11; ISO-NE Comments at 4-5; SPP Market Monitor Comments at 7; PJM
Market Monitor Comments at 6; EEI Comments at 6; Exelon Comments at
13-14; PJM Power Providers Comments at 3.
---------------------------------------------------------------------------

    110. PJM states that higher natural gas prices have led to higher
cost-based incremental energy offers from resources, but verifying
resource costs with natural gas price indices can be challenging
because there is not a strong or straightforward correlation between
changes in natural gas index prices and the magnitude of changes in
cost-based offers, particularly when cost-based incremental energy
offers in PJM are high.\238\ ISO-NE argues that indices may not fairly
represent the fuel prices that resources must pay, particularly when
natural gas supplies are tight.\239\ ISO-NE notes that there may be
scant independent or timely information on natural gas resources' costs
during such times.\240\ Various commenters explain that during such
times, natural gas resources must often purchase natural gas outside of
the exchange trading platforms \241\ through bilateral deals that are
not reported on such exchanges, and that a significant amount of such
purchases tends to make natural gas

indices less representative of the price natural gas resources pay for
natural gas.\242\
---------------------------------------------------------------------------

    \238\ PJM/SPP Comments at 11 (citing Attachment A). Attachment A
presents an analysis of cost-based incremental energy offers and
natural gas prices during the winters of 2013/14, 2014/15, and 2015/
16. The analysis in Attachment A shows that for cost-based offers in
the $500/MWh-$750/MWh range, the median gas price corresponding to
the range of offers was $10.44/MMBtu in the 2013/14 winter, $15.62
MMBtu in the 2014/15 winter, and $3.75/MMBtu in the 2015/16 winter.
    \239\ ISO-NE Comments at 4-5.
    \240\ Id.
    \241\ Industrial Customers Comments at 16; ISO-NE Comments at 4-
5; ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments
at 6; SPP Market Monitor Comments at 7.
    \242\ ISO-NE Market Monitor Comments at 8; PJM Market Monitor
Comments at 6.
---------------------------------------------------------------------------

    111. The ISO-NE., PJM, and SPP market monitors state that cost
verification is most challenging when natural gas demand is high
because of low liquidity and high bid-ask spreads for natural gas
purchased on open exchanges such as the ICE.\243\ For example, the PJM
Market Monitor and the ISO-NE Market Monitor state that the natural gas
market is least transparent on days with very high electric demand and
that the ICE index is likely to be unsuitable for verification purposes
because there are either no completed trades reported, a low number of
completed gas trades (i.e., low liquidity), or the bid-ask spread is so
wide as to be meaningless.\244\ The SPP Market Monitor states that the
risk inherent in determining accurate fuel costs from natural gas
indices is acceptable in most periods, but that the risk increases to
unacceptable levels during extremely stressed fuel supply
conditions.\245\ Comments from generators also suggest that natural gas
indices become less reliable during periods when natural gas supplies
are limited and natural gas prices spike.\246\ Dominion and Exelon
assert that purchasing natural gas outside of an exchange through
marketers or bilateral deals also increases the risks that a natural
gas resource faces when it formulates its bid, and can increase the
error associated with a resource's estimate of its actual costs.\247\
---------------------------------------------------------------------------

    \243\ ISO-NE Market Monitor Comments at 8; PJM Market Monitor
Comments at 6; SPP Market Monitor Comments at 7.
    \244\ ISO-NE Market Monitor Comments at 7-8; PJM Market Monitor
Comments at 6.
    \245\ SPP Market Monitor Comments at 7.
    \246\ EEI Comments at 6; Exelon Comments at 13-14; PJM Power
Providers Comments at 3.
    \247\ Dominion Comments at 5; Exelon Comments at 13-14.
---------------------------------------------------------------------------

c. Feasibility of Verification Requirement
    112. The Commission sought comment on the feasibility of the
proposed verification requirement.\248\ As discussed further below,
ISO-NE, MISO, and NYISO state that current mitigation procedures could
satisfy the proposed verification requirement if the Commission
clarifies that the verification process can include expected, rather
than actual, costs.\249\ Several commenters express concerns that
timely verification of a resource's actual short-run marginal costs is
not possible within the timeframe of the RTO/ISO day-ahead and real-
time market clearing process.\250\
---------------------------------------------------------------------------

    \248\ NOPR, FERC Stats. & Regs. ] 32,714 at PP 59, 73.
    \249\ See infra PP 126-127.
    \250\ Exelon Comments at 11; Industrial Customers Comments at
13-16; ISO-NE Market Monitor Comments at 9; Joseph Margolies
Comments at 13; Potomac Economics Comments at 3-4; SPP Market
Monitor Comments at 2, 7, 9.
---------------------------------------------------------------------------

    113. For example, Potomac Economics states that time constraints
will make the proposal infeasible if the proposed verification requires
that resource cost data be collected and fully validated to actual cost
prior to market clearing.\251\ The ISO-NE Market Monitor states that
the lack of solid information about natural gas prices on high-
volatility, low-liquidity days makes validation of a resource's
expected short-run marginal costs difficult, particularly if many
resources seek to update their cost-based incremental energy
offers.\252\ The PJM Market Monitor notes that in PJM, a large volume
of data, including information from approximately 420 gas-fired
resources and about 35 gas trading points, must be processed to review
cost-based incremental energy offers.\253\ The SPP Market Monitor
states that verification prior to market clearing may not be feasible
in SPP given the tight timeline, particularly during sudden fuel
shortages and fuel price spikes, and adds that it would need additional
technical capabilities for such verification.\254\ The SPP Market
Monitor states that the proposal could also negatively affect RTO/ISO
market monitors' ability to conduct timely market power mitigation
under the proposed timeline because market monitors would be required
to perform cost verification and market mitigation before completion of
the market clearing process.\255\
---------------------------------------------------------------------------

    \251\ Potomac Economics Comments at 3-4.
    \252\ ISO-NE Market Monitor Comments at 9.
    \253\ PJM Market Monitor Comments at 7.
    \254\ SPP Market Monitor Comments at 2, 7, 9, 10-11.
    \255\ Id. at 9.
---------------------------------------------------------------------------

    114. Industrial Customers argue that market monitors cannot be
expected to have the ability to assess the legitimacy of the cost
component of resource offers in real-time.\256\ Industrial Customers
add that even if a resource has a natural gas invoice with a high price
and provides it to the market monitor, this alone does not provide
adequate consumer protection because the market monitor must
investigate, understand, and accept the dynamics that led to that
invoice.\257\
---------------------------------------------------------------------------

    \256\ Industrial Customers Comments at 14.
    \257\ Industrial Customers Comments at 19.
---------------------------------------------------------------------------

    115. Citing CAISO's prior comments about practical implementation
challenges associated with before-the-fact verification, Industrial
Customers argue that the proposal in the NOPR may not be beneficial
because pre-verification presents significant challenges given time
constraints.\258\ KEPCo/NCEMC states that RTOs/ISOs may not be in a
position to verify cost-based incremental energy offers prior to market
clearing without substantial investment in both new technology and
significant changes to the existing RTO/ISO tariffs and business
practice manuals.\259\ KEPCo/NCEMC argues that the verification
requirement involves substantial technological and regulatory costs for
wholesale market participants, which KEPCo/NCEMC asserts are
unwarranted given the limited nature of the problem with the current
RTO/ISO offer caps.\260\
---------------------------------------------------------------------------

    \258\ Id. at 14-16 (citing CAISO Post-Technical Workshop
Comments, Docket No. AD14-14-000, at 4-6 (Mar. 6, 2015)).
    \259\ KEPCo/NCEMC Comments at 5.
    \260\ Id.
---------------------------------------------------------------------------

    116. EEI maintains that the NOPR proposal is heavily dependent on
having a verification process that is not so cumbersome as to prevent a
resource's cost based incremental energy offer from being verified in
time to be used in the LMP calculation. It argues that the use of make-
whole payments would not serve the Commission's goal of having clearing
prices that reflect the true marginal cost of production, taking into
account all physical constraints.\261\ NEI states that the manner in
which the verification is performed is a key concern, and without a
simple and efficient process, there is risk that the LMP will not
reflect the true costs of operating the system because it will exclude
offers above the cap. NEI maintains that an alternative approach would
be warranted if market monitors cannot validate incremental energy
offers in excess of $1,000/MWh quickly and efficiently.\262\
Competitive Suppliers contend that the proposed verification
requirement would result in cost-based offers above $1,000/MWh being
unable to set the LMP because cost verification prior to the market
clearing process is not possible.\263\
---------------------------------------------------------------------------

    \261\ EEI Comments at 5.
    \262\ NEI Comments at 4.
    \263\ Competitive Suppliers Comments at 17-18.
---------------------------------------------------------------------------

    117. Competitive Suppliers argue that removing the offer cap
entirely or increasing it significantly would alleviate any challenges
inherent in a before-the-fact cost verification process.\264\
Similarly, NEI states that instead of the verification requirement, the
Commission should lift caps to a

level that does not artificially constrain LMPs.\265\
---------------------------------------------------------------------------

    \264\ Id.
    \265\ NEI Comments at 4.
---------------------------------------------------------------------------

    118. Midcontinent Joint Consumer Advocates and TAPS argue that it
is possible to perform the proposed cost verification prior to the
market clearing process.\266\ Midcontinent Joint Consumer Advocates
state that the MISO Market Monitor has publicly confirmed its ability
to verify offers prior to market clearing and that it currently tracks
fuel prices that could be used to make adjustments to gas and fuel
costs included in a MISO resource's cost-based incremental energy
offer.\267\ According to TAPS, MISO's current process for developing
and updating cost-based incremental offers for resources is workable
because the vast majority of resources will never experience cost
levels close to $1,000/MWh, and the resources that are likely to reach
such levels should have already provided the Market Monitoring Unit
with up-to-date information about their heat rates, which will allow
the Market Monitoring Unit to quickly calculate cost-based incremental
energy offers for such resources.\268\ TAPS states that MISO's current
methodology for verification of cost-based incremental offers could be
modified and adapted in all RTOs/ISOs.\269\
---------------------------------------------------------------------------

    \266\ Midcontinent Joint Consumer Advocates Comments at 5; TAPS
Comments at 13-15.
    \267\ Midcontinent Joint Consumer Advocates Comments at 5.
    \268\ TAPS Comments at 13-14.
    \269\ Id. at 14-15.
---------------------------------------------------------------------------

d. Uplift Payments
    119. Several stakeholders commented on the after-the-fact review of
costs in the event that the RTO/ISO or Market Monitoring Unit is unable
to verify a resource's incremental energy offer above $1,000/MWh prior
to the market clearing process.\270\ MISO states that market
participants should be required to consult with the Market Monitoring
Unit before the submission of an offer in order for that market
participant to be eligible for make-whole payments after-the-fact, and
asserts that market participants should not be eligible for cost
recovery above their offers just because in hindsight, their offers
were below their actual costs.\271\ PG&E states that if a cost-based
incremental energy offer is verified after the market has run, energy
cleared from such an offer should be compensated on an ``as bid''
basis.\272\ PG&E maintains that if a cost-based incremental energy
offer cannot be verified even after the market has run, then that
resource's cleared energy should instead be compensated at the
LMP.\273\ PJM Power Providers and Competitive Suppliers assert that
even after-the-fact verification of a resource's costs will be
challenging, and, according to Competitive Suppliers, it will be
particularly challenging for natural gas resources that have complex
fuel supply arrangements.\274\
---------------------------------------------------------------------------

    \270\ Competitive Suppliers Comments at 19; MISO Comments at 10;
PG&E Comments at 3; PJM Power Providers Comments at 4.
    \271\ MISO Comments at 10.
    \272\ PG&E Comments at 3.
    \273\ Id.
    \274\ Competitive Suppliers Comments at 19; PJM Power Providers
Comments at 4.
---------------------------------------------------------------------------

    120. Competitive Suppliers state that in some instances, a resource
may not be able to use the RTO's/ISO's verification process to set the
market clearing price (for offers above $1,000/MWh) and in such rare
cases, it may be necessary to compensate that resource through an
uplift payment based on after-the-fact cost verification.\275\
Competitive Suppliers assert that if a resource incurs justifiable and
demonstrable short-run marginal costs, those costs should be recovered
so that the resource does not operate at a loss and so that the
resource is not discouraged from offering supply to the market.\276\
---------------------------------------------------------------------------

    \275\ Competitive Suppliers Comments at 20-21.
    \276\ Id. at 21.
---------------------------------------------------------------------------

    121. NEI states that, given that the Commission's price formation
reforms are aimed at reducing the use of out-of-market payments, NEI is
disappointed by the NOPR proposal to include uplift payments as a fall
back if before-the-fact cost verification proves infeasible in
practice.\277\ However, Direct Energy states that if a resource's
verified cost-based incremental energy offer exceeds the cap, that
resource should be entitled to full cost recovery of RTO/ISO approved
costs through uplift.\278\
---------------------------------------------------------------------------

    \277\ NEI Comments at 4.
    \278\ Direct Energy Comments at 3.
---------------------------------------------------------------------------

e. Specific Proposals for the Verification Requirement
    122. Given the concerns about verification of actual costs, several
commenters, including RTOs/ISOs,\279\ Market Monitoring Units,\280\ and
other stakeholders,\281\ request that the Commission clarify that if it
is not possible to verify a resource's actual costs prior to setting
LMP, it will accept a process that verifies that a resource's
incremental energy offer reasonably reflects that resource's expected
costs.
---------------------------------------------------------------------------

    \279\ ISO-NE Comments at 4-7; NYISO Comments at 2; PJM/SPP
Comments at 12-13.
    \280\ Potomac Economics Comments at 3-4; ISO-NE Market Monitor
Comments at 4.
    \281\ EEI Comments at 6-7; Exelon Comments at 17.
---------------------------------------------------------------------------

    123. Several commenters maintain that a prior-to-the-market-
clearing verification process that requires cost-based offers be equal
to actual costs will likely result in fewer incremental energy offers
above $1,000/MWh that are eligible to set LMP.\282\ For example, EEI
states that its primary concern with the NOPR is the verification
process and whether it is workable.\283\ The ISO-NE Market Monitor and
PJM/SPP state that there is a trade-off between the level of precision
of the cost-based offer verification, the number of offers that will be
eligible to set LMPs, and the level of uplift.\284\
---------------------------------------------------------------------------

    \282\ CEA Comments at 5; EEI Comments at 5.
    \283\ EEI Comments at 5.
    \284\ ISO-NE Market Monitor Comments at 5; PJM/SPP Comments at
13.
---------------------------------------------------------------------------

    124. Several commenters ask the Commission to indicate the types of
verification processes it would accept.\285\ ISO-NE., MISO, and NYISO
state that their current process for developing and updating cost-based
incremental energy offers, known as reference levels, could comply with
the proposal as clarified to include estimated costs.\286\
---------------------------------------------------------------------------

    \285\ CEA Comments at 6; IRC Comments at 2.
    \286\ ISO-NE Comments at 6; MISO Comments at 8; NYISO Comments
at 2.
---------------------------------------------------------------------------

    125. CAISO states that the simplest method of verifying cost-based
incremental energy offers would involve reviewing a broker quote or
procurement invoice provided as evidence of a resource's costs, but
CAISO questions whether such information would be sufficient.\287\
CAISO predicts that incremental energy offers above $1,000/MWh are not
likely to be eligible to set the clearing price in CAISO and that
instead a resource with costs above $1,000/MWh would receive an uplift
payment, assuming that the resource's costs were verified after-the-
fact.\288\
---------------------------------------------------------------------------

    \287\ CAISO Comments at 11.
    \288\ Id.
---------------------------------------------------------------------------

    126. PJM/SPP state that the principles outlined in the NOPR are
sound, provided that the Final Rule allows RTOs/ISOs flexibility to
design verification procedures that are consistent with current RTO/ISO
rules.\289\ PJM/SPP outline conceptual initial proposals for
verification, but stress the need to provide RTOs/ISOs with latitude to
develop the final verification process with stakeholders.\290\ PJM
presents a possible verification process that involves an automatic
screen to filter out unreasonably high offers and to create a range of
reasonableness based on an

index of natural gas prices, the bid/ask spread, and resource heat
rates.\291\ PJM states that the verification requirement could use a
screening process that determines whether certain resources'
incremental energy offers in a given area are within ten percent or
$100/MWh of a benchmark offer based on a natural gas price index.\292\
SPP states that it could develop additional rules that facilitate
resources' submission of the fuel cost component of their cost-based
incremental energy offers that is consistent with the resource's actual
costs where possible, or that is a reasonably accurate representation
of those costs. SPP states that given the need to approximate fuel
costs that are difficult to verify, in most cases such a verification
process could be subject to a reasonable margin of error.\293\
---------------------------------------------------------------------------

    \289\ PJM/SPP Comments at 2-3.
    \290\ Id. at 14-21.
    \291\ Id. at 15-16.
    \292\ Id. at 16-17.
    \293\ Id. at 19.
---------------------------------------------------------------------------

    127. ISO-NE states that if its current cost verification process is
acceptable to the Commission, then the offer cap proposal may be
workable and would help improve price formation if high fuel prices
cause generation costs to exceed $1,000/MWh.\294\ MISO contends that
its current process to establish and adjust cost-based offers can be
used to verify incremental energy offers above $1,000/MWh.\295\ NYISO
also states that its current review process of a resource's incremental
energy costs could be used to satisfy the proposed verification
requirement.\296\
---------------------------------------------------------------------------

    \294\ ISO-NE Comments at 6.
    \295\ MISO Comments at 8.
    \296\ NYISO Comments at 3.
---------------------------------------------------------------------------

    128. The ISO-NE Market Monitor states that the Commission should
revise the proposed verification requirement to permit use of ISO-NE's
current Commission-approved process where a resource can update its
cost-based incremental energy offer, which occurs through a ``Fuel
Price Adjustment.'' \297\ The ISO-NE Market Monitor states that ISO-
NE's Fuel Price Adjustment mechanism balances the desire to reflect
resource costs in cost-based incremental energy offers, the limited
information the ISO-NE Market Monitor has available to verify costs,
and the need to deter abuse.\298\ The ISO-NE Market Monitor explains
that ISO-NE's market power mitigation software automatically calculates
cost-based incremental energy offers for resources, which may be based
on a day-ahead fuel price index.\299\
---------------------------------------------------------------------------

    \297\ ISO-NE Market Monitor Comments at 5-10.
    \298\ Id. at 5.
    \299\ Id. at 6.
---------------------------------------------------------------------------

    129. Potomac Economics states that MISO's current process for
developing and updating reference levels would comply with a Final Rule
which clarified that before-the-fact verification of a resource's
expected costs is acceptable.\300\ Potomac Economics explains that in
MISO, cost-based offers are calculated on the day before every
operating day based on next-day fuel price indices.\301\ In real-time,
the MISO Market Monitor (i.e., Potomac Economics), reviews natural gas
prices on ICE at various delivery points, and if natural gas prices
rise significantly compared to the next-day fuel index, the MISO Market
Monitor adjusts the cost-based incremental energy offers of any
affected resources.\302\ Potomac Economics adds that a MISO resource
can also consult with the Market Monitor and request to raise its cost-
based offer beyond this adjustment if the resource provides supporting
information, which may or may not be approved.\303\
---------------------------------------------------------------------------

    \300\ Potomac Economics Comments at 5.
    \301\ Id. at 4.
    \302\ Id. In MISO, cost-based offers are referred to as
reference levels.
    \303\ Id. at 5.
---------------------------------------------------------------------------

    130. Potomac Economics explains that a NYISO resource may also
request to update its cost-based incremental energy offer through a
software process that automatically permits such an increase, provided
the increase does not exceed a predetermined threshold.\304\ Potomac
Economics maintains that NYISO may need to adjust the validation
threshold to account for periods of unusually high fuel price
volatility, but that with such an adjustment, NYISO's current
verification process could comply with the proposal.\305\
---------------------------------------------------------------------------

    \304\ Id. NYISO states that a resource that updates the fuel
type or fuel cost information associated with its cost-based
incremental energy offer must make supporting documentation
available for NYISO's review after-the-fact. See NYISO Comments at
4.
    \305\ Potomac Economics Comments at 6.
---------------------------------------------------------------------------

    131. The PJM Market Monitor explains that resource owners in PJM
are responsible for submitting their own cost-based offers and fuel
cost policies, and that fuel costs are an essential part of the
verification process.\306\ The PJM Market Monitor states that it does
not have the authority to tell a resource owner what its fuel cost is
or what its offer should be, but it does have the authority to verify
cost-based offers, to discuss cost issues with resource owners, and to
refer resource owners to the Commission for rule violations and for the
attempted or actual exercise of market power.\307\ It states that it is
essential that the Commission impose significant penalties for rule
violations determined during the after-the-fact review. According to
the PJM Market Monitor, a resource should be required to have in place
a fuel cost policy that has been approved by both the PJM Market
Monitor and PJM before the resource is able to submit an offer in
excess of $1,000/MWh.\308\ The PJM Market Monitor states that if a
resource's cost-based incremental energy offer above $1,000/MWh is used
in the market clearing process, the PJM Market Monitor would perform a
timely after-the-fact review to determine whether a resource's offer
was based upon the best information available at the time the resource
submitted the cost-based incremental energy offer.\309\ The PJM Market
Monitor states that, in cases where an offer above $1,000/MWh is not
permitted, the PJM Market Monitor would perform a timely after-the-fact
review to determine the actual incurred costs of a resource, and uplift
would be paid if the costs exceeded the market clearing price.\310\ Any
uplift payments for such offers would be based on the actual gas cost
incurred. The PJM Market Monitor also recommends that the $1,000/MWh
offer cap apply to a resource's ``operating rate,'' which is calculated
by adding a resource's incremental offer to its no-load offer.\311\
---------------------------------------------------------------------------

    \306\ PJM Market Monitor Comments at 4-5.
    \307\ Id. at 5.
    \308\ Id. at 6.
    \309\ Id. at 7-8.
    \310\ Id.
    \311\ Id. at 2.
---------------------------------------------------------------------------

    132. The PJM Market Monitor also maintains that it is essential
that any verification process include a rigorous and timely after-the-
fact review and a requirement that a resource follows the cost-based
offer submission rules and abides by its approved fuel cost policy. The
PJM Market Monitor states that the verification process requires strong
compliance incentives, and the Commission should impose significant
penalties if a resource violates the cost-based incremental energy
offer guidelines.\312\
---------------------------------------------------------------------------

    \312\ Id. at 7.
---------------------------------------------------------------------------

    133. Commenters representing generator and load interests also
proposed verification processes. Competitive Suppliers and NEI state
that lifting the offer cap to a level that does not artificially
constrain LMPs is preferable to developing a verification process, as
removing the cap allows the market price to convey accurate information
of the state of the system even during high stress.\313\
---------------------------------------------------------------------------

    \313\ Competitive Suppliers Comments at 18; NEI Comments at 4.

---------------------------------------------------------------------------

    134. Competitive Suppliers prefer no verification requirement but
contends that if the Commission requires that all cost-based
incremental energy offers above $1,000/MWh be verified, the RTO/ISO and
the generator should be able to identify a set of accepted criteria and
data inputs such that resources can submit offers that can be accepted
and thus eligible to set LMP.\314\ Competitive Suppliers state that
PJM's Cost Development Guidelines provide a means of verifying resource
costs and may provide an alternative approach to the proposed
verification requirement.\315\
---------------------------------------------------------------------------

    \314\ Competitive Suppliers Comments at 19.
    \315\ Id.
---------------------------------------------------------------------------

    135. Exelon proposes that the Commission require RTOs/ISOs to adopt
tariff provisions that will permit timely review and approval of
resources' cost-based offers based on a resource-specific ``safe
harbor'' formula that is agreed upon in advance.\316\ Exelon proposes
that, at a minimum, the safe harbor formula should include a ten
percent uncertainty component and a fuel cost component based on a
daily natural gas index, natural gas adders, balancing costs,
transportation costs, and a risk adder.\317\
---------------------------------------------------------------------------

    \316\ Exelon Comments at 11.
    \317\ Id. at 17-20 (citing Testimony of Leslie O. Dedrickson at
29-31).
---------------------------------------------------------------------------

    136. Dominion supports a verification process that uses fuel
estimates based on recent prices, historical prices during similar
conditions, or a combination of both.\318\ Dominion would support
allowing market participants to submit cost-based offers within a
reasonable range of a reference price that would be based on a
historical fuel price index or an average of ask prices within a given
fuel market, and that offers which fall in the range of that reference
price and clear the market should be eligible to set LMP.\319\
---------------------------------------------------------------------------

    \318\ Dominion Comments at 5.
    \319\ Id.
---------------------------------------------------------------------------

    137. The New Jersey and Pennsylvania Commissions and OPSI maintain
that in order to implement the proposal in PJM, resources should be
required to have a fuel cost policy approved by the Market Monitoring
Unit prior to submission of cost-based incremental energy offers above
$1,000/MWh.\320\ The Pennsylvania Commission states that pre-approved
resource fuel cost policies in PJM would speed up the verification
process, foster market stability, and provide certainty to
resources.\321\ The New Jersey Commission and OPSI assert that resource
fuel cost policies should be derived from a verifiable, algorithmic,
and systematic approach consistent with the PJM Market Monitor's fuel
cost policy guidelines.\322\ The Delaware and Pennsylvania Commissions
and OPSI argue that PJM should clarify the role of PJM and the PJM
Market Monitor in the review and approval of fuel cost policies and
assert that the PJM Market Monitor should have the authority to verify
offers above $1,000/MWh.\323\
---------------------------------------------------------------------------

    \320\ New Jersey Commission Comments at 12-13; Pennsylvania
Commission Comments at 9; OPSI Comments at 7-9. This issue was also
raised in comments in PJM's offer flexibility proposal in Docket No.
ER16-372-000.
    \321\ Pennsylvania Commission Comments at 9.
    \322\ New Jersey Commission Comments at 13; OPSI Comments at 8
(citing Monitoring Analytics, Fuel Cost Policy Guidelines: Gas
Replacement Cost (Sept. 24, 2015), available at http://www.monitoringanalytics.com/reports/Market_Messages/Messages/IMM_Fuel_Cost_Policy_Guidelines_20150924.pdf).
    \323\ Delaware Commission Comments at 12; OPSI Comments at 7-9.
---------------------------------------------------------------------------

    138. SCE argues that each RTO/ISO should utilize its own
stakeholder processes to develop specific verification rules, which may
reflect regional factors such as differences in market power mitigation
processes and region-specific costs such as emissions and greenhouse
gas costs.\324\
---------------------------------------------------------------------------

    \324\ SCE Comments at 1-2.
---------------------------------------------------------------------------

3. Determination
    139. We adopt the NOPR proposal and clarify that each RTO/ISO or
Market Monitoring Unit is required to verify that any incremental
energy offer above $1,000/MWh reasonably reflects the associated
resource's actual or expected costs prior to using that offer to
calculate LMPs. We find that this verification requirement is necessary
for incremental energy offers above $1,000/MWh because market power
concerns are heightened when a resource's short-run marginal costs
exceed $1,000/MWh.
    140. Based on the record, it is not practical to require that RTOs/
ISOs or Market Monitoring Units verify a resource's actual costs in all
circumstances because a resource may not know its actual short-run
marginal costs at the time it submits an incremental energy offer to
the RTO/ISO for various reasons, including the timing of natural gas
procurement. Accordingly, we clarify that an RTO/ISO or a Market
Monitoring Unit must verify that cost-based incremental energy offers
above $1,000/MWh reasonably reflect a resource's actual or expected
costs. Under this requirement, the verification process for cost-based
incremental offers above $1,000/MWh must ensure that a resource's cost-
based incremental energy offer reasonably reflects that resource's
actual or expected costs.
    141. The RTO/ISO or Market Monitoring Unit, as prescribed in the
RTO/ISO tariff and consistent with Order No. 719,\325\ must verify the
costs within a cost-based incremental energy offer above $1,000/MWh
before that offer is used to calculate LMP, subject to the condition
that such offers are capped at $2,000/MWh for purposes of calculating
LMP.\326\ To create such a verification process, we expect that the
RTO/ISO would build on its existing mitigation processes for
calculating or updating cost-based incremental energy offers.\327\
However, we appreciate statements from RTOs/ISOs, market monitors, and
others about potential verification processes for incremental energy
offers above $1,000/MWh. We recognize that the verification process for
incremental energy offers may be a fact-specific inquiry, and we have
previously provided Market Monitoring Units with flexibility to make
case-specific determinations.\328\ Given the potential complexities
involved in verifying incremental energy offers as well as the
Commission's recognition of the need for proper mitigation methods in
energy markets, we will require that RTOs/ISOs explain in their
compliance filings what factors will be considered by the RTO/ISO or
its Market Monitoring Unit in the verification process for cost-based
incremental energy offers above $1,000/MWh and whether such factors are
currently considered in existing market power mitigation provisions or
whether new practices or tariff provisions are necessary given the
verification requirement adopted in this Final Rule. Therefore, we
disagree that the verification requirement is needlessly cumbersome
because RTOs/ISOs may build on existing processes for market power
mitigation.
---------------------------------------------------------------------------

    \325\ Wholesale Competition in Regions with Organized Electric
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at PP 370-375
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ]
31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ] 61,252
(2009). See also 18 CFR 35.28(g)(3)(iii)(B) (2016).
    \326\ Pursuant to 18 CFR 35.28(g)(3)(iii)(B), either the
internal or external market monitor can ``provide the inputs
required to conduct prospective mitigation . . . including, but not
limited to reference levels, identification of system constraints,
and cost calculations.'' 18 CFR 35.28(g)(3)(iii)(B) (2016). However,
prospective mitigation may only be carried out by an internal market
monitor if the RTO/ISO has a hybrid Market Monitoring Unit
structure. 18 CFR 35.28(g)(3)(iii)(D) (2016).
    \327\ NOPR, FERC Stats. & Regs. ] 32,714 at P 63.
    \328\ See New England Power Generators Association, Inc. v. ISO
New England Inc., 144 FERC ] 61,157, at P 62 (2015).
---------------------------------------------------------------------------

    142. Most RTOs/ISOs prohibit incremental energy offers above
$1,000/MWh, a prohibition that some market

monitors characterize as a backstop market power mitigation
measure.\329\ The offer cap adopted in this Final Rule retains the
backstop function that the current $1,000/MWh offer cap plays in
existing RTO/ISO market power mitigation because it limits incremental
energy offers that are not cost-based to $1,000/MWh. Under this Final
Rule, incremental energy offers below $1,000/MWh will remain subject to
existing market power mitigation measures. However, this Final Rule
will require that all incremental energy offers equal to and above
$1,000/MWh be cost-based, which essentially requires mitigation of all
incremental energy offers above $1,000/MWh.
---------------------------------------------------------------------------

    \329\ NOPR, FERC Stats. & Regs. ] 32,714 at P 23.
---------------------------------------------------------------------------

    143. In this way, the verification requirement requires RTOs/ISOs
to make only an incremental change to their existing market power
mitigation procedures because the market power mitigation provisions
that apply to incremental energy offers below $1,000/MWh will be
unchanged. While in this Final Rule we increase the offer cap for cost-
based incremental energy offers, we also subject offers above $1,000/
MWh to additional market power mitigation in the form of the
verification requirement. The verification requirement is designed to
ensure that a cost-based incremental energy offer above $1,000/MWh is
not an attempt by the associated resource to exercise market power. The
verification requirement is part-and-parcel with the increase of the
offer cap for cost-based incremental energy offers. We find that it
would be inappropriate to raise the offer cap without imposing a
verification requirement. The verification requirement thus serves as
an additional backstop market power mitigation measure.\330\
---------------------------------------------------------------------------

    \330\ Moreover, existing Commission regulations establish that
misrepresenting costs when submitting cost-based incremental energy
offers as part of a supply offer may be in violation of 18 CFR
35.41(b) (2016) and 18 CFR 1c.2(a)(2) (2016).
---------------------------------------------------------------------------

    144. Contrary to Potomac Economics' assertion that competition is
not diminished when short-run marginal costs rise above $1,000/MWh, we
find that market power concerns are heightened during such periods
because short-run marginal costs in this range may indicate that very
few resources are available to provide additional supply. Supply may be
limited during such periods because of fuel supply limitations or the
physical limitations of resources (e.g., ramping constraints).
Accordingly, resources with available supply during such periods likely
face little competition, particularly in real-time, and may therefore
be able to exercise market power. We find that the verification
requirement reasonably addresses market power concerns associated with
incremental energy offers above $1,000/MWh because such offers will be
required to be cost-based, which should deter attempts by resources to
exercise market power.
    145. As discussed above, this Final Rule will require RTOs/ISOs to
limit incremental energy offers to $2,000/MWh when calculating LMPs,
which may be below the cost-based incremental energy offer of a
resource. Thus, we revise the verification requirement proposed in the
NOPR as indicated below and add new language (underlined below) to
account for any uplift associated with the $2,000/MWh hard cap and
adopt the following verification requirement:

    The costs underlying a resource's cost-based incremental energy
offer above $1,000/MWh must be verified before that offer can be
used for purposes of calculating Locational Marginal Prices. If a
resource submits an incremental energy offer above $1,000/MWh and
the costs underlying that offer cannot be verified before the market
clearing process begins, that offer may not be used to calculate
Locational Marginal Prices and the resource would be eligible for a
make-whole payment if that resource is dispatched and the resource's
costs are verified after-the-fact. A resource would also be eligible
for a make-whole payment if it is dispatched and its verified cost-
based incremental energy offer exceeds $2,000/MWh.

    146. We will retain the proposal in the NOPR which ensures that, if
a resource's incremental energy offer above $1,000/MWh is not verified
but that resource is nonetheless dispatched, that resource would be
eligible to receive an uplift payment to recover its verified costs.
The basis of the uplift payment would be the difference between a given
resource's energy market revenues and that resource's actual short-run
marginal costs of the MWs dispatched, as verified after-the-fact by the
RTO/ISO or Market Monitoring Unit.\331\ We find that such uplift
payments are necessary given the challenges associated with the
verification processes, to ensure that resources have an incentive to
offer into RTO/ISO energy markets, and to ensure that resources are
compensated for the service they provide.
---------------------------------------------------------------------------

    \331\ The Commission notes that the clarification regarding use
of a resource's actual or expected short-run marginal costs during
the verification process that occurs prior to the market clearing
process is not applicable to such uplift payments. Any such uplift
payment, which is paid after-the-fact, must be based on a resource's
actual short-run marginal costs.
---------------------------------------------------------------------------

    147. This Final Rule will permit regional variation in the process
for treating incremental energy offers above $1,000/MWh that the RTO/
ISO or Market Monitoring Unit cannot verify prior to the start of the
market clearing process. For example, the RTO/ISO could have procedures
to change the incremental energy offer to $1,000/MWh or to mitigate
that offer to a level below $1,000/MWh pursuant to other applicable
market power mitigation provisions.

C. Resource Neutrality

1. NOPR Proposal
    148. In the NOPR, the Commission proposed the following resource
neutrality requirement:

    All resources, regardless of type, are eligible to submit cost-
based incremental energy offers in excess of $1,000/MWh.\332\
---------------------------------------------------------------------------

    \332\ NOPR, FERC Stats. & Regs, ] 32,714 at P 69.

    The Commission reasoned that this requirement would ensure that the
eligibility to submit cost-based incremental energy offers in excess of
$1,000/MWh would not be applied in an unduly discriminatory or unduly
preferential manner.\333\ The Commission also stated that the proposed
resource neutrality requirement is consistent with prior orders related
to the offer cap in PJM and MISO.\334\
---------------------------------------------------------------------------

    \333\ Id.
    \334\ Id. (citing MISO 2014/15 Offer Cap Order, 150 FERC ]
61,083 at P 16; PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P
39).
---------------------------------------------------------------------------

2. Comments
    149. Several commenters support the proposed resource neutrality
requirement.\335\ For example, MISO supports the resource neutrality
requirement and notes that the MISO tariff currently allows any
resource, regardless of type, to establish a cost-based reference
level.\336\ MISO adds that some resources could be constrained by the
$1,000/MWh cap because they may be unable to provide evidence of high
fuel costs.\337\
---------------------------------------------------------------------------

    \335\ EEI Comments at 1, 3; Ohio Commission Comments at 12; MISO
Comments at 12.
    \336\ MISO Comments at 12 (citing MISO Tariff, Module D,
64.1.4.a, 64.3.a, and 64.1.4.h).
    \337\ Id.
---------------------------------------------------------------------------

    150. Commenters disagree about whether demand response resources
should be able to submit incremental energy offers above $1,000/MWh.
Some commenters argue that demand response resources should be treated
the same as other physical generation resources that provide
offers.\338\

Additionally, MISO questions why a demand response resource should be
prevented from submitting an offer at the same level (in $/MWh) as
physical resources.\339\
---------------------------------------------------------------------------

    \338\ API Comments at 12-13; Competitive Suppliers Comments at
23-24; Exelon Comments at 23 (citing PJM Manual 11 2.3.3);
Industrial Customers Comments at 28; PJM Market Monitor Comments at
12-13.
    \339\ MISO Comments at 7.
---------------------------------------------------------------------------

    151. However, other commenters argue that demand response should
not be able to submit incremental energy offers above $1,000/MWh. PJM/
SPP argue that the proposed offer cap revisions should not apply to
demand response resources because demand response resource offers are
intended to capture foregone commercial revenues, not the short-run
marginal cost of reducing output.\340\ ISO-NE asserts that a demand
response resource's costs would be based on its marginal opportunity
cost of foregone consumption, which could routinely exceed $1,000/MWh
or $2,000/MWh, and that verifying such costs could not be accomplished
on short notice. ISO-NE surmises that allowing demand resources to
submit incremental energy offers above $1,000/MWh could create perverse
incentives and may give physical resources the incentive to move behind
the meter to exploit asymmetries in the application of the offer cap.
Accordingly, ISO-NE requests that the Commission carefully consider its
position on verification of the actual costs of demand response
resources.\341\
---------------------------------------------------------------------------

    \340\ PJM/SPP Comments at 5.
    \341\ ISO-NE Comments at 7-8.
---------------------------------------------------------------------------

    152. The New Jersey Commission argues that in the absence of a
comprehensive definition of short-run marginal costs for demand
response resource offers, demand response resources should not be
permitted to offer and set the market clearing price above the
Commission's determined offer cap.\342\ The Pennsylvania Commission
asserts that demand response resources should not be eligible to set
LMP and should be treated as price takers, asserting that such
resources do not generally exhibit competitive behavior in energy
markets because the energy revenues of such resources are de minimis
relative to their capacity market revenues.\343\
---------------------------------------------------------------------------

    \342\ New Jersey Commission Comments at 18.
    \343\ Pennsylvania Commission Comments at 14 (citing PJM, Demand
Response Operations Market's Activity Report: February 2016 (Feb.
16, 2016), Fig. 23; Monitoring Analytics, LLC, State of the Markets
Report for PJM, Vol. 1., Fig. 10 (Mar. 10, 2016)).
---------------------------------------------------------------------------

    153. Several commenters express concerns about whether RTOs/ISOs or
Market Monitoring Units can verify the costs of demand response
resources. For example, ISO-NE asserts that a demand response
resource's costs would be based on that resource's marginal opportunity
cost of foregone consumption and other information that is difficult to
validate, particularly if the demand response resource's costs increase
significantly from the prior day.\344\ PJM/SPP state that it is not
clear what demand response resource costs could be validated to justify
an offer above the $1,000/MWh offer cap.\345\ The Pennsylvania
Commission states that with the limited exception of on-site backup
generation costs, the incremental energy costs of demand response
capacity resources are largely unknown.\346\ ISO-NE urges the
Commission to carefully consider whether the verification of actual
costs should be imposed on a resource-neutral basis, and explains its
concerns regarding its ability to timely verify the offers of demand
response resources.\347\ AEMA argues that it is impractical, if not
impossible, to verify the costs of a demand response resource in the
same manner as a physical generation resource, particularly before-the-
fact.\348\ AEMA also cites a prior Commission order on ISO-NE's Order
No. 745 compliance where the Commission found that ``unlike with supply
resources, it would be very difficult to develop a competitive offer or
reference price to which to mitigate each demand response resource.''
\349\ AEMA asserts that there is no need to create an additional
verification requirement for demand response resources, because the
Commission has recognized that comparability does not require identical
treatment.\350\
---------------------------------------------------------------------------

    \344\ ISO-NE Comments at 7-8.
    \345\ PJM/SPP Comments at 5.
    \346\ Pennsylvania Commission Comments at 14.
    \347\ ISO-NE Comments at 7-8.
    \348\ AEMA Comments at 7-8.
    \349\ Id. at 8 (citing ISO New England Inc., 138 FERC ] 61,042,
at P 138 (2012)).
    \350\ Id. at 8-9 (citing Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890, FERC Stats. &
Regs. ] 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs.
] 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299,
at P 216 (2008), order on reh'g, Order No. 890-C, 126 FERC ] 61,228,
order on clarification, Order No. 890-D, 129 FERC ] 61,126 (2009);
Indep. Market Monitor for PJM v. PJM Interconnection, L.L.C., 155
FERC ] 61,059, at P 31 (2016) (``comparability does not require
identical application to demand response resources and generation
resources of PJM's offer cap and the must-offer requirement'')).
---------------------------------------------------------------------------

    154. AEMA requests that the Commission clarify that the offer cap
proposed in the NOPR only impacts demand response resources that
participate in energy markets and would not apply to demand resources
that exclusively participate in capacity markets.\351\ AEMA explains
that demand response resources that participate exclusively in capacity
markets do not make incremental energy offers. AEMA explains that
capacity-only demand response resources are only dispatched on a
reliability-based trigger that determines the price the demand resource
is paid as opposed to an offer price-based trigger that does not
represent the LMP at which the customer wishes to be dispatched, or the
costs of the customer to curtail its load. AEMA asserts that forcing
these resources to make ``incremental energy offers'' in the energy
market would drive them away from participation.\352\
---------------------------------------------------------------------------

    \351\ Id. at 3.
    \352\ Id. at 3-5.
---------------------------------------------------------------------------

    155. AEMA requests that the Commission continue to allow demand
response resources to submit offers up to the offer cap in energy
markets and not impose additional verification requirements on demand
response resource energy market offers beyond what has already been
accepted.\353\ AEMA asserts that the Final Rule should not impact
existing or proposed methods for monitoring and evaluating demand
resource offers in energy markets or create additional verification
hurdles for demand resource offers beyond those that currently
exist.\354\
---------------------------------------------------------------------------

    \353\ Id. at 5-6.
    \354\ Id. at 2-3, 7-9.
---------------------------------------------------------------------------

3. Determination
    156. We adopt the NOPR proposal and find that resources with costs
above $1,000/MWh should be able to submit cost-based incremental energy
offers to recover their costs, regardless of the type of resource.
Prohibiting a particular set of resources from submitting cost-based
incremental energy offers above $1,000/MWh could preclude them from
recovering their costs.
    157. In the NOPR the term ``resource'' referred to all supply
resources, including demand response resources, that offer incremental
energy to RTO/ISO energy markets.\355\ As such, a demand response
resource that submits incremental energy offers to the energy market
based on short-run marginal cost would be subject to the verification
requirement if that incremental energy offer exceeds $1,000/MWh. For
such a resource, the short-run marginal cost may equal its opportunity
costs.
---------------------------------------------------------------------------

    \355\ This is consistent with prior uses of the term. See, e.g.,
Settlement Intervals and Shortage Pricing in Markets Operated by
Regional Transmission Organizations and Independent System
Operators, Order No. 825, 81 FR 42,882 (June 30, 2015), FERC Stats.
& Regs. ] 31,384, at P 98 (2016).
---------------------------------------------------------------------------

    158. We recognize that the verification process for demand response
resources will necessarily differ from the verification process for
generation resources, as noted by ISO-NE and AEMA. The Commission has

recognized that demand response resources should receive comparable,
but not necessarily identical treatment to generation resources.\356\
However, we decline AEMA's request to exempt demand response resources
that submit incremental energy offers in RTO/ISO energy markets from
any additional verification requirements associated with this Final
Rule, because such an exemption does not constitute comparable
treatment. However, as noted above,\357\ this Final Rule does not
prescribe how RTOs/ISOs should verify cost-based incremental energy
offers above $1,000/MWh, including offers from demand response
resources.
---------------------------------------------------------------------------

    \356\ Demand Response Compensation in Organized Wholesale Energy
Markets, Order No. 745, FERC Stats. & Regs. ] 31,322, at P 66, order
on reh'g and clarification, Order No. 745-A, 137 FERC ] 61,215
(2011) (``as a general matter demand response providers and
generators should be subject to comparable rules that reflect the
characteristics of the resource.'').
    \357\ See supra P 141.
---------------------------------------------------------------------------

    159. Finally, we find that the New Jersey and Pennsylvania
Commissions' comments that demand response resources should not be able
to set LMP are beyond the scope of this Final Rule, which only applies
to incremental energy offers above $1,000/MWh, and not the general
eligibility of demand response resources to set LMPs in RTO/ISO energy
markets. We clarify, however, that reforms adopted in this Final Rule,
which provide that resources are eligible to submit cost-based
incremental energy offers in excess of $1,000/MWh and require that
those offers be verified, do not apply to capacity-only demand response
resources that do not submit incremental energy offers in energy
markets.

V. Other Issues

A. Virtual Transactions

    160. Although the Commission preliminarily found in the NOPR that
virtual supply offers and virtual demand bids (virtual transactions)
could not provide a cost basis for offers above $1,000/MWh, it sought
comment about whether prohibiting virtual transactions above $1,000/MWh
could limit hedging opportunities, present opportunities for
manipulation or gaming, create market inefficiencies, or have other
undesirable consequences.\358\
---------------------------------------------------------------------------

    \358\ NOPR, FERC Stats. & Regs ] 32,714 at PP 64, 73.
---------------------------------------------------------------------------

1. Comments
    161. CAISO states that virtual transactions do not face short-run
marginal production costs and would thus be unable to justify costs
above $1,000/MWh.\359\ However, CAISO notes that if physical resources
can submit incremental energy offers above $1,000/MWh, then virtual
participants should also be able to bid above $1,000/MWh to arbitrage
those physical offers.\360\
---------------------------------------------------------------------------

    \359\ CAISO Comments at 13.
    \360\ Id.
---------------------------------------------------------------------------

    162. ISO-NE states that market participants should be able to
submit virtual supply offers at levels as high as offers from physical
resources to ensure that there is a liquid supply of offers that can
compete with physical resources in the day-ahead market under all
market conditions, which can reduce the potential exercise of market
power during tight day-ahead conditions.\361\ ISO-NE asserts that if
the Commission adopts a new hard cap, there is no cost-basis or market
power rationale to limit virtual supply offers below the level of any
hard cap.\362\
---------------------------------------------------------------------------

    \361\ ISO-NE Comments at 8.
    \362\ Id. at 8-9.
---------------------------------------------------------------------------

    163. PJM argues that virtual transactions should be permitted to
exceed $1,000/MWh or be subject to a reasonableness screen because
virtual transactions increase competition in the day-ahead markets and
reduce market share, and thus reduce market power.\363\ MISO states
that prohibiting virtual transactions above $1,000/MWh could limit
hedging opportunities which could increase the price differentials
between the day-ahead and real-time energy markets.\364\ MISO adds that
revising the offer cap for virtual transactions could conceivably
expose other market participants to high prices but notes that MISO
already has mitigation measures in place for virtual transactions and
that years of market experience have shown that such manipulation
concerns are improbable.\365\
---------------------------------------------------------------------------

    \363\ PJM/SPP Comments at 27.
    \364\ MISO Comments at 18; see also PJM/SPP Comments at 27-28.
    \365\ MISO Comments at 18.
---------------------------------------------------------------------------

    164. NYISO states that cost-based incremental energy offers,
interchange transactions (e.g., imports and exports), and virtual
transactions should be capped at the level of the hard cap, which will
allow market participants to continue to compete to the maximum extent
practicable.\366\ NYISO also argues that a hard cap is appropriate for
virtual transactions because such transactions are based on price
expectations as opposed to verifiable costs.\367\ SPP states that it
takes no position on the application of the proposed reforms to virtual
transactions.\368\
---------------------------------------------------------------------------

    \366\ NYISO Comments at 7-8.
    \367\ Id. at 7.
    \368\ PJM/SPP Comments at 28.
---------------------------------------------------------------------------

    165. Potomac Economics states that competitive virtual transactions
should be permitted to exceed $1,000/MWh when real-time prices are
expected to exceed $1,000/MWh.\369\ Potomac Economics states that
although virtual transactions do not have production costs, they do
have marginal costs, and notes that the marginal cost of selling
virtual energy in the day-ahead market is the expected cost of buying
the energy in the real-time market.\370\ Potomac Economics states that
virtual transactions support the competitive performance of day-ahead
markets and thus argues that it is important to structure the rules for
virtual transactions in a manner that does not impede their
participation in the market.\371\
---------------------------------------------------------------------------

    \369\ Potomac Economics Comments at 10.
    \370\ Id.
    \371\ Id.
---------------------------------------------------------------------------

    166. Potomac Economics proposes that virtual transactions be
permitted to exceed $1,000/MWh when real-time LMPs are expected to
exceed $1,000/MWh for more than a specified period (e.g., 30
minutes).\372\ The PJM Market Monitor argues that market participants
should not be permitted to submit virtual transactions above $1,000/MWh
because increasing the offer cap on virtual transactions would create
opportunities for the exercise of market power and manipulation of
markets and permit resource owners to avoid the requirement that
incremental energy offers above $1,000/MWh be cost-based.\373\ The PJM
Market Monitor states there is no evidence that virtual supply offers
have increased competition or would increase competition in extreme
circumstances.\374\ The PJM Market Monitor recommends that if the
Commission wishes to permit some virtual transactions to exceed $1,000/
MWh, the Commission should: (1) Limit virtual transactions above
$1,000/MWh to liquid trading hubs; (2) require market participants to
explain why virtual offers or bids above $1,000/MWh are appropriate;
and (3) subject such virtual transactions to a ``reasonableness
screen'' and an after-the-fact review for whether they resulted in
manipulation or market power.\375\ The PJM Market Monitor states that
the asserted benefits of virtuals with respect to hedging, competition,
and price convergence have not been empirically established, and, thus,
it is unnecessary to create

market power risks when revising the offer cap.\376\
---------------------------------------------------------------------------

    \372\ Id. at 9-10.
    \373\ PJM Market Monitor Comments at 11; PJM Market Monitor
Answer at 6.
    \374\ PJM Market Monitor Answer at 5.
    \375\ PJM Market Monitor Comments at 11-12.
    \376\ PJM Market Monitor Answer at 5.
---------------------------------------------------------------------------

    167. Separately, the PJM Market Monitor recommends that up-to-
congestion transactions in PJM be excluded from any offer cap reforms
stating that because up-to-congestion transactions are spread bids
between nodes there is no reason to relax the current rules that govern
such transactions.\377\
---------------------------------------------------------------------------

    \377\ PJM Market Monitor Comments at 11; PJM Market Monitor
Answer at 6.
---------------------------------------------------------------------------

    168. Several commenters argue that the Commission should allow
virtual transactions to exceed $1,000/MWh.\378\ Some commenters focus
on the use of virtual transactions to hedge physical transactions and
argue that virtual transactions should thus be subject to the same
offer caps as physical resources.\379\ Dominion states that in extreme
winter conditions, a physical resource that faces a start-up risk and
is likely to receive a day-ahead award may submit a virtual demand bid
to hedge against the potential outage in real-time.\380\ Exelon also
argues that hedging the risk of physical transactions through virtual
transactions is especially important when the system is stressed, and
that doing so may improve market performance by converging day-ahead
and real-time prices.\381\ Competitive Suppliers assert that the same
argument articulated in the NOPR for having a uniform offer cap across
regions demands similar treatment of virtual transactions, imports, and
emergency demand response across regions.\382\
---------------------------------------------------------------------------

    \378\ Competitive Suppliers Comments at 23-24; Dominion Comments
at 7; Exelon Comments at 23-24; ISO-NE Comments at 8; PJM/SPP
Comments at 27; SPP Market Monitor Comments at 12; NY Department of
State Comments at 6.
    \379\ SPP Market Monitor Comments at 12; Competitive Suppliers
Comments at 23-24; NY Department of State Comments at 6; Dominion
Comments at 7.
    \380\ Dominion Comments at 7.
    \381\ Exelon Comments at 23-24.
    \382\ Competitive Suppliers Comments at 23.
---------------------------------------------------------------------------

    169. Dominion states that limiting the ability to submit virtual
transactions above $1,000/MWh to physical resources with verified cost-
based incremental energy offers above $1,000/MWh in order to allow such
resources to hedge would minimize concerns about market
manipulation.\383\ The PJM Market Monitor responds that Dominion's
proposal creates a significant risk of manipulation because Dominion
does not propose to limit the virtual bids to the cost-based offer of
the generator.\384\
---------------------------------------------------------------------------

    \383\ Dominion Comments at 7.
    \384\ PJM Market Monitor Answer at 6.
---------------------------------------------------------------------------

    170. Several other commenters argue that virtual transactions
should be prohibited from submitting transactions above $1,000/
MWh.\385\ For example, several commenters argue that virtual
transactions should not be permitted to exceed $1,000/MWh because
allowing transactions in this range could raise clearing prices without
a commensurate increase in short-run marginal production costs.\386\
Six Cities argues that permitting virtual transactions to submit offers
above the $1,000/MWh cap would be inconsistent with the Commission's
goals of allowing recovery of actual production costs in excess of the
cap and establishing LMPs consistent with actual production costs under
extreme market conditions.\387\ TAPS argues that the Commission does
not need to allow virtual transactions to exceed $1,000/MWh to
encourage price convergence between the day-ahead and real-time
markets.\388\
---------------------------------------------------------------------------

    \385\ APPA, NRECA, and AMP Comments at 19; Industrial Customers
Comments at 28-29; Ohio Commission Comments at 14; New Jersey
Commission Comments at 17-18; Six Cities Comments at 3.
    \386\ Industrial Customers Comments at 28-29; New Jersey
Commission Comments at 17-18; Six Cities Comments at 3; Ohio
Commission Comments at 14; TAPS Comments at 20-21.
    \387\ Six Cities Comments at 4.
    \388\ TAPS Comments at 21.
---------------------------------------------------------------------------

    171. Some commenters argue, as the PJM Market Monitor does, that
allowing virtual transactions above the $1,000/MWh cap could lead to
undesirable consequences, such as creating the opportunity for market
manipulation and the exercise of market power.\389\ For example, SCE
cautions that allowing virtuals above $1,000/MWh would undermine the
purpose of having a backstop for existing market power mitigation
rules.\390\ APPA, NRECA, and AMP state that although they oppose the
idea, any proposal to allow virtual transactions above $1,000/MWh must
be accompanied by an assurance that the RTO/ISO and/or Market
Monitoring Unit will be able to address any gaming or anti-competitive
conduct.\391\ PG&E asks that the Commission direct market monitors to
study the potential impacts and gaming opportunities associated with
permitting virtual transactions above $1,000/MWh before revising any
caps on virtual transactions.\392\ Midcontinent Joint Consumer
Advocates state that while it generally supports applying the same
offer cap to physical and virtual transactions, the issue should be
monitored to ensure that inappropriate virtual transactions do not
affect real-time energy prices.\393\ The Delaware Commission recommends
that virtual transactions in PJM be limited to $400/MWh.\394\
---------------------------------------------------------------------------

    \389\ APPA, NRECA, and AMP Comments at 19; ODEC Comments at 1;
KEPCo/NCEMC Comments at 5; New Jersey Commission Comments at 18; PJM
Market Monitor Comments at 11-12; TAPS Comments at 21.
    \390\ SCE Comments at 2.
    \391\ APPA, NRECA, and AMP Comments at 19.
    \392\ PG&E Comments at 3-4.
    \393\ Midcontinent Joint Consumer Advocates Comments at 9.
    \394\ Delaware Commission Comments at 14. The Delaware
Commission recommends that in PJM, virtual transactions and
incremental energy offers that are not cost-based be limited to
$400/MWh.
---------------------------------------------------------------------------

2. Determination
    172. In light of the comments received and our adoption of a
$2,000/MWh hard cap, we find that it is just and reasonable to permit
market participants to submit virtual transactions up to $2,000/MWh. We
do not require that virtual transactions be subject to the cost
verification described above. Allowing virtual transactions above
$1,000/MWh could improve price convergence between day-ahead and real-
time markets.\395\ An offer cap that is lower for virtual transactions
than for physical resources could increase divergence between day-ahead
and real-time LMPs. This finding is consistent with prior Commission
precedent, which finds it is reasonable to permit market participants
to submit virtual transactions at levels commensurate with the levels
that real-time LMPs can reach.\396\
---------------------------------------------------------------------------

    \395\ PJM Interconnection, L.L.C., 139 FERC ] 61,057 (2012).
    \396\ Id. PP 123-126. In that order, the Commission found that
``if virtual traders and demand cannot submit higher bids in the
day-ahead market [commensurate with the $/MWh value that real-time
LMPs can reach if shortage pricing is in effect], that market may
not converge with prices in the real-time market during times when
PJM experiences shortage conditions in the real-time market.'' Id. P
124.
---------------------------------------------------------------------------

    173. We find that market participants should be allowed to submit
virtual transactions up to the hard cap, as they can today. As such,
this Final Rule is therefore less likely to result in unintended
consequences associated with capping virtual transactions at a level
below the hard cap. For example, capping virtual transactions at
$1,000/MWh when the incremental energy offers used to calculate LMPs
are capped at $2,000/MWh could encourage some market participants to
place virtual demand bids at $1,000/MWh, a transaction that may be
profitable if real-time prices exceed $1,000/MWh but would not
contribute to day-ahead and real-time price convergence.
    174. Under this Final Rule, LMPs may rise above $1,000/MWh. By
permitting virtual transactions to exceed $1,000/MWh, we preserve a
market participant's ability to use virtual

transactions to hedge its exposure to real-time LMPs above $1,000/MWh.
Otherwise, if virtual transactions are limited to $1,000/MWh, as
proposed in the NOPR, a market participant would be barred from placing
virtual transactions commensurate with its market risks.
    175. We also find that allowing virtual transactions above $1,000/
MWh may add liquidity to day-ahead markets. Permitting virtual
transactions in the $1,000/MWh--$2,000/MWh range could result in
additional demand bids and supply offers (i.e., virtual demand bids and
virtual supply offers) and will thus allow virtual transactions to
continue to perform the functions that they do today by adding
liquidity to the day-ahead market.
    176. We recognize that virtual transactions, by their nature,
cannot be subjected to the type of cost-verification discussed above.
However, in response to comments arguing that virtual transactions
above $1,000/MWh will raise LMPs above verifiable costs and/or result
in market power abuse, we note that Market Monitoring Units currently
monitor for anti-competitive behavior by market participants. While
they are not required to do so, if RTOs/ISOs determine that additional
measures are necessary to address any concerns that arise from
permitting virtual transactions up to $2,000/MWh, RTOs/ISOs may propose
such additional measures in a separate filing under section 205 of the
Federal Power Act.
    177. Dominion proposes to limit the ability to submit virtual
transactions above $1,000/MWh to physical resources that have cost-
based offers above $1,000/MWh. We find that Dominion's proposal to
limit virtual transactions to certain market participants would be
unduly discriminatory. Such a limitation would treat market
participants differently depending on whether they owned physical
generation assets, and would be unduly discriminatory because it would
limit the benefits of virtual transactions above $1,000/MWh to those
participants with physical assets. Further, such a limitation could
limit the other potential benefits of virtual transactions above
$1,000/MWh, such as increased liquidity and increased convergence
between day-ahead and real-time LMPs. Additionally, we find that the
PJM Market Monitor's and Potomac Economics' proposals to limit virtual
transactions above $1,000/MWh to certain time periods or certain
locations lack sufficient detail and record evidence to make a finding
that either proposal is just and reasonable. Finally, we clarify that
this Final Rule does not apply to up-to-congestion transactions in PJM,
because such transactions are spread bids and not virtual supply offers
or virtual demand bids.

B. External Transactions

    178. In the NOPR, the Commission stated that external RTO/ISO
resources (i.e., imports) would not be eligible to submit cost-based
incremental energy offers above $1,000/MWh because RTO/ISO processes to
develop cost-based incremental energy offers for mitigation purposes
typically only apply to internal RTO/ISO resources.\397\ The Commission
added, however, that it would consider RTO/ISO proposals to verify
cost-based incremental energy offers from external transactions in
their respective compliance filings.\398\ The Commission also sought
comment on whether the offer cap proposal should apply to imports and
whether a cost verification process for import transactions is
feasible.\399\
---------------------------------------------------------------------------

    \397\ NOPR, FERC Stats. & Regs ] 32,714 at P 63.
    \398\ Id.
    \399\ Id. PP 63, 73.
---------------------------------------------------------------------------

1. Comments
    179. CAISO maintains that the consistent treatment of internal
resources and external resources (e.g., imports) is key to an efficient
market and to avoid unintended consequences.\400\ CAISO surmises that
capping import offers to a level below the cap that internal resource
incremental energy offers are subject to could reduce supply offers
from imports during periods when natural gas prices in the West rise to
a level that would justify LMPs above $1,000/MWh.\401\
---------------------------------------------------------------------------

    \400\ CAISO Comments at 13.
    \401\ Id.
---------------------------------------------------------------------------

    180. ISO-NE states that it cannot verify the costs associated with
energy import transactions in real-time.\402\ ISO-NE explains that an
importer's actual cost to import power into ISO-NE from an adjacent
market is the adjacent market's real-time LMP, which is determined at
the same time as ISO-NE's LMP. ISO-NE adds that, given the lack of
organized markets in some control areas adjacent to ISO-NE., it is
unclear how actual costs would be verified for import transactions from
those areas. Accordingly, ISO-NE requests additional guidance from the
Commission about the application of the proposed rule to imports and
exports.\403\
---------------------------------------------------------------------------

    \402\ ISO-NE Comments at 9.
    \403\ Id.
---------------------------------------------------------------------------

    181. PJM asserts that non-emergency imports should be allowed to
submit offers above $1,000/MWh to ensure that economic import
transactions occur even when PJM LMPs exceed $1,000/MWh because such
purchases and sales will benefit the market and provide electric
supplies by allowing the lowest cost energy to serve customers.\404\
PJM adds that imports may also defer operational emergency procedures
in extreme situations.\405\
---------------------------------------------------------------------------

    \404\ PJM/SPP Comments at 25.
    \405\ Id.
---------------------------------------------------------------------------

    182. PJM explains that under PJM's current rules, economic
transactions are capped at the maximum energy price (absent congestion
and losses) of $2,700/MWh while emergency import transactions are not.
PJM states that the value of lost load may exceed this level and states
that PJM is thus willing to pay more than $2,700/MWh to procure
emergency energy to prevent load shedding.\406\ PJM notes that the
verification of import's cost would have to follow a different process
than internal resources because the resource behind the import is
frequently unknown.\407\
---------------------------------------------------------------------------

    \406\ Id. at 26 (citing PJM, Intra-PJM Tariffs, OATT, Tariff
Operating Agreement, Attachment K-Appendix, section 3.2.3.A).
    \407\ Id.
---------------------------------------------------------------------------

    183. SPP states that verifying the costs of imports could be
problematic because it is difficult to obtain cost information from
resources outside of SPP.\408\ SPP asks the Commission to allow
regional flexibility for this issue, noting that it would investigate
the issue further in response to any Final Rule issued in this
proceeding.\409\
---------------------------------------------------------------------------

    \408\ Id. at 27.
    \409\ Id.
---------------------------------------------------------------------------

    184. According to the PJM Market Monitor, 99.99 percent of PJM
imports are price takers but imports that are not price takers should
continue to be limited to $1,000/MWh offers.\410\ Potomac Economics
contends that external transactions should be eligible to submit offers
above $1,000/MWh when prices in the real-time market exceed $1,000/MWh
for more than a specified period of time (e.g., 30 minutes). Potomac
Economics also asserts that Coordinated Transaction Schedules should be
exempt from the proposed reforms because they reflect a forecast of the
price spread between RTO/ISO markets and thus would not set the LMP in
either market.\411\
---------------------------------------------------------------------------

    \410\ PJM Market Monitor Comments at 10.
    \411\ Potomac Economics Comments at 9-10.
---------------------------------------------------------------------------

    185. The SPP Market Monitor states that the proposed offer cap
requirements should apply to imports because imports have the same
potential impact on LMPs as internal resources. However, the SPP Market
Monitor acknowledges that it is more challenging to verify the offers
of

imports as compared to offers from internal SPP resources because the
SPP market monitor may have limited access to the cost data of external
resources.\412\
---------------------------------------------------------------------------

    \412\ SPP Market Monitor Comments at 11.
---------------------------------------------------------------------------

    186. Several commenters assert that imports should be able to offer
above $1,000/MWh provided the costs in their offers are verified
beforehand,\413\ and some commenters say it is possible to develop a
workable solution for such verification.\414\ For example, the New
Jersey Commission argues that imports that clear the PJM capacity
auctions, which are pseudo-tied, will have short-run marginal
production costs that are available for the market monitor to review,
and should thus be permitted to offer into the PJM energy market above
$1,000/MWh when their costs exceed $1,000/MWh.\415\ Midcontinent Joint
Consumer Advocates explain that offers from imports are provided in the
day-ahead market and then only scheduled in real-time, and imports
cannot set real-time LMPs in MISO.\416\ However, Midcontinent Joint
Consumer Advocates state that if imports are the source of higher
prices in MISO markets, then it would be important to verify the costs
of imports and in such cases, Midcontinent Joint Consumer Advocates
would support verification for imports so that all suppliers are
treated equally.\417\ The Delaware Commission supports the NOPR
proposal to require verification of exchange transactions provided the
process in an exporting region is not less objective or rigorous than
the process in the importing region.\418\
---------------------------------------------------------------------------

    \413\ Delaware Commission Comments at 13; Midcontinent Joint
Consumer Advocates Comments at 8; Ohio Commission Comments at 13;
Six Cities Comments at 3.
    \414\ Midcontinent Joint Consumer Advocates Comments at 8; Six
Cities Comments at 3; CEA Comments at 7-8.
    \415\ New Jersey Commission Comments at 18.
    \416\ Midcontinent Joint Consumer Advocates Comments at 8.
    \417\ Id.
    \418\ Delaware Commission Comments at 13.
---------------------------------------------------------------------------

    187. Powerex asks the Commission to consider adopting a
verification process for external resources that is distinct from the
process used for internal resources because the two resource types
differ.\419\ Powerex states that verifying external resource costs is
challenging in WECC because large hydroelectric storage facilities in
the Pacific Northwest do not have easily calculable and verifiable
short-run marginal costs, and because CAISO does not require that
import offers be associated with a specific resource.\420\ As an
alternative, Powerex suggests that the Commission could direct the
RTOs/ISOs to implement an offer cap tied to prevailing market prices,
such as capping offers from external resources at the higher of $1,000/
MWh or 120 percent of the highest market price index report in the
region for the previous seven days.\421\ TAPS and APPA, NRECA, and AMP
assert that the Commission should give individual RTOs/ISOs the
discretion to determine whether to allow imports to submit cost-based
incremental energy offers over $1,000/MWh.\422\
---------------------------------------------------------------------------

    \419\ Powerex Comments at 7-8.
    \420\ Id. at 8-9.
    \421\ Id. at 9.
    \422\ TAPS Comments at 19-20; APPA, NRECA, and AMP Comments at
18-19.
---------------------------------------------------------------------------

    188. Several commenters argue that limiting external resources to
$1,000/MWh offers may dissuade them from offering electricity to the
RTO/ISO in periods when it is most needed.\423\ For example, CEA states
that in light of the Commission's price formation proceeding, there is
no compelling reason to adopt an asymmetrical offer cap for internal
resources and imports and questions the wisdom of excluding external
transactions when price signals indicate scarcity and extreme
conditions.\424\ Powerex states that the Western Interconnection has a
robust market for energy and ancillary services outside of CAISO and
that non-CAISO resources may make the economically rational choice to
sell power to a non-CAISO customer if CAISO has a lower offer cap
compared to the non-CAISO WECC bilateral market.\425\
---------------------------------------------------------------------------

    \423\ NY Transmission Owners Comments at 5-6; CEA Comments at 7-
8; NY Department of State Comments at 5; Powerex Comments at 7-8.
    \424\ CEA Comments at 7-8.
    \425\ Powerex Comments at 7-8.
---------------------------------------------------------------------------

    189. NYISO and Competitive Power Providers state that all market
transactions, including imports and virtual transactions, should be
capped at the level of the hard cap, which will allow for a greater
degree of competition.\426\
---------------------------------------------------------------------------

    \426\ Competitive Suppliers Comments at 23-24; NYISO Comments at
7.
---------------------------------------------------------------------------

    190. Some commenters discussed emergency imports. For example, PJM
Power Providers agrees with PJM that the Commission should not apply
the proposed offer requirements to emergency imports because an offer
cap on emergency energy or emergency load reductions would limit PJM's
ability to procure sufficient resources and could threaten
reliability.\427\
---------------------------------------------------------------------------

    \427\ PJM Power Providers Answer at 6-7.
---------------------------------------------------------------------------

    191. However, the PJM Market Monitor argues that emergency imports
above $1,000/MWh should be subject to cost verification before they are
eligible to set LMP in PJM and asserts that such imports currently have
an unmitigated opportunity to exercise market power in PJM
markets.\428\ The PJM Market Monitor states that the rules of
competitive markets should apply, even during emergency
conditions.\429\ The PJM Market Monitor adds that verifying the costs
of emergency imports is feasible because they occur infrequently.\430\
PJM Market Monitor asserts that PJM/SPP offer no rationale for
exempting emergency imports from the proposed offer cap requirements,
which the PJM Market Monitor states are most critical during emergency
situations.\431\
---------------------------------------------------------------------------

    \428\ PJM Market Monitor Comments at 11; PJM Market Monitor
Answer at 2-3.
    \429\ PJM Market Monitor Answer at 2.
    \430\ PJM Market Monitor Comments at 11; PJM Market Monitor
Answer at 3.
    \431\ PJM Market Monitor Answer at 3.
---------------------------------------------------------------------------

2. Determination
    192. We find that it is just and reasonable to permit economic
exchange transactions (i.e., imports and exports) to offer up to the
level of the $2,000/MWh hard cap. We do not require that import or
export transactions above $1,000/MWh be subject to the verification
requirement prior to the market clearing process.
    193. While in the NOPR the Commission proposed to make imports
ineligible to offer above $1,000/MWh, i.e., to prohibit imports from
making such offers, we now are persuaded that such a prohibition could
discourage imports at times when they are most needed. Imports benefit
the market because they offer additional supply and increase
competition. A prohibition on imports above $1,000/MWh would discourage
external resources with short-run marginal costs above $1,000/MWh from
supplying energy to the RTO/ISO market, even though the market is
willing to purchase that supply, and such a prohibition would thus put
upward pressure on energy prices. We applied this rationale above in
adopting the offer structure requirement and find that it applies
equally to imports. Additionally, similar to the rationale outlined
above for virtual transactions, allowing imports to offer up to $2,000/
MWh without cost verification is generally consistent with the current
market structures in RTOs/ISOs, which typically allow imports to offer
up to the same offer cap that internal RTO/ISO resources are subject
to. A similar logic applies to export transactions.
    194. Further, prohibiting imports from offering above $1,000/MWh
could result in uneconomic flows between RTOs/ISOs. For example, if the
LMP in one

RTO/ISO is $1,500/MWh and an external resource would like to offer an
import at a price of $1,400/MWh, a prohibition on import offers above
$1,000/MWh would restrict that transaction and result in inefficient
flows across RTO/ISO boundaries.
    195. Additionally, we will not require import offers above $1,000/
MWh be cost-verified and find that imports are not similarly situated
to internal generation resources. Unlike incremental energy offers from
internal resources, import offers are often not resource-specific and,
thus, it is difficult--some commenters say impossible--to ascertain the
underlying costs of most import offers. This approach is consistent
with current market power mitigation measures in RTOs/ISOs that apply
to internal resources but do not typically apply to imports.
    196. Additionally, RTO/ISO market participants can import energy
from adjacent markets and sell that energy in the RTO/ISO energy
market. Therefore, it is difficult for external resources in an
adjacent market to withhold because internal RTO/ISO resources can
import energy from that adjacent market. Additionally, provided the
adjacent market is competitive, which is expected if the adjacent
market is an RTO/ISO with market power mitigation, it would be
difficult for an external resource to exercise market power in the
importing RTO/ISO.
    197. Though it is not required, the Commission would consider
proposals by RTOs/ISOs to verify or otherwise review the costs of
imports or exports and/or develop additional mitigation provisions for
import and export transactions above $1,000/MWh. Such proposals should
be submitted in a separate filing under section 205 of the Federal
Power Act.
    198. We clarify that this Final Rule will not apply to Coordinated
Transactions Schedules, which are spread bids as opposed to energy
offers. Additionally, the Final Rule will not apply to emergency
purchases, which would go beyond the scope of this Final Rule because
such transactions are administratively priced rather than based on
short-run marginal cost.

VI. Other Comments

    199. The Commission also sought comment on various aspects of the
verification process and the types of costs that should be considered
in the verification. Specifically, the Commission sought comment on (1)
whether the Market Monitoring Unit or RTOs/ISOs may need additional
information to ensure that all short-run marginal cost components that
are difficult to quantify, such as certain opportunity costs, are
accurately reflected in a resource's cost-based incremental energy
offer, and (2) to the extent that RTOs/ISOs currently include an adder
above cost in cost-based incremental energy offers, whether such an
adder is appropriate for incremental energy offers above $1,000/
MWh.\432\ Commenters also discussed the impact that the proposed offer
cap reforms could have on other market constructs, such as shortage
pricing.
---------------------------------------------------------------------------

    \432\ NOPR, FERC Stats. & Regs. ] 32,714 at P 73.
---------------------------------------------------------------------------

A. Verification Requirement Details

1. Comments
    200. Commenters express differing views on whether opportunity
costs are legitimate costs, and if so, whether it is appropriate to
include them within cost-based incremental energy offers. The PJM
Market Monitor states that it currently calculates opportunity costs at
the request of PJM members and does not need additional information
about the details of opportunity costs.\433\ The SPP Market Monitor
explains that SPP currently allows an opportunity cost adder above
mitigated offers, which would still be appropriate to include if costs
exceed $1,000/MWh.\434\
---------------------------------------------------------------------------

    \433\ PJM Market Monitor Comments at 8.
    \434\ SPP Market Monitor Comments at 10. The SPP Market Monitor
notes that resources can use forecasted LMPs and production costs to
estimate price-cost margins for each hour of the day to determine
the opportunity cost component of the mitigated offer.
---------------------------------------------------------------------------

    201. Midcontinent Joint Consumer Advocates and TAPS oppose
opportunity cost adders in the verification methodology for cost-based
incremental energy offers above $1,000/MWh.\435\ Midcontinent Joint
Consumer Advocates add that if the Commission finds that opportunity
costs may be recoverable, then the Market Monitoring Unit should review
such costs to ensure they are just and reasonable.\436\
---------------------------------------------------------------------------

    \435\ Midcontinent Joint Consumer Advocates Comments at 6-7;
TAPS Comments at 16.
    \436\ Midcontinent Joint Consumer Advocates Comments at 6-7.
---------------------------------------------------------------------------

    202. Commenters expressed a range of opinions regarding whether it
is appropriate to account for cost uncertainty or other risks through
an adder in cost-based incremental energy offers above $1,000/MWh. SPP
takes no position on the appropriateness of the adder but argues that
the different RTOs/ISOs should be allowed to develop verification rules
that are consistent with their existing rules, including adders.\437\
PJM, MISO, the PJM Market Monitor, and Potomac Economics support an
adder of up to ten percent to account for uncertainty and risk.\438\
The ISO-NE Market Monitor states that the primary function of a ten
percent adder is to provide for errors or under-estimation of a
resource's marginal cost and contends that the Commission should not
require such an adder unless it identifies specific and valid costs
that are unique to days with abnormally high natural gas prices.\439\
---------------------------------------------------------------------------

    \437\ PJM/SPP Comments at 24.
    \438\ Id. at 22-23; MISO Comments at 15; PJM Market Monitor
Comments at 9; Potomac Economics Comments at 7.
    \439\ ISO-NE Market Monitor Comments at 12
---------------------------------------------------------------------------

    203. Dominion, Exelon, ODEC, and PJM support the inclusion of a ten
percent adder to cost-based incremental offers.\440\ Dominion and
Exelon contend that a ten percent adder to cost-based incremental
offers is appropriate because the adder accounts for some of the
uncertainty that accompanies fuel cost estimation as well as dispatch
instructions.\441\ ODEC maintains that the ten percent adder in cost-
based incremental energy offers is both justified and necessary in PJM
and should not be removed because it accounts for the fact that some
costs are unknown when PJM resources compute their cost-based
incremental energy offers.\442\ APPA, NRECA, and AMP state that adders
above cost are not necessary when a resource's costs can be accurately
verified prior to the market clearing process.\443\
---------------------------------------------------------------------------

    \440\ Dominion Comments at 6; Exelon Comments at 20 (citing
Testimony of Kevin A. Libby at 8-9 (Libby Test.)); ODEC Comments at
5-6; PJM/SPP Comments at 22.
    \441\ Dominion Comments at 6; Exelon Comments at 20 (citing
Libby Test. at 8-9).
    \442\ ODEC Comments at 6 (citing PJM 2015 Offer Cap Order, 153
FERC ] 61,289 at P 30).
    \443\ APPA, NRECA, and AMP Comments at 17.
---------------------------------------------------------------------------

    204. However, the New Jersey Commission, Direct Energy, PG&E, TAPS,
and Industrial Customers oppose including a ten percent adder in cost-
based incremental energy offers above $1,000/MWh.\444\ The New Jersey
Commission argues that such an adder would simply afford the generators
an additional ten percent margin of profit above their costs that
consumers would fund.\445\ TAPS and Industrial Customers state that the
ten percent adder should not be included in incremental energy offers
above $1,000/MWh because the

adder does not constitute an actual cost.\446\
---------------------------------------------------------------------------

    \444\ Direct Energy Comments at 5; PG&E Comments at 3; New
Jersey Commission Comments at 17; TAPS Comments at 16; Industrial
Customers Comments at 25-26 (citing PJM Market Monitor Comments,
Docket No. ER14-1144, at 2, n. 5 (filed Mar. 26, 2015)).
    \445\ New Jersey Commission Comments at 17.
    \446\ TAPS Comments at 16; Industrial Customers Comments at 25-
26 (citing PJM Market Monitor Comments, Docket No. ER14-1144, at p.
2, n. 5 (filed Mar. 26, 2015)).
---------------------------------------------------------------------------

    205. With respect to other short-run marginal cost components, the
Pennsylvania Commission, CAISO, and Industrial Customers argue that a
resource's permissible short-run marginal costs should not include
unauthorized natural gas costs and natural gas pipeline penalties.\447\
CAISO requests that the Commission convene a technical conference to
discuss limitations in fuel markets and the appropriate parameters for
determining prudently incurred costs.\448\ Industrial Customers recount
the Commission's reasoning that allowing recovery for costs and
penalties of unauthorized gas consumption could jeopardize gas pipeline
and transmission system reliability, and that generators would still
have sufficient flexibility.\449\
---------------------------------------------------------------------------

    \447\ Pennsylvania Commission Comments at 5, 10; CAISO Comments
at 11-12; Industrial Customers Comments at 26.
    \448\ CAISO Comments at 12.
    \449\ Industrial Customers Comments at 26-27 (citing N.Y. Indep.
Sys. Operator, Inc., 154 FERC ] 61,111, at P 1 (2016)).
---------------------------------------------------------------------------

    206. The Commission also sought comment on whether the verification
of physical offer components is necessary.\450\ The ISO-NE Market
Monitor states that ISO-NE's existing process to verify physical offer
components takes significant time because such changes to physical
offer parameters cannot be completed on the day that offers are
due.\451\ The ISO-NE Market Monitor advises the Commission to avoid
imposing time limitations that interfere with the ISO-NE Market
Monitor's ability to review and verify physical parameters before-the-
fact.\452\ The PJM Market Monitor requests that the Commission clarify
that the cost-based offers contemplated in the NOPR include the same
limits on offer parameters as all other cost-based offers.\453\ Potomac
Economics advises that any Final Rule not address physical parameters
because additional verification of physical parameters is not needed,
and the proposal only addressed incremental energy offers.\454\
Midcontinent Joint Consumer Advocates note that physical offer
components such as generation minimum and maximum levels are already
known and reviewed by the Market Monitoring Unit, and therefore, there
is no need for additional verification of physical offer
components.\455\
---------------------------------------------------------------------------

    \450\ NOPR, FERC Stats. & Regs. ] 32,714 at P 73.
    \451\ ISO-NE Market Monitor Comments at 10.
    \452\ Id. at 11.
    \453\ PJM Market Monitor Comments at 2-3.
    \454\ Potomac Economics Comments at 11 (citing Potomac Economics
Post-Technical Workshop Comments. Docket No. AD14-14-000, at 5
(filed Feb. 24, 2015)).
    \455\ Midcontinent Joint Consumer Advocates Comments at 6.
---------------------------------------------------------------------------

2. Determination
    207. Several commenters state that adders above costs should be
included in cost-based offers to account for cost uncertainty or
risk.\456\ While we will not require RTOs/ISOs to include such an
adder, if an RTO/ISO chooses to retain an adder above cost or proposes
to include a new adder above cost in cost-based incremental energy
offers above $1,000/MWh, such adders may not exceed $100/MWh. On
balance, we find that limiting adders above cost to $100/MWh is just
and reasonable because as clarified above, the verification process may
involve reviewing a resource's expected, rather than actual, costs,
which could involve the use of imperfect information. Given that
practical reality, we find that it is necessary to place an upper bound
on the level of adders above cost when incremental energy offers exceed
$1,000/MWh in order to ensure that cost-based incremental energy offers
above $1,000/MWh reasonably and accurately reflect actual or expected
short-run marginal cost.\457\ The Commission has previously found in
PJM that adders above cost are unjust and unreasonable as applied to an
after-the-fact review of documented costs because the costs are no
longer uncertain.\458\ Applying that same reasoning here, if a resource
receives uplift after-the-fact because that resource's cost-based
incremental energy offer above $1,000/MWh could not be verified prior
to the market clearing process or because its cost-based incremental
energy offer exceeded $2,000/MWh, the uplift payments that the resource
receives should not include any adders above costs. As noted above,
after-the-fact uplift would be based on a resource's actual costs.\459\
---------------------------------------------------------------------------

    \456\ See supra P 203.
    \457\ The Commission notes that it previously accepted adders
above costs in PJM that exceed $100/MWh. However, after reviewing
the record before us in this proceeding, we find that it is just and
reasonable to limit the adder to $100/MWh. See PJM 2015 Offer Cap
Order, 153 FERC ] 61,289 at P 31.
    \458\ PJM 2015 Offer Cap Order, 153 FERC ] 61,289 at P 31
(citing PJM Interconnection, L.L.C., 149 FERC ] 61,059 at P 13).
    \459\ See supra P 146.
---------------------------------------------------------------------------

    208. Based on the record before us, we will not require that
additional information on short-run marginal cost components be
provided to the RTO/ISO or Market Monitoring Unit. Furthermore, we will
not prescribe the manner in which RTOs/ISOs or Market Monitoring Units
verify cost-based incremental energy offers above $1,000/MWh. As
indicated in the NOPR, RTOs/ISOs use different processes to develop and
update the incremental energy offers used for mitigation and differ in
how they define the components of cost-based incremental energy
offers.\460\ While we are taking no action at this time on these issues
and comments, we do not prejudge what RTOs/ISOs may file with the
Commission in the future. Accordingly, the Final Rule will not require
verification of physical offer parameters or financial offer components
other than the incremental energy offer.
---------------------------------------------------------------------------

    \460\ NOPR, FERC Stats. & Regs. ] 32,714 at PP 61-62.
---------------------------------------------------------------------------

B. Impact of Offer Cap Reforms on Other Market Elements

    209. The Commission recognized in the NOPR that revising the offer
cap may impact other RTO/ISO market elements that depend on the offer
cap, such as shortage pricing levels or various penalty factors.\461\
---------------------------------------------------------------------------

    \461\ Id. P 72.
---------------------------------------------------------------------------

1. Comments
    210. Four RTOs/ISOs commented that RTO/ISO market elements other
than the offer cap may need to be revised if the offer cap is revised.
CAISO states that it will face significant implementation challenges if
it changes its current $1,000/MWh offer cap because the administrative
penalty prices CAISO uses in its market model to indicate that
constraints have been relaxed, such as the power balance constraint,
are based on the offer cap.\462\
---------------------------------------------------------------------------

    \462\ CAISO Comments at 14-17. CAISO requests that, prior to
issuing the Final Rule, the Commission conduct a technical
conference to better understand the challenges of implementation.
CAISO Comments at 3, 17.
---------------------------------------------------------------------------

    211. PJM states that it would likely need to adjust shortage
pricing rules in PJM in light of any Final Rule on offer caps.\463\ SPP
states that it would likely need to revise its scarcity prices and
violation relaxation limits to prevent instances in which LMPs exceed
scarcity values.\464\ MISO states that it may need to revise its
Operating Reserve Demand Curve, $3,500/MWh LMP cap, and Transmission
Constraint Demand Curves if MISO's $1,000/MWh offer cap is
revised.\465\
---------------------------------------------------------------------------

    \463\ PJM/SPP Comments at 28.
    \464\ Id. at 29.
    \465\ MISO Comments at 3-5.
---------------------------------------------------------------------------

    212. APPA, NRECA, and AMP and ODEC state that any Final Rule

regarding offer caps should be restricted to changing the offer cap and
not address potentially associated issues such as scarcity
pricing.\466\ In contrast, PG&E recommends that before allowing the
offer cap to rise above $1,000/MWh, the Commission and the individual
RTOs/ISOs should determine all related changes to the markets that
would be needed to ensure that the markets would function
properly.\467\
---------------------------------------------------------------------------

    \466\ ODEC Comments at 1; APPA, NRECA, and AMP Comments at 20-
21.
    \467\ PG&E Comments at 2.
---------------------------------------------------------------------------

2. Determination
    213. An RTO/ISO may file, pursuant to section 205 of the Federal
Power Act, to propose modifications to shortage prices or other market
elements that require revision in light of the offer cap reforms
adopted in this Final Rule. However, we do not require such
modifications to comply with this Final Rule. We find that it is not
appropriate to determine in this Final Rule the changes that individual
RTOs/ISOs should make to market elements that are not the subject of
these reforms.

VII. Requests Beyond the Scope of This Proceeding

A. Comments

    214. Commenters raised issues that are not discussed above and that
are outside the scope of this rulemaking. Several commenters argue that
the focus of the recommendations in the NOPR is too narrow. API
recommends that the Commission look for ways to encourage the
appropriate integration of new technologies, including quickly ramping
gas-fired generation technology, to meet rapidly changing grid-
conditions and allow prices in real-time markets to better reflect the
true state of grid reliability at a given moment while addressing any
remaining concerns of market power abuse.\468\ API further recommends
that the Commission initiate an examination of opportunity costs and
risk premiums, inclusive of a wider range of resources, in wholesale
energy market offer pricing and how they may or may not be considered
by various RTO/ISO market rules.\469\
---------------------------------------------------------------------------

    \468\ API Comments at 2-3.
    \469\ Id. at 8.
---------------------------------------------------------------------------

    215. The PJM Market Monitor argues that because gas is the only
fuel likely to result in offers greater than $1,000/MWh, the removal of
any cap on short run marginal cost therefore relies on the
competitiveness of the gas markets.\470\ The PJM Market Monitor
suggests that a reconsideration of the structure and design of the gas
market and the potential for a gas market RTO/ISO is a longer term
solution to address issues of transparency and market power in the gas
market.\471\
---------------------------------------------------------------------------

    \470\ PJM Market Monitor Comments at 4.
    \471\ Id. at 6.
---------------------------------------------------------------------------

    216. The Pennsylvania Commission states that the Commission should
direct PJM and other RTO/ISO stakeholders to develop a ``circuit
breaker'' provision to cap energy market revenue during uncontrollable
and sustained outage events.\472\ The Pennsylvania Commission states
that during sustained outages, price signals in energy markets become
irrelevant, and the main consideration is the time required to repair
infrastructure as opposed to the economic theory behind energy
markets.\473\ The Pennsylvania Commission also recommends that the
Commission direct PJM to introduce some level of aggregate market power
mitigation or impose a screen for aggregate market power in the PJM
day-ahead and real-time markets.\474\ PJM Joint Consumer Advocates
argue that shortage prices in PJM should be revised to represent
customers' willingness to pay,\475\ and the Ohio Commission states that
scarcity pricing may no longer be necessary in light of this Final
Rule.\476\
---------------------------------------------------------------------------

    \472\ Pennsylvania Commission Comments at 5-7.
    \473\ Id. at 8.
    \474\ Id. at 13-14.
    \475\ PJM Joint Consumer Advocates Comments at 5-6.
    \476\ Ohio Commission Comments at 14-15.
---------------------------------------------------------------------------

    217. Industrial Customers argue that increases to the current
$1,000/MWh offer cap should be explored simultaneously with the
elimination of capacity markets, and that the Commission could act more
methodically to explore ways to improve capacity market competitiveness
and transparency.\477\
---------------------------------------------------------------------------

    \477\ Industrial Customers Comments at 29-30.
---------------------------------------------------------------------------

B. Determination

    218. We appreciate the concerns raised by numerous commenters
requesting that the Commission undertake various initiatives, as set
forth above. However, we find that the requested initiatives go beyond
the scope of this rulemaking, which only addresses incremental energy
offers above $1,000/MWh. Accordingly, we will not address those
concerns here.

VIII. Information Collection Statement

    219. The Paperwork Reduction Act (PRA) \478\ requires each federal
agency to seek and obtain Office of Management and Budget (OMB)
approval before undertaking a collection of information directed to ten
or more persons or contained in a rule of general applicability. OMB's
regulations,\479\ in turn, require approval of certain information
collection requirements imposed by agency rules. Upon approval of a
collection(s) of information, OMB will assign an OMB control number and
an expiration date. Respondents subject to the filing requirements of a
rule will not be penalized for failing to respond to these
collection(s) of information unless the collection(s) of information
display a valid OMB control number.
---------------------------------------------------------------------------

    \478\ 44 U.S.C. 3501-3520.
    \479\ 5 CFR 1320 (2016).
---------------------------------------------------------------------------

    220. In this Final Rule, we are amending the Commission's
regulations to improve the operation of organized wholesale electric
power markets operated by RTOs/ISOs. We require that each RTO/ISO (1)
cap each resource's incremental energy offer at the higher of $1,000/
MWh or that resource's verified cost-based incremental energy offer;
and (2) when calculating LMPs, RTOs/ISOs shall cap verified cost-based
incremental energy offers at $2,000/MWh. The reforms required in this
Final Rule would require a one-time tariff filing with the Commission
due 75 days after the effective date of this Final Rule to implement
these reforms. We anticipate the reforms required in this Final Rule,
once implemented, would not significantly change currently existing
burdens on an ongoing basis. With regard to those RTOs/ISOs that
believe that they already comply with the reforms required in this
Final Rule, they could demonstrate their compliance in the compliance
filing required 75 days after the effective date of this Final Rule in
this proceeding. The Commission will submit the proposed reporting
requirements to OMB for its review and approval under section 3507(d)
of the Paperwork Reduction Act.\480\
---------------------------------------------------------------------------

    \480\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    221. In the NOPR, the Commission sought comments on the accuracy of
provided burden and cost estimates and any suggested methods for
minimizing the respondents' burdens, including the use of automated
information techniques. Specifically, the Commission sought detailed
comments on the potential cost and time necessary to implement aspects
of the reforms proposed in the NOPR, including (1) software and
business processes changes, including market power mitigation; (2)
increased time spent validating cost-based incremental energy offers;
and (3) processes for RTOs/ISOs to vet proposed changes amongst their
stakeholders. The Commission also stated that although it did not
expect other entities to incur

compliance costs as a result of the reforms proposed in the NOPR, it
sought detailed comments on whether other entities, such as load-
serving entities, would incur costs as a result of the reforms proposed
in the NOPR. The Commission received no comments in response to these
questions.
    Burden Estimate and Information Collection Costs: The Commission
believes that the burden estimates below are representative of the
average burden on respondents, including necessary communications with
stakeholders. The estimated burden and cost for the requirements
contained in this rule follow.\481\ The Commission notes that these
cost estimates below do not include costs for software or hardware or
for increased time spent validating cost-based incremental energy
offers above $1,000/MWh.\482\ Software or hardware upgrades may not be
required.
---------------------------------------------------------------------------

    \481\ The RTOs/ISOs (CAISO, ISO-NE., MISO, NYISO, PJM, and SPP)
are required to comply with the reforms in this Final Rule.
    \482\ The Commission expects that the validation of cost-based
incremental energy offers above $1,000/MWh would be an infrequent
occurrence. To the extent that the Market Monitoring Unit or the
RTO/ISO spends time validating these offers, the Commission
estimates such time to be de minimis.

                                                FERC-516, as Modified by Final Rule in Docket RM16-5-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                Annual number
                                 Number of       of responses     Total number   Average  burden  (hours) &  Total annual  burden hours      Cost per
                                respondents    per  respondent    of responses        cost per  response         & total  annual cost    respondent  ($)
                                         (1)              (2)   (1) x (2) = (3)  (4).......................  (3) x (4) = (5)...........       (5) / (1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
One-Time Tariff Filings                    6                1                6   500 hrs.; $37,000 \483\...  3,000 hrs.; $222,000......         $37,000
 (Year 1).
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the total cost of
compliance, all within four months of a Final Rule plus initial
implementation, to be $222,000. After Year 1, the reforms in this Final
Rule, once implemented, would not significantly change existing burdens
on an ongoing basis.
---------------------------------------------------------------------------

    \483\ The estimated hourly cost (salary plus benefits) provided
in this section is based on the salary figures for May 2015 posted
by the Bureau of Labor Statistics for the Utilities sector
(available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000)
and scaled to reflect benefits using the relative importance of
employer costs in employee compensation from June 2016 (available at
http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates
for salary plus benefits are:
     Legal (code 23-0000), $128.94
     Computer and mathematical (code 15-0000), $60.54
     Information systems manager (code 11-3021), $91.63
     IT security analyst (code 15-1122), $63.55
     Auditing and accounting (code 13-2011), $53.78
     Information and record clerk (code 43-4199), $37.69
     Electrical Engineer (code 17-2071), $64.20
     Economist (code 19-3011), $74.43
     Management (code 11-0000), $88.94
    The average hourly cost (salary plus benefits), weighting all of
these skill sets evenly, is $73.74. The Commission rounds it to $74
per hour.
---------------------------------------------------------------------------

    The Commission notes that these estimates do not include costs for
software or hardware. Software or hardware upgrades may not be
required.
    Title: FERC-516C,\484\ Electric Rate Schedules and Tariff Filings.
---------------------------------------------------------------------------

    \484\ The RM16-5-000 Final Rule reporting requirements should be
submitted to FERC-516 (OMB Control No. 1902-0096). Currently, that
information collection is under review for an unrelated activity.
The FERC-516C is a temporary information collection. The reporting
requirements of the RM16-5-000 Final Rule are being submitted to
FERC-516C to ensure timely submission to OMB.
---------------------------------------------------------------------------

    Action: Proposed revisions to an information collection.
    OMB Control No. 1902-0287.
    Respondents for this Rulemaking: RTOs/ISOs.
    Frequency of Information: One-time.
    Necessity of Information: The Federal Energy Regulatory Commission
approves this rule to improve competitive wholesale electric markets in
the RTO/ISO regions.
    Internal Review: The Commission has reviewed the changes and has
determined that such changes are necessary. These requirements conform
to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has specific, objective support for the burden estimates
associated with the information collection requirements.
    222. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., 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-516C and OMB Control No. 1902-
0287.

IX. Regulatory Flexibility Act Certification

    223. The Regulatory Flexibility Act of 1980 (RFA) \485\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA does
not mandate any particular outcome in a rulemaking. It only requires
consideration of alternatives that are less burdensome to small
entities and an agency explanation of why alternatives were rejected.
---------------------------------------------------------------------------

    \485\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

    224. This rule would apply to six RTOs/ISOs (all of which are
transmission organizations). The average estimated annual cost to each
of the RTOs/ISOs is $37,000, all in Year 1. This one-time cost of
filing and implementing these changes is not significant.\486\
Additionally, the RTOs/ISOs are not small entities, as defined by the
RFA.\487\ This is because the

relevant threshold between small and large entities is 500 employees
and the Commission understands that each RTO/ISO has more than 500
employees. Furthermore, because of their pivotal roles in wholesale
electric power markets in their regions, none of the RTOs/ISOs meet the
last criterion of the two-part RFA definition a small entity: ``not
dominant in its field of operation.'' As a result, we certify that the
reforms in this Final Rule would not have a significant economic impact
on a substantial number of small entities.
---------------------------------------------------------------------------

    \486\ This estimate does not include costs for software or
increased time spent validating cost-based incremental energy
offers. As stated above, the Commission expects that the validation
of cost-based incremental energy offers above $1,000/MWh would be an
infrequent occurrence. To the extent that the Market Monitoring Unit
or the RTO/ISO spends time validating these offers, the Commission
expects such time to be de minimis.
    \487\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C.
632.
---------------------------------------------------------------------------

X. Environmental Analysis

    225. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\488\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Final Rule under
section 380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the Federal Power Act relating to the filing of schedules
containing all rates and charges for the transmission or sale of
electric energy subject to the Commission's jurisdiction, plus the
classification, practices, contracts and regulations that affect rates,
charges, classifications, and services.\489\
---------------------------------------------------------------------------

    \488\ Regulations Implementing the National Environmental Policy
Act of 1989, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC
Stats. & Regs. ] 30,783 (1987).
    \489\ 18 CFR 380.4(a)(15) (2016).
---------------------------------------------------------------------------

XI. Document Availability

    226. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
    227. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number of this document, excluding the last three digits, in
the docket number field.
    228. User assistance is available for eLibrary and the Commission's
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>
XII. Effective Date and Congressional Notification

    229. These regulations are effective February 21, 2017. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of OMB, that this rule
is not a ``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Non-discriminatory open
access transmission tariffs.

    By the Commission.

    Issued: November 17, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
    In consideration of the foregoing, the Commission amends 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: