[Federal Register Volume 81, Number 23 (Thursday, February 4, 2016)]
[Proposed Rules]
[Pages 5951-5965]
[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,<PHONE_NUMBER><EMAIL_ADDRESS>Pamela Quinlan (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>Anne Marie Hirschberger (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>
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.

    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\

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, <IP_ADDRESS> (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,
<IP_ADDRESS> (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

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.

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.
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    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

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,

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

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

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).
---------------------------------------------------------------------------

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.

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, <IP_ADDRESS>.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

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, <IP_ADDRESS>.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

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

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.
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    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:
<EMAIL_ADDRESS>Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
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:<PHONE_NUMBER>, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically
to the following email address<EMAIL_ADDRESS>Comments
submitted to OMB should include FERC-516 and OMB Control No. 1902-0096.

V. Regulatory Flexibility Act Certification

    80. The Regulatory Flexibility Act of 1980 (RFA) \164\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA does
not mandate any particular outcome in a rulemaking. It only requires
consideration of alternatives that are less burdensome to small
entities and an agency explanation of why alternatives were rejected.
---------------------------------------------------------------------------

    \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\
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    \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<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
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:

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