).
    \35\ MISO, Request for Waiver, Docket No. ER16-248-000 (filed 
Nov. 2, 2015).
    \36\ PJM 2015/16 Offer Cap Order, 153 FERC ] 61,289 at P 25. The 
tariff provisions related to the offer cap do not have a sunset 
date.
    \37\ Id. PP 25-26. Resources can submit cost-based offers above 
$2,000/MWh and PJM will use such offers for merit order dispatch, 
but incremental energy offers used for purposes of calculating LMP 
are capped at $2,000/MWh.
    \38\ Midcontinent Indep. Sys. Operator, Inc., 154 FERC ] 61,006 
(2015) (MISO 2015/16 Offer Cap Order).
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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.
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    \39\ Price Formation in Energy and Ancillary Services Markets 
Operated by Regional Transmission Organizations and Independent 
System Operators, Notice Inviting Post-Technical Workshop Comments, 
Docket No. AD14-14-000, at 2-3 (Jan. 16, 2015). A list of commenters 
and the abbreviated names the Commission will use for them in this 
document appears in Appendix A.
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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.

[[Page 5955]]

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\
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    \40\ ANGA Comments at 2; Brookfield Comments at 7; EPSA Comments 
at 24; Entergy Nuclear Power Marketing Comments at 11-12; Exelon 
Comments at 10-11; PJM Comments at 2-3; PJM Power Providers Comments 
at 2-4; SPP Comments at 1; Western Power Trading Forum Comments at 
5-6.
    \41\ EPSA Comments at 21-24; Exelon Comments at 10-12; OMS 
Comments at 2; PJM Comments at 2-3; PJM Power Providers Comments at 
2.
    \42\ OMS Comments at 2.
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    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\
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    \43\ PJM Utilities Coalition Comments at 3-4; Western Power 
Trading Forum Comments at 5.
    \44\ Direct Energy Comments at 2; EPSA Comments at 21.
    \45\ ANGA Comments at 2-3; Xcel Comments at 2.
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    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\
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    \46\ ANGA Comments at 2; Brookfield Comments at 7; Entergy 
Nuclear Power Marketing Comments at 11-12; ISO-NE Comments at 5; IRC 
Comments at 2-3; MISO Comments at 4; PJM Comments at 2; PJM Power 
Providers Group Comments at 2-4; Potomac Economics Comments at 3; 
Powerex Comments at 29-30; PSEG Companies Comments at 5-6; Western 
Power Trading Forum Comments at 5-6.
    \47\ EPSA Comments at 21-22.
    \48\ MISO Comments at 4.
    \49\ Id.; PJM Comments at 2.
    \50\ SPP Comments at 1; Western Power Trading Forum Comments at 
5-6.
---------------------------------------------------------------------------

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

    \51\ APPA and NRECA Comments at 30; CAISO Comments at 3; ELCON 
Comments at 6.
    \52\ CAISO Comments at 3; ISO-NE Comments at 3 & n.2; NYISO 
Comments at 4.
    \53\ CAISO Comments at 3.
    \54\ NCPA Comments at 2; PG&E Comments at 3; SCE Comments at 3; 
see also California State Water Project Comments at 2; New York 
Transmission Owners Comments at 2.
    \55\ NCPA Comments at 2-3; SCE Comments at 2.
    \56\ SCE Comments at 2. According to SCE, the $390/MWh figure 
assumes a heat rate of 17,000 Btu/kWh, slightly higher than the 
least efficient unit in CAISO, and a natural gas price of $23/MMBtu.
    \57\ APPA and NRECA Comments at 32.
---------------------------------------------------------------------------

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

    \58\ Scarcity and Shortage Pricing, Offer Mitigation and Offer 
Caps Workshop, Docket No. AD14-14-000, Tr. 205:6-15 (Oct. 28, 2014).
    \59\ Id. at 206:24-207:7.
    \60\ Id. at 210:14-23.
    \61\ Id. at 211:25-212:14.
---------------------------------------------------------------------------

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

    \62\ ANGA Comments at 2-3; Entergy Nuclear Power Marketing 
Comments at 11; EPSA Comments at 22-23; Exelon Comments at 11-12; 
Wisconsin Electric Comments at 2-3; Xcel Comments at 2.
    \63\ Wisconsin Electric Comments at 2.
    \64\ Direct Energy Comments at 2.
    \65\ GDF SUEZ Comments at 3.
---------------------------------------------------------------------------

    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

[[Page 5956]]

generator market power abuses, but also in whether the prices of input 
costs were developed in a competitive market.\69\
---------------------------------------------------------------------------

    \66\ ISO-NE Comments at 4; MISO Comments at 5-6; New York 
Transmission Owners Comments at 2-3; NYISO Comments at 3; TAPS 
Comments at 10-11; California State Water Project Comments at 2-3.
    \67\ Direct Energy Comments at 2; MISO Comments at 9; NCPA 
Comments at 3; New York Transmission Owners Comments at 4; Wisconsin 
Electric Comments at 2-3.
    \68\ ISO-NE Comments at 4.
    \69\ OMS Comments at 2.
---------------------------------------------------------------------------

    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 after-the-fact.\74\
---------------------------------------------------------------------------

    \70\ Potomac Economics Comments at 3-4.
    \71\ ELCON Comments at 6; TAPS Comments at 10-11.
    \72\ TAPS Comments at 12-13 (citing Scarcity and Shortage 
Pricing, Offer Mitigation and Offer Caps Workshop, Docket No. AD14-
14-000, Tr. 217:17-21 (Oct. 28, 2014)).
    \73\ TAPS Comments at 11 (citing Written Statement of Patrick T. 
Connors on Behalf of WPPI Energy and the Transmission Access Policy 
Study Group Regarding Impacts of Offer Caps and Market Power 
Mitigation, at 5 (Dec. 3, 2014)).
    \74\ APPA and NRECA Comments at 31-32.
---------------------------------------------------------------------------

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

    \75\ Id. at 29-31; California State Water Project Comments at 2-
3; New York Transmission Owners Comments at 2-3.
    \76\ APPA and NRECA Comments at 31.
    \77\ Id. at 31.
---------------------------------------------------------------------------

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

    \78\ Id. at 31-32.
    \79\ PG&E Comments at 3-4; SCE Comments at 3.
---------------------------------------------------------------------------

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

    \80\ Calpine Comments at 4-6.
    \81\ Id. at 21.
    \82\ Powerex Comments at 30.
    \83\ SPP Comments at 1.
    \84\ OMS Comments at 3.
---------------------------------------------------------------------------

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

    \85\ ISO-NE Comments at 4-6; MISO Comments at 5-7.
    \86\ ISO-NE Comments at 6.
    \87\ MISO Comments at 5-6.
    \88\ ISO-NE Comments at 6-7.
---------------------------------------------------------------------------

c. Higher Fixed Offer Cap
    32. Some commenters support raising the offer cap to a higher 
level. ANGA states that, at a minimum, the offer cap should be 
increased significantly to reduce unnecessary market distortions.\89\ 
Exelon argues that the current $1,000/MWh cap on market-based offers in 
PJM should be eliminated, but maintains that, if the offer cap remains 
in place, it should be raised to account for the highest reasonably 
expected offer, and that cost-based offers should be allowed to exceed 
the market-based offer cap.\90\
---------------------------------------------------------------------------

    \89\ ANGA Comments at 3.
    \90\ Exelon Comments at 12.
---------------------------------------------------------------------------

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

    \91\ ISO-NE Comments at 6.
    \92\ Id. at 3-4.
    \93\ MISO Comments at 4-5.
    \94\ Id. at 5.
---------------------------------------------------------------------------

    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,

[[Page 5957]]

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

    \95\ TAPS Comments at 13.
    \96\ APPA and NRECA Comments at 30-31.
    \97\ Id. at 30-31.
---------------------------------------------------------------------------

d. Permitting Cost-Based Incremental Energy Offers Above $1,000/MWh
    35. Some commenters argue that cost-based incremental energy offers 
should not be capped.\98\ PJM states that cost-based offers should not 
be subject to offer caps because offer caps impose arbitrary 
limits.\99\ PJM suggests that one approach may be to set a market-based 
offer cap on an annual basis at some percentage above the highest cost-
based incremental energy offer from previous time periods.\100\ PJM 
Power Providers and PSEG Companies assert that cost-based offers should 
not be capped and should be eligible to set the LMP.\101\ APPA and 
NRECA state that if the Commission wishes to revise the offer cap, it 
should limit any increase in the offer cap to periods when production 
costs exceed $1,000/MWh and ensure that any changes to the offer cap 
are accompanied by assurances that protect consumers against market 
power abuse.\102\ Although TAPS does not support increasing the $1,000/
MWh offer cap, TAPS similarly states that if the Commission wants to 
take temporary or seasonal action, the Commission should at the very 
least require that any incremental energy offer above $1,000/MWh be 
verified by the market monitor to be cost-justified.\103\
---------------------------------------------------------------------------

    \98\ Direct Energy Comments at 2; Exelon Comments at 12; PJM 
Comments at 3; PJM Power Providers Comments at 3-4; PSEG Companies 
Comments at 5.
    \99\ PJM Comments at 2-3.
    \100\ Id. at 4.
    \101\ PJM Power Providers Comments at 4; PSEG Companies Comments 
at 6.
    \102\ APPA and NRECA Comments at 30-32.
    \103\ TAPS Comments at 13-14.
---------------------------------------------------------------------------

    36. APPA and NRECA, CAISO and NCPA, however, argue that cost-based 
incremental offers must be verified before the market clears in order 
to avoid potentially disruptive after-the-fact corrections to clearing 
prices, and these commenters raise concerns that it is not feasible to 
do so.\104\ CAISO does not believe there is a firm basis to verify the 
natural gas price included in supply offers because market participants 
might not purchase natural gas before submitting offers and because 
natural gas quotes might not be available. CAISO also states that 
natural gas prices and quotes may be subject to manipulation, thereby 
making fuel cost verification difficult.\105\ CAISO requests that if 
the Commission directs RTOs/ISOs to pay resources uplift for fuel costs 
above the offer cap, then only incremental fuel costs associated with 
the incremental energy offer be reimbursable. In contrast, CAISO states 
that costs such as natural gas pooling, imbalance penalties, or risk 
premiums should be recovered through capacity payments.\106\
---------------------------------------------------------------------------

    \104\ APPA and NRECA Comments at 32; CAISO Comments at 6-7, NCPA 
Comments at 2.
    \105\ CAISO Comments at 4-6.
    \106\ Id. at 6.
---------------------------------------------------------------------------

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

    \107\ TAPS Comments at 14-15.
    \108\ Direct Energy Comments at 3-4.
---------------------------------------------------------------------------

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

    \109\ Brookfield Comments at 8; Calpine Comments at 5; EEI 
Comments at 9; EPSA Comments at 21; Exelon Comments at 13-14; IRC 
Comments at 2; ISO-NE Comments at 6-7; MISO Comments at 8; New York 
Transmission Owners Comments at 3-4; NYISO Comments at 4; PJM 
Comments at 4; PJM Power Providers Comments at 5-6; PJM Utilities 
Coalition Comments at 6; PSEG Companies Comments at 6-7; Potomac 
Economics Comments at 5; Western Power Trading Forum Comments at 6; 
Wisconsin Electric Comments at 4.
    \110\ IRC Comments at 2; PJM Comments at 4; PSEG Companies 
Comments at 6-7.
    \111\ ISO-NE Comments at 7; NYISO Comments at 5.
    \112\ NYISO Comments at 4-5.
    \113\ MISO Comments at 8.
---------------------------------------------------------------------------

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

    \114\ APPA and NRECA Comments at 29-30; NCPA Comments at 3.
    \115\ APPA and NRECA Comments at 32.
    \116\ Direct Energy Comments at 4; PJM Utilities Coalition 
Comments at 6.
---------------------------------------------------------------------------

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

    \117\ SCE Comments at 2.
    \118\ CAISO Comments at 5.
    \119\ MISO Comments at 5.
---------------------------------------------------------------------------

    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

[[Page 5958]]

assist RTOs/ISOs with gas price verification and to ameliorate natural 
gas price spikes.\122\
---------------------------------------------------------------------------

    \120\ IRC Comments at 3; New York Transmission Owners Comments 
at 5.
    \121\ New York Transmission Owners Comments at 5.
    \122\ IRC Comments at 3.
---------------------------------------------------------------------------

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

    \123\ See supra P 10.
    \124\ See supra P 17.
    \125\ See, e.g., Midwest Indep. Transmission Sys. Operator, 
Inc., 108 FERC ] 61,163, at PP 380-381, order on reh'g, 109 FERC ] 
61,157 (2004), order on clarification, 111 FERC ] 61,367 (2005); 
N.Y. Indep. Sys. Operator, Inc., 97 FERC ] 61,095, at 61,496-97 
(2001); ISO New England, Inc., 97 FERC ] 61,090, at 61,471.
    \126\ See supra PP 23-26.
---------------------------------------------------------------------------

    44. First, the offer cap can prevent a resource from recouping its 
short-run marginal costs. With the current $1,000/MWh offer cap, a 
resource whose short-run marginal cost exceeds $1,000/MWh may operate 
at a loss. For example, in January 2014, resources in PJM faced high 
natural gas prices that caused their short-run marginal costs to exceed 
the $1,000/MWh offer cap in place at the time.\127\ Similarly, MISO 
states that high natural gas prices in January and March 2014 caused 
some MISO resources to experience costs in excess of the $1,000/MWh 
offer cap.\128\
---------------------------------------------------------------------------

    \127\ PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P 2.
    \128\ MISO 2014/15 Offer Cap Order, 150 FERC ] 61,083 at P 2.
---------------------------------------------------------------------------

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

    \129\ MISO Comments at 4; PJM Comments at 2.
---------------------------------------------------------------------------

    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 short-run marginal cost. For these reasons, the 
Commission preliminarily finds that the current offer caps result in 
rates that are unjust and unreasonable. In addition, these reasons 
illustrate that the current offer caps may not achieve the price 
formation goals discussed above.
    48. The Commission considered several alternatives to achieve the 
price formation goals. On balance, the Commission has preliminarily 
determined that the alternative that best achieves the price formation 
goals is to retain the existing $1,000/MWh offer cap except in 
circumstances when a resource has verifiable short-run marginal costs 
in excess of $1,000/MWh. The discussion at the technical workshop and 
subsequent comments received suggest that the $1,000/MWh offer cap is 
appropriate in most circumstances and serves as an appropriate backstop 
to the existing market power mitigation rules. However, recent 
experience also suggests that some resources may face short-run 
marginal costs greater than $1,000/MWh and, in such infrequent 
circumstances, the $1,000/MWh offer cap inappropriately limits those 
resources' incremental energy offers and the resulting LMP. To the 
extent incremental energy offers can be verified, we believe a generic 
reform to allow offers and LMPs to exceed $1,000/MWh will enhance 
market efficiency and mitigate the potential for seams issues.

B. Alternative Offer Cap Proposals Discussed in Comments

    49. This section briefly discusses why the Commission has not 
proposed the other alternative offer cap designs. The Commission is not 
proposing the alternative that uses 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\
---------------------------------------------------------------------------

    \130\ Price Formation in Energy and Ancillary Services Markets 
Operated by Regional Transmission Organizations and Independent 
System Operators, Notice Inviting Post-Technical Workshop Comments, 
Docket No. AD14-14-000, at 2 (Jan. 16, 2015).
---------------------------------------------------------------------------

    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

[[Page 5959]]

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 short-run marginal cost 
and potentially suppress LMPs if that resource's costs rose above the 
fixed offer cap. Additionally, like the floating offer cap, a higher 
fixed offer cap could raise market power concerns.

C. Commission Proposal

    52. To remedy any potentially unjust and unreasonable rates, the 
Commission proposes, pursuant to section 206 of the Federal Power Act 
(FPA),\131\ to revise its regulations to require that each RTO/ISO cap 
a resource's incremental energy offer used for purposes of setting LMPs 
to the higher of $1,000/MWh or that resource's verified cost-based 
incremental energy offer. Under the proposal, consistent with Order No. 
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.
---------------------------------------------------------------------------

    \131\ 16 U.S.C. 824e(b).
    \132\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at PP 370-375 
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 
31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ] 61,252 
(2009).
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1. Offer Cap Structure
    53. The first proposed requirement is as follows:
    A resource's incremental energy offer used for purposes of 
calculating Locational Marginal Prices in energy markets must be capped 
at the higher of $1,000/MWh or that resource's cost-based incremental 
energy offer.
This requirement would ensure that a resource is given the opportunity 
to recoup its short-run marginal costs during intervals when those 
costs exceed $1,000/MWh because the resource could include such costs 
within its cost-based incremental energy offer. Additionally, this 
requirement would ensure that LMPs are no longer suppressed by the 
offer cap when marginal production costs exceed $1,000/MWh. This 
requirement would permit RTOs/ISOs to accept cost-based incremental 
energy offers above $1,000/MWh and use those offers in the market 
clearing process that calculates LMPs, but only when such offers are 
cost-based. Accordingly, all incremental energy offers above $1,000/MWh 
would be subject to market power mitigation and the attendant 
requirement that the offer be equal to the short-run marginal cost of 
the associated resource. Incremental energy offers at or below $1,000/
MWh will continue to be subject to existing market power mitigation 
provisions.
    54. The Commission preliminarily finds that it is necessary to 
permit resources to submit cost-based incremental energy offers above 
$1,000/MWh, because as PJM and MISO indicated in recent filings, the 
$1,000/MWh offer cap appears to have limited some resources' 
incremental energy offers to a level below their short-run marginal 
cost during intervals with high natural gas prices.\133\ In addition, 
allowing all resources to offer consistent with short-run marginal cost 
will enhance an RTO/ISO's ability to dispatch the lowest cost 
resources, particularly when multiple resources have short-run marginal 
cost greater than $1,000/MWh. Furthermore, allowing a resource to 
submit a cost-based incremental energy offer above $1,000/MWh would 
help ensure that resources with short-run marginal costs above $1,000/
MWh have an incentive to offer electricity into the market during high 
price periods, when their electricity may be needed. Allowing LMPs to 
reflect a given RTO/ISO's marginal cost of production could result in 
more economic power flows across seams because electricity would flow 
to where it is most valued.
---------------------------------------------------------------------------

    \133\ PJM 2015/16 Offer Cap Order, 153 FERC ] 61,289, at PP 2-3 
(2015); MISO, Transmittal at 4, Docket No. ER16-248-000 (filed Nov. 
2, 2015); MISO 2015/16 Offer Cap Order, 154 FERC ] 61,006.
---------------------------------------------------------------------------

    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 short-run 
marginal cost of resources in those RTOs/ISOs (i.e., the offer cap does 
not currently force a resource to submit an incremental energy offer 
below its short-run marginal cost).\137\ Under this proposal, verified 
cost-based incremental energy offers are not capped. The Commission 
recently approved tariff revisions in PJM that required all incremental 
energy offers above $1,000/MWh to be cost-based and also placed a 
$2,000/MWh hard cap on cost-based incremental energy offers used for 
purposes of calculating LMPs.\138\ The Commission seeks comment on 
whether such a hard cap should be included in any final rule in this 
proceeding and, if so, whether the hard cap should equal $2,000/MWh or 
another value.
---------------------------------------------------------------------------

    \134\ Scarcity and Shortage Pricing, Offer Mitigation and Offer 
Price Caps Workshop, Docket No. AD14-14-000, Tr. 205:11-19, 206:24-
207:7, 210:14-211:8, 212:12-213:3 (Oct. 28, 2015).
    \135\ See supra PP 25-26.
    \136\ ISO-NE Comments at 4.
    \137\ CAISO Comments at 3; ISO-NE Comments at 3; NYISO Comments 
at 4.
    \138\ See supra n.36.
---------------------------------------------------------------------------

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.

[[Page 5960]]

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 cost-based incremental energy 
offer above $1,000/MWh is in fact cost-based. The Market Monitoring 
Unit or the RTO/ISO would verify that a resource's cost-based offer is 
an accurate reflection of that resource's short-run marginal cost. The 
Commission notes that for purposes of mitigation, the RTO/ISO tariffs 
use different terminology to describe the market power mitigation 
process, short-run marginal costs, and mitigated offers.\139\ The 
Market Monitoring Units in some RTOs/ISOs currently have processes 
whereby the Market Monitoring Unit or the market participant itself can 
derive cost-based incremental energy offers that are specific to a 
given resource.\140\ Additionally, ISO-NE and NYISO currently have 
processes in place where a resource can contact, before the close of 
the day-ahead or real-time markets, the Market Monitoring Unit to 
update the resource's cost-based incremental energy offer (e.g., due to 
a change in fuel prices).\141\ These updates are subject to 
verification by the Market Monitoring Unit.
---------------------------------------------------------------------------

    \139\ See supra n.16.
    \140\ Id.
    \141\ ISO-NE, Markets and Services Tariff, Market Rule 1, 
III.A.3.1 (43.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services 
Tariff, 23.3.1.4.6.7 (11.0.0). Resources in SPP may also contact the 
Market Monitoring Unit during the operating day and request a 
mitigation exception pursuant to SPP, OATT, Sixth Revised Volume No. 
1, Attachment AF, 3.8 (7.0.0). Additionally, in MISO resources may 
consult with the Market Monitoring Unit to change reference levels 
as soon as practicable. MISO, FERC Electric Tariff, 64.1.4.h 
(30.0.0).
---------------------------------------------------------------------------

    59. Under the proposal, the Market Monitoring Unit or the RTO/ISO 
must verify the costs within a cost-based incremental energy offer 
above $1,000/MWh before that offer is used for purposes of calculating 
LMPs. The Commission seeks comment regarding the Market Monitoring 
Unit's or the RTO/ISO's ability to timely verify the costs within 
incremental energy offers above $1,000/MWh prior to the day-ahead or 
real-time market clearing process, including whether the verification 
of physical offer components is also necessary. The Commission seeks 
comment on whether the Market Monitoring Unit or RTO/ISO may need 
additional information to ensure that all short-run marginal cost 
components that are difficult to quantify, such as certain opportunity 
costs, are accurately reflected in a resource's cost-based incremental 
energy offer. For example, cost-based offers in PJM include a ten 
percent adder, which may account for such cost components. To the 
extent that RTOs/ISOs currently include an adder above cost in cost-
based incremental energy offers, is such an adder appropriate for 
incremental energy offers above $1,000/MWh? The Commission also seeks 
comment on whether the Market Monitoring Unit or RTO/ISO may need 
additional information or new authority to require revisions or 
corrections to cost-based incremental energy offers to ensure that a 
cost-based incremental energy offer is an accurate reflection of a 
resource's short-run marginal cost.
    60. Under this proposal, each RTO/ISO would be required to include 
in its tariff a process by which the Market Monitoring Unit or RTO/ISO 
verifies the costs included in cost-based incremental energy offers 
above $1,000/MWh. To create such a verification process, the Commission 
expects that the Market Monitoring Unit or RTO/ISO would build on its 
existing mitigation processes for calculating or updating cost-based 
incremental energy offers. The Commission notes that the nature of 
before-the-fact and after-the-fact cost verification processes often 
differ. The Commission expects that a market participant that seeks to 
submit a cost-based incremental energy offer above $1,000/MWh must 
provide appropriate documentation to the Market Monitoring Unit or the 
RTO/ISO. The Market Monitoring Unit or RTO/ISO should then have a 
before-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.
---------------------------------------------------------------------------

    \142\ For example, CAISO and PJM mitigate resources to cost-
based offers that include a ten percent adder, while the standard 
cost-based offers in MISO, ISO-NE, and NYISO do not include an adder 
above cost.
    \143\ See supra n.16
---------------------------------------------------------------------------

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

    \144\ Any proposal to develop cost-based incremental energy 
offers for external transactions could address external resources 
generically or address certain scheduling practices (e.g., dynamic 
or pseudo tie schedules).
---------------------------------------------------------------------------

    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

[[Page 5961]]

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

    \145\ To the extent they currently exist, this proposal would 
not affect existing RTO/ISO tariff provisions that permit virtual 
transactions to exceed $1,000/MWh.
    \146\ The Commission found it just and reasonable for virtual 
increment offers and decrement bids in PJM to clear up to $2,700/
MWh, equal to the newly established energy and reserve market 
aggregate price cap. PJM Interconnection, L.L.C., 139 FERC ] 61,057, 
at PP 123-143 (2012).
---------------------------------------------------------------------------

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

    \147\ Under 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.
---------------------------------------------------------------------------

    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 cost-based 
incremental energy offer above $1,000/MWh, a resource that 
misrepresents its costs would be in violation of the Commission's 
regulations requiring accurate statements. Section 35.41(b) of the 
Commission's regulations requires market participants to provide 
``accurate and factual information and not submit false or misleading 
information, or omit material information, in any communication with 
the Commission, Commission-approved market monitors . . . [or] 
Commission-approved independent system operators.'' \149\ Additionally, 
a resource that intentionally misrepresents its costs could violate the 
Commission's Anti-Manipulation Rule. That rule prohibits a market 
participant from intentionally making ``any untrue statement of a 
material fact or to omit[ting] to state a material fact necessary in 
order to make the statements made, in the light of the circumstances 
under which they were made, not misleading.'' \150\ Thus, any 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.
---------------------------------------------------------------------------

    \148\ Several RTOs/ISOs also rely on procedures to temporarily 
strip resources of the opportunity to make fuel price related 
adjustments to their reference levels in the event after-the-fact 
verification processes fail to confirm the need for the reference 
level update. See ISO-NE., Transmission Markets and Services Tariff, 
Market Rule 1, III.A.3.4(c) (43.0.0); NYISO, NYISO Tariffs, NYISO 
Markets and Services Tariff, 23.3.1.4.6.8 (11.0.0).
    \149\ 18 CFR 35.41(b) (2015).
    \150\ 18 CFR 1c.2(a)(2) (2015).
---------------------------------------------------------------------------

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

    \151\ CAISO Comments at 6-7.
---------------------------------------------------------------------------

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

    \152\ PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P 39.
    \153\ See MISO 2014/15 Offer Cap Order, 150 FERC ] 61,083 at P 
16; PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P 39; PJM 
2015/16 Offer Cap Order, 153 FERC ] 61,289; MISO 2015/16 Offer Cap 
Order, 154 FERC ] 61,006.
---------------------------------------------------------------------------

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

[[Page 5962]]

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

    \154\ NYISO Comments at 4-5.
    \155\ ISO-NE Comments at 7; NYISO Comments at 5.
    \156\ See PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P 
42; MISO 2014/15 Offer Cap Order, 150 FERC ] 61,083 at P 19.
---------------------------------------------------------------------------

    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 price-sensitive demand bids, and other means by which 
load can express its willingness to pay for electricity. Although they 
are not required to do so, the Commission would consider other market 
design changes, such as changes to scarcity or shortage pricing or 
other penalty prices, associated with adopting this proposal in the 
compliance filing.
---------------------------------------------------------------------------

    \157\ CAISO Comments at 8.
---------------------------------------------------------------------------

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 cost-based 
incremental energy offers and to implement market power mitigation 
provisions that are to be used as a basis for implementing this 
proposal. As noted previously, the Commission is also willing to 
consider proposed revisions to other market design features that may 
require revision in light of this proposal, such as changes to scarcity 
or shortage pricing or other market parameters.
    75. To the extent that any RTO/ISO believes that it already 
complies with the reforms adopted in a final rule in this proceeding, 
the RTO/ISO would be required to demonstrate, in the compliance filing, 
how it complies.

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

    \158\ 44 U.S.C. 3501-3520.
    \159\ 5 CFR 1320 (2015).
---------------------------------------------------------------------------

    77. The reforms proposed in this NOPR would amend the Commission's 
regulations to improve the operation of organized wholesale electric 
power

[[Page 5963]]

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

    \160\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

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

    \161\ The RTOs and ISOs (CAISO, ISO-NE., MISO, NYISO, PJM, and 
SPP) are required to comply with the reforms proposed in this NOPR.

                                                                        Software or Hardware Upgrades May Not Be Required
                                                                      [FERC-516, as modified by NOPR in Docket RM16-5-000]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Annual number
                                             Number of     of responses    Total number   Average burden (hours) & cost per response   Total annual burden hours & total annual      Cost per
                                            respondents   per respondent   of responses                                                                  cost                     respondent ($)
                                                     (1)             (2)     (1) x (2) =  (4).......................................  (3) x (4) = (5)...........................       (5) / (1)
                                                                                     (3)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
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\
---------------------------------------------------------------------------

    \162\ The Commission expects that the validation of cost-based 
incremental energy offers above $1,000/MWh would be an infrequent 
occurrence. To the extent that the Market Monitoring Unit or the 
RTO/ISO spends time validating these offers, the Commission 
estimates such time to be de minimis.
    \163\ The estimated hourly cost (salary plus benefits) provided 
in this section are based on the salary figures for May 2014 posted 
by the Bureau of Labor Statistics for the Utilities sector 
(available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000) 
and scaled to reflect benefits using the relative importance of 
employer costs in employee compensation from March 2015 (available 
at http://www.bls.gov/news.release/ecec.nr0.htm). The hourly 
estimates for salary plus benefits are:
     Legal (code 23-0000), $129.87
     Computer and mathematical (code 15-0000), $58.25
     Information systems manager (code 11-3021), $94.55
     IT security analyst (code 15-1122), $63.55
     Auditing and accounting (code 13-2011), $51.11
     Information and record clerk (code 43-4199), $37.50
     Electrical Engineer (code 17-2071), $66.45
     Economist (code 19-3011), $73.04
     Management (code 11-0000), $78.04
    The average hourly cost (salary plus benefits), weighting all of 
these skill sets evenly, is $72.48. The Commission rounds it to $72 
per hour.
---------------------------------------------------------------------------

    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.

[[Page 5964]]

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

    \164\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

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

    \165\ This estimate does not include costs for software or 
increased time spent validating cost-based incremental energy 
offers, for which the Commission requests comment. As stated above, 
the Commission expects that the validation of cost-based incremental 
energy offers above $1,000/MWh would be an infrequent occurrence. To 
the extent that the Market Monitoring Unit or the RTO/ISO spends 
time validating these offers, the Commission expects such time to be 
de minimis.
    \166\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administrations' regulations at 13 CFR 121.201 define 
the threshold for a small Electric Bulk Power Transmission and 
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 
632.
---------------------------------------------------------------------------

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

    \167\ Regulations Implementing the National Environmental Policy 
Act of 1989, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC 
Stats. & Regs. ] 30,783 (1987).
    \168\ 18 CFR 380.4(a)(15) (2015).
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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:

[[Page 5965]]

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.28 by adding paragraph (g)(9) to read as follows:

Sec.  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 make-whole payment if that resource clears the 
energy market and the resource's costs are verified after-the-fact. All 
resources, regardless of type, are eligible to submit cost-based 
incremental energy offers in excess of $1,000/MWh.
    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