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

    \181\ Potomac Economics Comments at 9-11.
---------------------------------------------------------------------------

    125. The PJM Market Monitor states that five-minute shortage
pricing would correctly reflect actual shortage conditions and should
be implemented if PJM can accurately measure the level of reserves on a
five-minute basis, which the PJM Market Monitor understands that PJM
currently cannot do. The PJM Market Monitor asserts that, without
accurate measurement of reserves at minute-by-minute granularity,
system operators cannot know with certainty that a shortage condition
exists, thus masking the trigger for five-minute shortage pricing. The
PJM Market Monitor recommends that if PJM cannot measure operating
reserves on a five-minute basis, the Commission should direct PJM to
develop methods to do so. The PJM Market Monitor asserts that if RTOs/
ISOs cannot demonstrate that they can accurately measure reserves at
minute-by-minute granularity, they should not implement five-minute
shortage pricing until they have that capability.\182\
---------------------------------------------------------------------------

    \182\ PJM Market Monitor Comments at 9.
---------------------------------------------------------------------------

    126. The SPP Market Monitor supports the Commission's proposal to
require RTOs/ISOs to trigger shortage pricing for any dispatch interval
during which a shortage of energy and operating reserves occurs. The
SPP Market Monitor states that SPP's Integrated Marketplace uses
administratively-determined scarcity pricing demand curves to set
prices during capacity shortages. The SPP Market Monitor explains that,
during shortages, quick-start and fast-ramping resources--which
generally have higher costs and low capacity factors--earn a
significant portion of their annual revenue. The SPP Market Monitor
asserts that scarcity pricing serves as an important mechanism for
sending correct price signals to these resources; however, the SPP
Market Monitor states that SPP is not sending this price signal during
ramp-constrained operating reserve shortages since the SPP market rules
do not allow insufficient ramping capability to trigger scarcity
pricing of operating reserves.\183\ The SPP Market Monitor requests
that the Commission address the ramp-constrained operating reserve
shortage pricing issue in the Final Rule.\184\
---------------------------------------------------------------------------

    \183\ SPP Market Monitor Comments at 4 (citing SPP Tariff,
Attachment AE <IP_ADDRESS> and <IP_ADDRESS>).
    \184\ SPP Market Monitor Comments at 4-6.
---------------------------------------------------------------------------

c. Comments Supporting the Shortage Pricing Reform
    127. Several other commenters express support for shortage pricing
reform. These commenters agree that the proposed shortage pricing
reform will increase transparency, create incentives to trigger quick
response from supply, promote investment in resources that

can respond to short duration shortages, and provide revenues to
resources that reflect the value of the service provided.\185\ In
addition, several commenters, including EPSA and Westar, support the
shortage pricing proposal and state that it should apply to all
shortages, regardless of duration.\186\
---------------------------------------------------------------------------

    \185\ Ameren Comments at 1, 3-4; ANGA Comments at 2-5; CAISO
Comments at 2; CEA Comments at 3-6; Dominion Comments at 1-2; DTE
Comments at 3-4; EDP Renewables Comments at 2; EEI Comments at 2;
ESA Comments at 2-4; Entergy Nuclear Power Marketing Comments at 2;
EPSA Comments at 1-5; Exelon Comments at 4; Financial Marketers
Coalition Comments at 1; Golden Spread Initial Comments at 1-3;
Inertia Power and DC Energy Comments at 2; ISO-NE Comments at 1;
MISO Comments at 2, 9; NEI Comments at 1; NGSA Comments at 2-5; PJM
Power Providers Comments at 2-5; Potomac Economics Comments at 2;
Powerex Comments at 6; PSEG Comments at 3; Public Interest
Organizations Comments at 5; SPP Market Monitor Comments at 2;
Westar Comments at 1; Duke Comments at 7.
    \186\ EPSA Comments at 9; EPSA Comments, Pope Aff. at 15; Golden
Spread Initial Comments at 6; PJM Power Providers Comments at 4;
Powerex Comments at 6; EDP Renewables Comments at 5-6; Entergy
Nuclear Power Marketing Comments at 2; Exelon Comments at 6; PSEG
Comments at 13; Westar Comments at 5; NEI Comments at 14; CEA
Comments at 4; NGSA Comments at 5.
---------------------------------------------------------------------------

    128. Several commenters support the Commission's shortage pricing
proposal, arguing that market clearing prices should reflect shortage
or emergency situations so that generators are provided transparent
price signals that reflect the market conditions.\187\ EPSA and Westar
note that reflecting a shortage price signal during transient shortage
events will result in a price signal that incents resources to respond
to real-time system constraints based on a price that reflects the
value of loss of load even if the event is less than ten minutes in
duration.\188\ Further, Westar states that if the ``steepness'' of
regulation and operating reserve demand scarcity pricing curves is a
concern then an RTO/ISO should create separate operating reserve
scarcity demand curves for transitory periods versus periods lasting
longer than ten minutes.\189\
---------------------------------------------------------------------------

    \187\ EEI Comments at 10; EPSA Comments at 9; PJM Power
Providers Comments at 4; Westar Comments at 5; NEI Comments at 14.
    \188\ EPSA Comments at 9; Westar Comments at 5.
    \189\ Westar Comments at 5.
---------------------------------------------------------------------------

    129. Some commenters state that the shortage pricing proposal will
provide an incentive for existing resources to offer their supply and
to be available if shortages occur and will provide an incentive for
incremental investments to enable existing or new generation or
dispatchable demand to respond to shortages, regardless of
duration.\190\ Further, CEA states that without appropriate
compensation prices invariably become distorted insofar as they do not
reflect the increased value of that resource with utmost accuracy and
granularity.\191\ In addition, NGSA comments that the proposal will
encourage investments by generators that allow them to more reliably
perform, leading to greater regional fuel assurance.\192\
---------------------------------------------------------------------------

    \190\ EPSA Comments, Pope Aff. at 15; NEI Comments at 14; CEA
Comments at 4; NGSA Comments at 5.
    \191\ CEA Comments at 4.
    \192\ NGSA Comments at 5.
---------------------------------------------------------------------------

    130. ANGA states that while a shortage may be transient and last
only a single five-minute interval, some resources are able to move
quickly enough to meet these shifts in demand and, hence, reduce
overall system instability. Further, ANGA maintains, allowing prices to
respond to these small shortages also sends a long-term price signal to
the market, highlighting where and what types of resources are needed
on the system, which improves overall system reliability. ANGA also
agrees with EPSA's position, recorded in the NOPR, that all markets
should prioritize establishing shortage pricing based on operating
reserve demand curves and co-optimized with the energy market. ANGA
states that this is a least-cost solution and recommends that the
Commission direct the RTOs/ISOs to include in their compliance filing a
plan for modifying their rules, to the extent necessary, to include
these features in both the day-ahead and real-time markets.\193\
---------------------------------------------------------------------------

    \193\ ANGA Comments at 5.
---------------------------------------------------------------------------

    131. Powerex supports the Commission's proposal to require RTOs/
ISOs to apply shortage pricing for any dispatch interval during which a
shortage of energy or operating reserves occurs.\194\ Powerex contends
that shortage pricing mechanisms tied to real-time conditions provide
revenues to generators and demand side resources that provide energy
and reserves when needed, which is an advantage over the capacity
markets long-term focus on load growth and reliability.\195\
---------------------------------------------------------------------------

    \194\ Powerex Comments at 6.
    \195\ Powerex Comments at 8.
---------------------------------------------------------------------------

    132. EDP Renewables states that the Commission's shortage pricing
proposal would result in more accurate price signals than under
existing market rules, and therefore would encourage greater investment
in new production and storage technologies with the ability to respond
quickly to shortages.\196\ Similarly, ESA asserts that the shortage
pricing reform will improve the ability for a resource to be
compensated based on the value of the service the resource
provides.\197\ ESA maintains that, for energy storage resources to help
ensure grid reliability, an economic incentive must exist to
incorporate those resources onto the grid.\198\
---------------------------------------------------------------------------

    \196\ EDP Renewables Comments at 5-6.
    \197\ ESA Comments at 4.
    \198\ ESA Comments at 4.
---------------------------------------------------------------------------

    133. Exelon and Inertia Power assert that implementing shortage
pricing for any interval during which a shortage could occur will
provide the right incentives for generating resources and will promote
adequate incentives for resource adequacy. Exelon and Inertia Power
state that it is economically more efficient for prices to reflect the
value of the marginal resource during shortage periods, and that this
is particularly true in instances where generation resources must
compete with alternatives, such as exporting power to a neighboring
market or not consuming a scarce fuel.\199\
---------------------------------------------------------------------------

    \199\ Inertia Power and DC Energy Comments at 5; Exelon Comments
at 6.
---------------------------------------------------------------------------

    134. PSEG states that it supports the shortage pricing proposal,
that the proposal would address concerns about transparency, and that
it would accomplish Order No. 719's objective of enhancing market
efficiency by establishing a price that reflects the value of the loss
of load and encourage resources to respond to shortage events.\200\
PSEG further states that the absence of shortage pricing in the
appropriate intervals is inefficient within individual RTOs/ISOs as
well as between them, and it can frustrate the objectives of
Coordinated Transaction Scheduling, which is currently being deployed
by several RTOs/ISOs.\201\
---------------------------------------------------------------------------

    \200\ PSEG Comments at 13.
    \201\ PSEG Comments at 14.
---------------------------------------------------------------------------

    135. Golden Spread supports the Commission's proposed shortage
pricing reform and argues that even the smallest amount of operating
reserve and energy shortage should be reflected in scarcity
pricing.\202\ Golden Spread states that it has invested hundreds of
millions of dollars in a fleet of new quick-start, fast-ramping
generation resources in anticipation of the proper working of efficient
marginal cost-based energy markets. Golden Spread states that to the
extent these resources are not fully compensated because shortage
pricing is masked, the value of these assets to Golden Spread's members
and their consumers is diminished.\203\
---------------------------------------------------------------------------

    \202\ Golden Spread Reply Comments at 4.
    \203\ Golden Spread Reply Comments at 7.
---------------------------------------------------------------------------

    136. DTE states that, as a member of MISO, it has largely supported
the changes MISO has made through ELMP to ensure that generators are
provided

accurate price signals, akin to the shortage pricing proposal.\204\
---------------------------------------------------------------------------

    \204\ DTE Comments at 5.
---------------------------------------------------------------------------

d. Comments Recommending Changes to the Shortage Pricing Reform
    137. Several commenters propose changes to the shortage pricing
reform, or identify implementation issues in specific RTOs/ISOs.
    138. Golden Spread, for example, states that the current SPP rules
allow the temporary use of operating reserves to meet energy
requirements during transient periods without invoking shortage
pricing; in other words, SPP's rules encourage ``price manipulation''
undermining the transparency needed to incentivize longer term economic
and reliable solutions.\205\
---------------------------------------------------------------------------

    \205\ Golden Spread Reply Comments at 5.
---------------------------------------------------------------------------

    139. Golden Spread identifies examples of issues with certain SPP
processes that it argues need to be addressed to comply with this
reform and provides the following recommendations to resolve them: (1)
Relax constraints to allow economic dispatch to solve when there is a
resource capacity constraint, global power balance constraint, resource
ramp constraint or operating constraint; \206\ (2) prevent insufficient
ramping capability to be subject to scarcity pricing; \207\ (3) include
fast-start technologies in a Reliability Unit Commitment action to
avoid scarcity events, which then eliminates scarcity prices; \208\ and
(4) use of the concept of ``head-room'' to not factor much-needed
ramping capacity in the LMP, which is reducing transparency and
creating large uplifts.\209\
---------------------------------------------------------------------------

    \206\ Golden Spread Comments at 8.
    \207\ Golden Spread Comments at 7-8.
    \208\ Golden Spread Comments at 9-10.
    \209\ Golden Spread Comments at 10.
---------------------------------------------------------------------------

    140. ELCON states that the shortage pricing proposal should be
adopted only if the Commission promotes the development of technology-
neutral fast-ramp products paid to provide the specific shortage
service, and for which compensation would not inflate real-time
LMPs.\210\ ELCON asserts that it conditionally supports the provision
on shortage price triggers when applied to technology-neutral fast-
ramping products--products it states could be provided by demand
response, energy storage technologies, or generation--but not to real-
time shortage pricing in which every resource dispatched or called by
the system operator during a dispatch interval is paid the same
price.\211\
---------------------------------------------------------------------------

    \210\ ELCON Comments at 2.
    \211\ ELCON Comments at 3-6.
---------------------------------------------------------------------------

e. Comments Opposed to the Proposed Shortage Pricing Reform
    141. Several commenters oppose the shortage pricing proposal.
Several commenters argue that while the NOPR does not address the price
level of the shortage pricing, to the extent that RTOs/ISOs do change
shortage pricing triggers, the RTOs/ISOs should also evaluate whether
shortage pricing levels remain just and reasonable.\212\ For example,
Concerned Cooperatives and APPA and NRECA argue that the NOPR will
raise prices for consumers, but the Commission fails to quantify the
cost impact of the shortage pricing proposal on consumers or the
potential benefits to the market and consumers.\213\ Concerned
Cooperatives add that any changes to the shortage pricing triggers in
the RTO/ISO markets must be cost-justified on the basis of quantifiable
improvements in market efficiencies and cost reductions. Furthermore,
Concerned Cooperatives argue that the Commission's shortage pricing
will raise prices for consumers and increase revenues to incumbent
generators.\214\
---------------------------------------------------------------------------

    \212\ APPA and NRECA Comments at 12; TAPS Comments at 14-15;
Concerned Cooperatives Comments at 13.
    \213\ Concerned Cooperatives Comments at 13-14; APPA and NRECA
Comments at 6.
    \214\ Concerned Cooperatives Comments at 13.
---------------------------------------------------------------------------

    142. APPA and NRECA assert that it is important to understand how
various resource types would respond to price signals created by the
shortage pricing proposal. Specifically, they assert that the NOPR did
not discuss whether a five-minute shortage pricing event would produce
a sufficient response or only reflect a transient shortage resolvable
without resorting to shortage pricing.\215\ APPA and NRECA reference
PJM representative Adam Keech's comment at the October 28, 2014
workshop on scarcity and shortage pricing, justifying PJM's current
minimum duration of 30 minutes prior to triggering shortage pricing,
and assert that the shortage pricing proposal runs the risk of
rewarding generators that are already online just because another
generator has not fully ramped up yet.\216\ APPA and NRECA state that
the NOPR neither discussed the degree to which the RTOs/ISOs are
already in compliance with the proposal, the extent to which
implementation would impact the frequency of shortage pricing events or
impact prices, nor did it require RTOs/ISOs to undertake this
analysis.\217\ APPA and NRECA state that shortage pricing was triggered
relatively infrequently in PJM and MISO, but more frequently in
NYISO.\218\
---------------------------------------------------------------------------

    \215\ APPA and NRECA Comments at 6-7.
    \216\ APPA and NRECA Comments at 7.
    \217\ APPA and NRECA Comments at 9.
    \218\ APPA and NRECA Comments at 9-10.
---------------------------------------------------------------------------

    143. APPA and NRECA question the extent to which shortage pricing
would improve short-term system efficiency. They comment that existing
variations among RTOs/ISOs in shortage pricing approaches create an
opportunity to analyze the efficacy of more frequent shortage events.
They request that the Commission direct the RTOs/ISOs to provide
evidence or examine whether the theoretical benefits of the shortage
pricing proposal can be validated with actual resource decisions. APPA
and NRECA caution that, without such analysis, entities, such as
generators already online that cannot easily ramp up or down or
financial marketers, could benefit financially without contributing to
system efficiency.\219\ Concerned Cooperatives also note that the
Commission's rationale that prices must rise to reflect the true value
of generation offered during operational shortages for the market to
function properly fails to consider that only half of the market, i.e.,
generators, may be able to respond to the price signal in real-
time.\220\
---------------------------------------------------------------------------

    \219\ APPA and NRECA Comments at 10-11.
    \220\ Concerned Cooperatives Comments at 14.
---------------------------------------------------------------------------

    144. On the topic of long-term incentives, several commenters
assert that no evidence exists that price signals as volatile and
transient as shortage prices would be the basis for capital
investments, whether to improve flexibility, whether to delay or avoid
retirements, and especially not for the construction of new resources.
APPA and NRECA assert that, even with a slight uptick in merchant plant
construction compared to prior years, 95 percent of new construction
was built under contract in 2014, and 98 percent of new construction
was built under contract in 2013.\221\ Further, Concerned Cooperatives
argue that the evidence presented at the technical conferences
preceding the NOPR demonstrate that short-term price signals from
shortage pricing do not result in the long-term resource investment
contemplated in the NOPR.\222\
---------------------------------------------------------------------------

    \221\ APPA and NRECA Comments at 11-12; TAPS Comments at 7-13;
Concerned Cooperatives Comments at 15-16.
    \222\ Concerned Cooperatives Comments at 15-16.
---------------------------------------------------------------------------

    145. Concerned Cooperatives contend that the RTOs/ISOs could
develop better products, such as a fast-ramping product, that could
encourage investment in more flexible resources without having to pay
every resource a high price during shortage intervals of short
duration.\223\ Moreover, APPA and

NRECA encourage the Commission to examine alternative methods of
achieving its stated goal of incentivizing the availability of
resources during periods of shortage, such as separately priced ramping
products. APPA and NRECA urge the Commission to also examine whether
such methods might achieve this goal at a lower cost to consumers.\224\
Concerned Cooperatives further argue that the Commission's proposal is
simply a transfer of wealth from consumers to generators without value
to consumers, because, as the Commission admitted in the NOPR, some
shortage events are so short that suppliers cannot react to the price
signal.\225\
---------------------------------------------------------------------------

    \223\ Concerned Cooperatives Comments at 22-24.
    \224\ APPA and NRECA Comments at 12.
    \225\ Concerned Cooperatives Comments at 15-16.
---------------------------------------------------------------------------

    146. ODEC states that, in the example provided by PJM, if a unit is
slow in coming online for a five-minute interval, it is not clear that
shortage pricing would not over-compensate a resource, or if supply can
even respond to such a short-term event in sufficient time for the
price signal to create an incentive to change behavior. ODEC states
that it therefore believes that shortage pricing during transient
shortages may be unjust and unreasonable because it will increase
prices paid by load without corresponding benefits.\226\
---------------------------------------------------------------------------

    \226\ ODEC Comments at 6.
---------------------------------------------------------------------------

    147. APPA and NRECA also express concern that more frequent
shortage pricing creates incentives to exercise market power and game
market rules due to the potential for higher energy and operating
reserve prices. They assert that if the proposal moves forward, each
RTO/ISO should be required to reevaluate its market power mitigation
rules and propose new or additional mitigation measures if
necessary.\227\ In addition, Concerned Cooperatives also argue that
revising RTO/ISO tariffs to invoke shortage pricing more frequently is
likely to increase opportunities for exploitation of consumers, but
that the NOPR does not propose to require RTOs/ISOs to include in their
compliance filings an analysis of needed reforms to ensure that
consumers remain protected against the exercise of market power.\228\
---------------------------------------------------------------------------

    \227\ APPA and NRECA Comments at 15-16.
    \228\ Concerned Cooperatives Comments at 15.
---------------------------------------------------------------------------

    148. Concerned Cooperatives also argue that if the Commission
issues a final rule in this proceeding, RTOs/ISOs must be required to
demonstrate that their shortage pricing mechanisms comply with four
overarching principles, by providing for (1) prices that reflect the
marginal costs of meeting the shortage; (2) a cap that is designed to
mitigate adverse financial impacts on parties who are short; (3) prices
that escalate with greater levels of shortage, because marginal costs
will vary by shortage; and (4) a mechanism to ensure that revenues
earned through shortage pricing are not duplicated by capacity market
revenues.\229\
---------------------------------------------------------------------------

    \229\ Concerned Cooperatives Comments at 24-25.
---------------------------------------------------------------------------

    149. The New Jersey Board urges the Commission to allow PJM to
retain its current shortage pricing mechanism--a thirty-minute look-
ahead dispatch algorithm that identifies reserve shortages as only
those lasting a minimum of thirty minutes. The New Jersey Board agrees
with PJM that five-minute shortfalls are not necessarily symptomatic of
system stress, but are merely transient shortfalls that can be quickly
addressed through system re-dispatch.
    150. More broadly, TAPS argues that any price signal during
transient scarcity events is meaningless because resources cannot
respond in time to the higher prices.\230\ In addition, Direct Energy
says that targeting transient shortages will create control issues and
increase uplift, and the application of RTO/ISO shortage penalty
factors to these transient situations will likely lead to higher prices
than would otherwise be produced, creating unjust and unreasonable
rates for generation compensation.\231\
---------------------------------------------------------------------------

    \230\ TAPS Comments at 7-13.
    \231\ Direct Energy Comments at 10-11.
---------------------------------------------------------------------------

    151. Regarding definitions, Direct Energy asserts that a true
shortage implies that insufficient capacity exists on an RTO's/ISO's
system to meet energy and reserve requirements. In contrast, Direct
Energy argues, transient shortage conditions are not true shortages
because they simply reflect the operating characteristics of the
generators being used to meet energy and reserve targets. Direct Energy
argues that in a transient shortage condition, the RTO/ISO has the
capacity to meet energy and reserve requirements and the transient
shortage period represents the period of time it takes to deploy
generation resources to meet those targets.\232\
---------------------------------------------------------------------------

    \232\ Direct Energy Comments at 10-11.
---------------------------------------------------------------------------

    152. Direct Energy claims the response an RTO/ISO receives based on
the shortage pricing signals sent during transient shortage conditions
is likely to cause a control issue when generation already being ramped
through RTO/ISO dispatch to resolve the shortage condition hits its
dispatch targets. Further, Direct Energy argues unjust and unreasonably
higher prices would result from targeting ``transient'' shortages
because of the impact of shortage pricing penalty factors in transient
shortage circumstances, because the shortage pricing reserve penalty
factors would be applied to a marginal unit providing energy that is
not the highest opportunity cost reserve unit. Thus, Direct Energy
argues the Commission should either revise its proposal to reflect
issues with transient shortages of operating reserves, or permit
individual RTOs/ISOs to evaluate this proposal and consider tariff
revisions to address true shortages and to send appropriate price
signals.\233\
---------------------------------------------------------------------------

    \233\ Direct Energy Comments at 11-13.
---------------------------------------------------------------------------

    153. Concerned Cooperatives and APPA and NRECA argue that the NOPR
does not account for differences among the RTOs/ISOs, maintaining that
shortage pricing issues should be resolved through individual
stakeholder processes.\234\ Alternatively, Concerned Cooperatives
request that the Commission not implement shortage pricing reform until
an RTO/ISO demonstrates that it has eliminated the conditions that
cause ``artificial'' shortages (those arising from mathematical
modeling when no actual operational shortage exists), adopts rules
preventing shortage pricing from being applied during artificial
shortages, and adopts rules ensuring that shortage price levels are
reduced during artificial shortages to reflect that these are not real
shortages.\235\
---------------------------------------------------------------------------

    \234\ APPA and NRECA Comments at 5; Concerned Cooperatives
Comments at 18.
    \235\ Concerned Cooperatives Comments at 18.
---------------------------------------------------------------------------

    154. Concerned Cooperatives also note that the NOPR fails to
provide a comparison of the market design in RTO/ISO-administered
markets that trigger shortage pricing for a shortage event of any
duration and those that use longer duration events as the trigger.\236\
Concerned Cooperatives argue that, before imposing a uniform rule, the
Commission should determine whether these different shortage pricing
rules have resulted in incremental resource development, improved
generator response to shortage conditions, and/or reduced the need for
uplift charges. Concerned Cooperatives state that in some cases, uplift
payments may be the most cost-effective solution for consumers.\237\
---------------------------------------------------------------------------

    \236\ Concerned Cooperatives Comments at 26.
    \237\ Concerned Cooperatives Comments at 26.
---------------------------------------------------------------------------

    155. Several commenters point to various efforts in RTOs/ISOs that
may impact shortage pricing. Concerned Cooperatives argue that the
Commission should not address price formation issues in a piecemeal
fashion, as changes to one element will impact the

need for other reforms. Concerned Cooperatives note that several RTOs/
ISOs already have rules providing adequate incentives for resource
performance and investment, such as PJM's Reliability Pricing Model,
ISO-NE's Forward Capacity Market, or MISO's ELMP.\238\ Concerned
Cooperatives assert that the Commission provides no evidence that more
frequent triggering of shortage pricing is necessary to ensure resource
adequacy or improve resource performance and flexibility when RTOs/ISOs
use other market tools to achieve the same objectives set forth in the
NOPR.
---------------------------------------------------------------------------

    \238\ Concerned Cooperatives Comments at 18-21.
---------------------------------------------------------------------------

    156. The New Jersey Board, APPA and NRECA and ODEC all acknowledge
PJM's Capacity Performance Program \239\ and argue to varying degrees
that shortage pricing need not be considered here given this PJM reform
or that the Commission should consider whether there would be overlap
between this PJM reform and the shortage pricing proposal.\240\
Furthermore, APPA and NRECA state that another factor in determining
whether the shortage pricing proposal would improve market efficiency
and benefit consumers is the extent to which there is an overlap
between this proposal and other RTO/ISO market rules.\241\ APPA and
NRECA also point out that, in some RTOs/ISOs such as NYISO, scarcity
pricing is an additional and separate revenue stream that can balance
reliance on capacity market revenues.\242\ Further, ODEC suggests that,
instead of requiring an expansion of scarcity pricing to transient time
periods, the Commission require PJM to consider the need to reduce, if
not eliminate, scarcity pricing in light of the new Capacity
Performance construct.\243\
---------------------------------------------------------------------------

    \239\ See PJM Interconnection, L.L.C., 151 FERC ] 61,208 (2015).
    \240\ New Jersey Board Comments 4-6; APPA and NRECA Comments at
14.
    \241\ APPA and NRECA Comments at 13.
    \242\ APPA and NRECA Comments at 14-15.
    \243\ ODEC Comments at 8.
---------------------------------------------------------------------------

    157. Concerned Cooperatives note that the NOPR fails to identify
the number of additional shortages that would be triggered in RTO/ISO
markets that do not invoke shortage pricing for a single settlement
interval. They argue that the NOPR also fails to quantify what that
cost might potentially be for consumers, particularly in PJM, which
recently sought to increase its energy offer caps to $2,000 per MWh
which could produce LMPs of $3,700 per MWh during shortage events.
Concerned Cooperatives state that the NOPR provides no evidence that
prices at this level are just and reasonable for a five-minute shortage
where a resource cannot respond and/or the event is triggered by an
artificial shortage.\244\
---------------------------------------------------------------------------

    \244\ Concerned Cooperatives Comments at 25.
---------------------------------------------------------------------------

    158. PG&E urges the Commission to examine transient shortages and
their attendant price spikes, and resolve modeling issues that are
causing these shortages. PG&E understands that shortage pricing might
be appropriate to the extent that such pricing provides a meaningful
price signal to resources. However, PG&E argues that most price spikes
in the CAISO over the past five years have been so short that they have
not provided a meaningful opportunity for resources to respond.\245\
For example, PG&E states that from 2012 through 2014, the CAISO five-
minute market saw positive price spikes (>$250/MWh) in approximately
0.75 percent of the intervals. PG&E argues that transitory price spikes
do not contribute to market efficiency, but result in increased market
costs, and they give false signals to virtual participants, which can
distort day-ahead awards and prices. PG&E also asserts that these
transitory price spikes have contributed to price divergence between
day-ahead and real-time and have resulted in significant uplift
costs.\246\
---------------------------------------------------------------------------

    \245\ PG&E Comments at 1-2.
    \246\ PG&E Comments at 1-2.
---------------------------------------------------------------------------

    159. PG&E notes that CAISO is already taking significant steps to
address modeling issues that create transient shortages and attendant
transient price spikes. For example, PG&E states that CAISO is working
to augment the real-time dispatch function with a Flexible Ramping
Product which will help avoid ramp-induced shortages that cause
scarcity conditions in real-time. PG&E also explains that CAISO is
considering applying different penalty prices for infeasibilities
depending on the level of constraint relaxation, which will more
appropriately reflect the cost of constraint violations. PG&E asserts
that a small violation of the power balance constraint may be covered
by deploying regulation reserves at a smaller cost per megawatt-hour
than a larger violation, which may require more costly load
shedding.\247\
---------------------------------------------------------------------------

    \247\ PG&E Comments at 2.
---------------------------------------------------------------------------

    160. Dominion states that it is concerned that some shortages are
merely transient in nature due to slight differences in modeling and
the ramping of generation, and may not warrant sending a shortage price
signal to the market. Dominion argues that issues regarding transient
shortages should be addressed prior to implementation of the proposed
reforms.\248\ Dominion states that the Commission should require RTOs/
ISOs to specifically explain how the RTOs/ISOs will address this issue
as part of their compliance filings. Further, Dominion asserts that the
modification of shortage pricing triggers to better correlate to
dispatch intervals should coincide with implementation of the
Commission's proposal to align settlement intervals with dispatch
intervals. Dominion argues that this will align a resource's timely
response to shortage pricing with payment for its response.\249\
---------------------------------------------------------------------------

    \248\ Dominion Comments at 4-5.
    \249\ Dominion Comments at 5.
---------------------------------------------------------------------------

4. Commission Determination
    161. For the reasons discussed below, we adopt the NOPR shortage
pricing proposal and modify the regulatory text to clarify that
shortage pricing is required only when a shortage of energy or
operating reserves is indicated by the RTO's/ISO's software.
    162. Specifically, we require each RTO/ISO to trigger shortage
pricing for any interval in which a shortage of energy or operating
reserves is indicated during the pricing of resources for that
interval. As stated in the NOPR, the shortage pricing requirement
should ``ensure that a resource is compensated based on a price that
reflects the value of the service the resource provides.'' \250\ This
rationale applies to any shortage ``regardless of the duration or cause
of [the] shortage.'' \251\ It thus would apply to ``transient
shortages.'' Several commenters specifically agreed with this
analysis.\252\ Under this requirement, whenever a shortage of energy or
operating reserves is indicated in an RTO's/ISO's pricing run software
for a particular pricing interval, shortage pricing should be invoked
even if during that period resources are ramping up to a particular
level they are likely to reach in a few minutes.
---------------------------------------------------------------------------

    \250\ NOPR, FERC Stats. & Regs. ] 32,710 at P 52.
    \251\ NOPR, FERC Stats. & Regs. ] 32,710 at P 47; see also id. P
9 (``This reform would also ensure that resources operating during a
shortage are compensated for the value of the service that they
provide, regardless of whether the shortage is short-lived.'').
    \252\ See, e.g., Inertia Power and DC Energy Comments at 6
(citing NYISO Comments, Docket No. AD14-14-000, at 28-29 (Mar. 6,
2015), Potomac Economics Comments, Docket No. AD14-14-000, at 25-26
(Mar. 6, 2015), and Calpine Comments, Docket No. AD14-14-000, at 20
(Mar. 6, 2015)); SPP Market Monitor Comments at 3; Golden Spread
Comments at 3-4.
---------------------------------------------------------------------------

    163. We find that the shortage pricing requirement will help ensure
that prices rise sufficiently and appropriately to allow supply to meet
demand during an operating reserve shortage, and thus will more
accurately reflect the value a

resource provides.\253\ Better formed prices help ensure just and
reasonable rates by providing appropriate incentives for market
participants to follow commitment and dispatch instructions, maintain
reliability, provide transparency of the underlying value of the
service so that operational and investment decisions are based on
prices that reflect the actual marginal cost of serving load and the
operational constraints of reliable system operation, and encourage
efficient investments in facilities and equipment.
---------------------------------------------------------------------------

    \253\ See NOPR, FERC Stats. & Regs. ] 32,710 at P 48 (citing
Order No. 719, FERC Stats. & Regs. ] 31,281).
---------------------------------------------------------------------------

    164. As for incentives to follow dispatch, as noted in the NOPR, if
a resource is compensated based on a price that reflects the value of
the service the resource provides, the resource will have appropriate
incentives to address energy or reserve shortages. As explained by
Potomac Economics, the higher prices (relative to non-shortage price
intervals) resulting from the shortage pricing proposal will enhance
resource flexibility by leading to: (1) Faster resource ramp rates; (2)
wider dispatch ranges and not self-scheduling resources; (3) shorter
start times for natural gas turbines; and (4) an incentive to build
more flexible, fast-ramping generating resources and to perform
maintenance on existing resources that increases their
flexibility.\254\ In addition, shortage pricing during all reserve
deficiencies also sends the correct price signal to already operating
resources to take any actions necessary to remain operational during
the shortage event. For instance, a resource that is already operating
but realizes it will need to take a forced outage in the near-term will
receive a clear signal to delay that forced outage, to the extent
possible, until the reserve shortage has been resolved.
---------------------------------------------------------------------------

    \254\ Potomac Economics Comments at 8.
---------------------------------------------------------------------------

    165. A number of commenters cite the role of appropriate shortage
pricing in creating an incentive for market participants to make
investments that will alleviate shortages in the future.\255\ EDP
Renewables and ESA note that the shortage pricing proposal will
encourage greater investment in new production and storage
technologies.\256\ In response to commenters that assert that short
duration shortage prices will not create a sufficient incentive for new
entry, we agree with EPSA that appropriate shortage pricing will
encourage more modest investments that can improve availability and
response-time, such as weatherization of fuel supplies, heat tracing to
reduce instrument failure during freezing temperatures, and completion
of deferred maintenance such as burner upgrades.\257\ Investments of
the nature identified by commenters should enhance reliability in the
long-run as system resources are more able to perform during critical
system conditions.
---------------------------------------------------------------------------

    \255\ NEI Comments at 14; NGSA Comments at 5; EPSA Comments,
Pope Aff. at 15; Potomac Economics Comments at 8.
    \256\ EDP Renewables Comments at 5-6; ESA Comments at 4. ESA
states that the shortage pricing reform will improve the ability for
a resource to be compensated based on the value of the service the
resource provides.
    \257\ EPSA Comments, Pope Aff. at 19.
---------------------------------------------------------------------------

    166. With regard to transparency, an RTO's/ISO's action to
establish prices at the times of shortage, including transient
shortages, makes the shortage apparent to all market participants. This
maximizes the opportunities and incentives for all system resources to
take actions to address the shortage.
    167. In response to commenters like CAISO, we clarify that we did
not intend to impose shortage pricing if a shortage occurs during an
interval for which the prices and dispatch decisions have already been
set. We did not intend that, for example, ex post pricing should, after
binding prices have been determined by the RTO/ISO software, invoke
shortage pricing based upon a subsequent recognition that a shortage
existed in a particular prior interval. Similarly, the shortage pricing
proposal also did not intend to require any changes to the frequency of
existing dispatch and pricing runs for energy or operating reserves. To
the extent that operating reserves are priced at a different interval
than energy resources are dispatched, as is the case in CAISO, this
Final Rule applies to the interval that prices and co-optimizes both
energy and operating reserves. Thus, an RTO/ISO need not trigger
shortage pricing during a fifteen-minute operating reserve period if it
becomes aware of a shortage within that interval, because reserve
prices have already been set for that entire fifteen-minute period.
Only if that shortage is projected to continue into the next reserve
period and there is time to factor that shortage into the dispatch and
pricing run for the next interval does the RTO/ISO need to trigger
shortage pricing for that next interval.
    168. Also, the shortage pricing proposal did not intend to require
any changes to existing pricing methods, such as ELMP in MISO that
allows offline resources to set energy prices, and we agree that the
use of offline resources can result in efficient pricing.\258\ However,
we agree with Potomac Economics that if an RTO's/ISO's pricing model
allows infeasible or uneconomic units to set prices, the offline units
represent an artificial increase in real-time supply that will depress
real-time prices. Therefore, for the purpose of this Final Rule, RTOs/
ISOs choosing to use offline resources to count towards energy and
operating reserve requirements may not allow infeasible or uneconomic
offline units to set prices through the real-time pricing model or to
be counted as providing reserves.
---------------------------------------------------------------------------

    \258\ See Midcontinent Indep. Sys. Operator, Inc., 150 FERC ]
61,143, at P 36 (2015) (``For the reasons discussed below, we
conditionally accept MISO's Revised ELMP Filing, effective March 1,
2015, subject to a further compliance filing. . . .''); Midcontinent
Indep. Sys. Operator, Inc., Docket No. ER15-685-001 (Feb. 4, 2016)
(delegated letter order accepting compliance filing).
---------------------------------------------------------------------------

    169. In opposing the proposal, PJM and SPP argue that an energy or
operating reserve shortage that the RTO/ISO expects to be resolved
quickly (e.g., within ten minutes), should not trigger shortage
pricing. They note that, in PJM, for example, shortage pricing is not
triggered until a shortage is projected to last at least thirty
minutes.\259\
---------------------------------------------------------------------------

    \259\ NOPR, FERC Stats. & Regs. ] 32,710 at P 46 & n.70; PJM and
SPP Comments at 5.
---------------------------------------------------------------------------

    170. We disagree that an energy or operating reserve shortage that
the RTO/ISO expects to be resolved quickly should not trigger shortage
pricing. Such a shortage presents exactly the type of mismatch between
system conditions and pricing that the reform was meant to remedy.
Thus, by adopting the proposed shortage pricing reform, we require PJM
and SPP to modify their existing shortage pricing mechanisms.
    171. As summarized above, PJM and SPP provide three hypothetical
situations in their joint comments to describe situations where they
argue shortage pricing should not apply.\260\ In all of these
scenarios, RTOs/ISOs are ``technically compromising the operating
reserve requirement,'' as PJM and SPP concede,\261\ although such
transient shortages may not violate NERC's reliability standards.\262\
However, we find that RTOs/ISOs should reflect these system conditions
in the price. Using shortage pricing for a transient shortage situation
reflects in

the price of operating reserves the current system conditions, which
include the possibility of a contingency occurring--for which operating
reserves were procured and designed to address. This is designed to
appropriately value those resources that provide value to the system by
their ability to respond quickly to changing prices. As Potomac
Economics states,\263\ transient shortages, which typically occur when
the system is ramp-constrained, are true shortages because, if a large
contingency occurs during such a shortage (e.g., a generator trips off-
line), the RTO/ISO will not have the ability to replace the capacity
because other generators are already ramping as quickly as possible. It
is possible, as PJM and SPP state, that when a transient shortage is
recognized, RTOs/ISOs can re-dispatch their system to eliminate the
shortage quickly.\264\ However, until the shortage is resolved, prices
should reflect the system conditions and the actions taken to resolve
the shortage as much as possible.
---------------------------------------------------------------------------

    \260\ PJM and SPP Comments at 3-5.
    \261\ PJM and SPP Comments at 4.
    \262\ Requirement R6.2 of North American Electric Reliability
Corporation's Reliability Standard BAL-002-1 requires restoration of
contingency reserves within 90 minutes: ``The default Contingency
Reserve Restoration Period is 90 minutes.'' In the Western Electric
Coordinating Council (WECC), the reliability standards require
restoration of contingency reserves within 60 minutes. WECC BAL-002-
WECC-2, R1.
    \263\ Potomac Economics Comments at 8.
    \264\ PJM and SPP Comments at 4.
---------------------------------------------------------------------------

    172. PJM, SPP, and Direct Energy have also not shown that applying
shortage pricing to transient shortages will create control issues and
increase uplift.\265\ In fact, there is evidence in this record that it
will not. The RTOs/ISOs which currently invoke shortage pricing during
relatively brief periods, i.e., MISO, NYISO and ISO-NE., do not appear
to have these types of control issues. Further, we note that reflecting
system conditions in prices should decrease uplift over time, as the
costs of units committed, dispatched, or designated as reserves would
be reflected in prices and those units would no longer need to be made
whole through uplift payments.
---------------------------------------------------------------------------

    \265\ See PJM and SPP Comments at 3-5 (making this argument in
the context of the hypotheticals discussed above); Direct Energy
Comments at 10-11.
---------------------------------------------------------------------------

    173. PJM and SPP state that application of the shortage pricing
reform to transient shortages would likely require the implementation
of operating reserve demand curves that distinguish prices relative to
varying degrees of shortage.\266\ In the NOPR, the Commission
acknowledged that, as a result of the shortage pricing reform, ``an
RTO/ISO may need to calibrate administrative shortage prices to better
reflect the value of the service.'' \267\ Thus, if PJM or SPP believes
that a modification of the applicable operating reserve demand curves
is appropriate in light of the shortage pricing reform, the appropriate
forum to make such is a change is through an FPA section 205 filing.
---------------------------------------------------------------------------

    \266\ PJM and SPP Comments at 7-8.
    \267\ NOPR, FERC Stats. & Regs. ] 32,710 at P 49.
---------------------------------------------------------------------------

    174. We disagree with TAPS, Concerned Cooperatives, APPA, and NRECA
that the only effect of requiring RTOs/ISOs to trigger shortage prices
in transient events is to provide extra revenue to generators already
in the market.\268\ While extra revenue may result from prices
accurately reflecting shortage conditions, we believe that is
appropriate. The purpose for requiring the shortage pricing is to
create transparent market prices that reflect system conditions. The
benefit of triggering shortage prices for all shortages is that it
gives all suppliers an incentive to do as much as they can, including
investments and operational alterations, to be available the next time
it appears that shortages may occur and shortage pricing may be
invoked, even if such shortages last briefly. Further, as discussed
above, shortage pricing during all reserve deficiencies also sends the
correct price signal to already operating resources to take any actions
necessary to remain operational during the shortage event.
---------------------------------------------------------------------------

    \268\ TAPS Comments at 9; APPA and NRECA Comments at 7;
Concerned Cooperatives Comments at 16.
---------------------------------------------------------------------------

    175. We disagree with the views of those commenters \269\ who
assert that the proposed rule is not justified because no evidence
exists that price signals as volatile and transient as shortage prices
would be the basis for capital investments. While shortage pricing
revenues may not, by themselves, be enough to financially justify
entirely new generation projects, commenters who are generation owners
and project developers have indicated that triggering shortage prices
during short duration shortages as proposed in the NOPR ``will provide
an incentive for incremental investments to enable existing or new
generation or dispatchable demand to respond to short-duration
shortages.'' \270\ As to the amount of construction done recently by
merchants as opposed to that done under long-term contracts, we note
that RTOs/ISOs such as PJM have been able to maintain reliability with
reliance primarily upon their capacity market and not long-term
contracts for new generation.\271\
---------------------------------------------------------------------------

    \269\ APPA and NRECA Comments at 11-12; TAPS Comments at 7-13;
Concerned Cooperatives Comments at 15-16.
    \270\ EPSA Comments, Pope Aff. at 15.
    \271\ See generally Monitoring Analytics, New Generation in the
PJM Capacity Market: MW and Funding Sources for Delivery Years 2007/
2008 through 2018/2019 (May 4, 2016), http://www.monitoringanalytics.com/reports/Reports/2016/New_Generation_in_the_PJM_Capacity_Market_20160504.pdf.
---------------------------------------------------------------------------

    176. TAPS recommends that the Commission direct each RTO/ISO to
propose new shortage prices for transient shortages that do not exceed
the value of the incremental benefit (if any) provided by an additional
megawatt in those circumstances, or to demonstrate that the RTO's/ISO's
existing shortage prices applicable in such circumstances already meet
that standard.\272\ We decline to require this in the Final Rule both
because this was not originally proposed and because the record in this
proceeding has not persuaded us that any RTO's/ISO's administrative
shortage prices need to be modified. However, as discussed above, any
RTO/ISO may file, pursuant to section 205 of the FPA, to propose a
modification of any of the administrative shortage prices as a result
of this Final Rule, as PJM and SPP indicate they might.
---------------------------------------------------------------------------

    \272\ TAPS Comments at 13. PJM and SPP indicate that they may
need to file to modify their shortage prices. See PJM and SPP
Comments at 8.
---------------------------------------------------------------------------

    177. The PJM Market Monitor identifies an implementation issue,
which may be unique to PJM. The PJM Market Monitor asserts that PJM
cannot accurately measure the actual level of operating reserves on a
five-minute basis. To address this, the PJM Market Monitor and the New
Jersey Board recommend that the Commission direct PJM to develop this
measurement capability before it implements the shortage pricing
proposal.\273\ To the extent that PJM or any other RTO/ISO believes it
needs to enhance its measurement capabilities to implement the shortage
pricing requirement, it should propose to do so in its compliance
filing.
---------------------------------------------------------------------------

    \273\ PJM Market Monitor Comments at 9.
---------------------------------------------------------------------------

    178. Concerned Cooperatives maintains that the shortage pricing
proposal may not achieve the price formation objective of increased
transparency because generators may not be capable of responding fast
enough to shortage pricing triggered during transient events.\274\
However, we find that the shortage pricing requirement will increase
transparency because shortage prices provide a clear and public market
signal, while compensation to resources provided through uplift
provides a signal only to individual resources and after-the-fact. In
addition, consistently sending a clear price signal during reserve
deficiencies in real-time should encourage market participant behavior
in the day-ahead market that translates into day-ahead

prices that better reflect expected system conditions.
---------------------------------------------------------------------------

    \274\ Concerned Cooperatives Comments at 6.
---------------------------------------------------------------------------

    179. Concerned Cooperatives, ODEC, ELCON, and PG&E suggest that the
Commission should not adopt the shortage pricing proposal because other
initiatives, such as PJM's Reliability Pricing Model modifications and
fast ramping products, already provide adequate incentives for resource
performance and send the signals needed for generation investment.\275\
We are not persuaded by these arguments. While other initiatives, such
as PJM's Reliability Pricing Model modifications and additional fast-
ramping products, could decrease the occurrence of shortages and
shortage pricing, an effective shortage pricing trigger is still
required to ensure appropriate pricing when shortages occur. This is
particularly important for incenting behavior by load in the day-ahead
market that is consistent with expected system conditions in real-time.
For instance, the Reliability Pricing Model modifications will send
real-time price signals to encourage resource performance, but will not
necessarily encourage accurate day-ahead load forecast for load.
---------------------------------------------------------------------------

    \275\ Concerned Cooperatives Comments at 18-25; ELCON Comments
at 2; PG&E Comments at 2.
---------------------------------------------------------------------------

    180. Concerned Cooperatives express concern that the Commission
does not require the RTOs/ISOs to include, in their compliance filings,
an analysis to ensure that consumers remain protected against the
exercise of market power when the proposed reforms are
implemented.\276\ However, Concerned Cooperatives do not explain why
the RTOs'/ISOs' existing market power mitigation methodologies would
not prevent the exercise of market power during times of shortage
pricing, under the proposed reforms or otherwise. Therefore, we do not
require the RTOs/ISOs to provide a market power review and mitigation
reforms in their compliance filings.
---------------------------------------------------------------------------

    \276\ Concerned Cooperatives Comments at 15.
---------------------------------------------------------------------------

C. Compliance and Implementation

1. Commission Proposal
    181. In the NOPR, the Commission proposed that RTOs/ISOs submit
compliance filings on both the proposed settlement reform and the
proposed shortage pricing reform four months from the effective date of
the Final Rule; that the proposed settlement reform become effective
twelve months from the date of the compliance filings for
implementation of reforms to settlement systems; and that the shortage
pricing proposal become effective four months from the date of the
compliance filings for implementation of reforms to shortage pricing
triggers.\277\
---------------------------------------------------------------------------

    \277\ NOPR, FERC Stats. & Regs. ] 32,710 at PP 38, 54-55.
---------------------------------------------------------------------------

2. Comments
    182. As described below, some commenters sought more time to submit
compliance filings and questioned (1) whether the Commission provided
enough time to implement the settlement proposal; and (2) whether the
Commission should extend implementation of the shortage pricing
proposal to allow for simultaneous implementation of shortage pricing
proposal with the settlement proposal.
a. Comments From RTOs/ISOs
    183. The ISO/RTO Council argues that the Commission should not
force the RTOs/ISOs to substantially reform their existing market
structure to comply with the shortage pricing proposal.\278\ PJM, MISO,
and ISO-NE either support the compliance deadline or believe that they
can meet the compliance deadline once a Final Rule is published in the
Federal Register.\279\
---------------------------------------------------------------------------

    \278\ ISO/RTO Council Comments at 3.
    \279\ PJM Comments at 7; MISO Comments at 13; ISO-NE Comments at
1.
---------------------------------------------------------------------------

    184. ISO-NE supports the implementation timeline for the shortage
pricing proposal because it believes that its market already meets the
NOPR proposal.\280\ Similarly, ISO-NE states that it has already
engaged its participants to discuss tariff changes to settle the real-
time markets in five-minute intervals, and is therefore not concerned
with the implementation timeline because it anticipates tariff changes
will be filed with the Commission in mid-2016, to be effective in
2017.\281\
---------------------------------------------------------------------------

    \280\ ISO-NE Comments at 3.
    \281\ ISO-NE Comments at 2. ``ISO-NE plans to implement five-
minute settlement of real-time reserves as part of the
implementation of five-minute settlement of real-time energy
transactions, which is currently being discussed with
stakeholders.'' Id. at 3.
---------------------------------------------------------------------------

    185. MISO states that it already has a project in progress to
replace the current software systems that perform market and
transmission settlements processing,\282\ and it estimates that an
additional eight months would be required to mitigate any issues
related to the new software and complete development of the revised
settlement system, allowing implementation by the fourth quarter of
2017.\283\ MISO states that the Commission should allow each RTO/ISO to
propose, in its compliance filing, what it believes is a reasonable
implementation schedule.\284\
---------------------------------------------------------------------------

    \282\ MISO Comments at 3.
    \283\ MISO Comments at 6.
    \284\ MISO Comments at 12.
---------------------------------------------------------------------------

    186. PJM asserts that it can make a compliance filing four months
after the date of the Final Rule, but is concerned that insufficient
time was suggested for implementation.\285\ PJM hopes to complete an
evaluation of what changes are needed in its settlement system around
April 2016, but, depending upon on the outcome of that analysis, it
estimates that revising the settlement process will require between
fifteen to thirty-eight months.\286\ PJM also states that, though it
opposes the shortage pricing proposal, if the Commission orders some
version of shortage pricing reform, the Commission should consider
simultaneous implementation of shortage pricing with the settlement
interval proposal.\287\
---------------------------------------------------------------------------

    \285\ PJM Comments at 7.
    \286\ PJM Comments at 3-4.
    \287\ PJM addresses its objections to the shortage pricing
proposals in the PJM and SPP Comments.
---------------------------------------------------------------------------

    187. CAISO also states that, depending upon the specifics of the
Final Rule, extra time may be necessary for a complete compliance
filing.\288\
---------------------------------------------------------------------------

    \288\ CAISO Comments at 25. CAISO has asked for certain
clarifications as part of its comments, and states that if the
Commission does not make the necessary clarifications, CAISO will
need extra time to consider what changes would need to be made to
its systems, and to develop implementing tariff language along with
the supporting filing. Id.
---------------------------------------------------------------------------

b. Comments Urging Flexibility in Implementation
    188. Several commenters urge flexibility in the implementation
timelines.\289\ The New Jersey Board concurs with PJM that, given the
technical uncertainties involved, the Commission, in the Final Rule,
should provide flexibility in the implementation timeline.\290\ Duke
states that the RTOs/ISOs should determine the implementation timeline
after first exploring system design options, cost impacts to market
participants, and approaches to reduce cost impacts.\291\ EEI and APPA
and NRECA contend that not only is a flexible implementation timeline
necessary, but RTOs/ISOs should also be encouraged to work with market
participants to ensure they have the necessary systems and metering in
place in advance.\292\
---------------------------------------------------------------------------

    \289\ ISO/RTO Council Comments at 3; New Jersey Board Comments
at 3; PJM Comments at 4; EEI Comments at 8; NEPOOL Comments at 1;
Golden Spread Comments at 7-8.
    \290\ New Jersey Board Comments at 3 (citing PJM Comments at 4).
    \291\ Duke Comments at 6.
    \292\ EEI Comments at 8; APPA and NRECA Comments at 4-5.
---------------------------------------------------------------------------

    189. NEPOOL, Golden Spread, and TAPS echo the statements of EEI,

contending that implementation should account for specific differences
between the RTOs/ISOs instead of imposing a rigid standard.\293\
---------------------------------------------------------------------------

    \293\ NEPOOL Comments at 5; Golden Spread Comments at 7-8; TAPS
Comments at 14-15.
---------------------------------------------------------------------------

    190. Although TAPS argues against the proposed shortage pricing
rule, it states that if the rule is adopted, then needed administrative
shortage pricing level modifications should become effective when other
shortage pricing modifications become effective.\294\ Golden Spread
also identifies issues it believes need to be addressed before the
proposed shortage pricing requirement can be properly implemented in
SPP.\295\
---------------------------------------------------------------------------

    \294\ TAPS Comments at 13.
    \295\ Golden Spread Comments at 8-10.
---------------------------------------------------------------------------

c. Compliance Filing Deadline
    191. Some commenters commented on the amount of time allowed to
submit a compliance filing. With regard to the settlement interval
proposal, Concerned Cooperatives state that because it could take over
a year to determine what market rules may need modification and to
subsequently implement those changes, the Commission should require a
compliance filing after one year so that RTOs/ISOs can discuss
implementation issues with stakeholders.\296\ TAPS states that the
four-month compliance deadline proposed in the NOPR is too short
because a rule adjusting shortage pricing triggers needs to be
accompanied by an adjustment to shortage pricing levels.\297\
---------------------------------------------------------------------------

    \296\ Concerned Cooperatives Comments at 12.
    \297\ TAPS Comments at 14.
---------------------------------------------------------------------------

d. Implementation Deadline
    192. PSEG states that, in markets where the current equipment can
be utilized, the twelve-month implementation timeline proposed by the
NOPR would be reasonable.\298\ However, PSEG notes that the Commission
must take into account the time it will take the individual RTOs/ISOs
to implement computer system changes.\299\ Several commenters assert
that the timelines for implementation mentioned in the NOPR may be too
short.
---------------------------------------------------------------------------

    \298\ PSEG Comments at 8.
    \299\ PSEG Comments at 15; Inertia Power Comments at 9.
---------------------------------------------------------------------------

    193. ODEC asserts that, instead of requiring implementation within
twelve months of the compliance filings, if the Commission determines
PJM must settle resources at the same interval those resources are
dispatched, then the Commission should require each RTO/ISO to submit a
proposed plan for compliance and implementation of the Final Rule.\300\
---------------------------------------------------------------------------

    \300\ ODEC Comments at 5.
---------------------------------------------------------------------------

    194. Exelon maintains that the implementation period for the five-
minute settlement interval proposal should be 18 months because of the
equipment changes that will be necessary for generators in the RTOs/
ISOs that do not currently use five-minute pricing.\301\
---------------------------------------------------------------------------

    \301\ Exelon Comments at 5.
---------------------------------------------------------------------------

    195. Ameren argues the timeline proposed in the NOPR is too short
and could potentially increase both costs and risks to the detriment of
their customers.\302\ As for the settlement interval proposal, Ameren
states that the implementation timeline developed from its internal
assessment is at least 24 months to 29 months, with a possible
implementation date of June 1, 2018 if a Final Rule is issued in early
2016.\303\
---------------------------------------------------------------------------

    \302\ Ameren Comments at 6.
    \303\ Ameren Comments at 6-7. Ameren also suggests ``aligning
the implementation of a final rule with the beginning of the MISO
Planning Year, i.e. June 1, in order to facilitate a more seamless
transition.'' Id.
---------------------------------------------------------------------------

    196. Dominion and IPL point out that implementation timing and
specifics for market participants will depend upon when the RTOs/ISOs
finalize their own implementation details, and it argues that the
proposed twelve-month implementation period for settlement interval
reforms does not appropriately take this factor into account.\304\
---------------------------------------------------------------------------

    \304\ Dominion Comments at 2; IPL Comments at 2-3.
---------------------------------------------------------------------------

    197. DTE states that it would need a minimum of eighteen months and
``several million dollars'' to implement necessary changes to its
settlement system,\305\ and Duke is concerned that twelve months will
not be enough time.\306\ DTE and Duke emphasize that it is essential
for the Commission to encourage RTOs/ISOs to work with stakeholders and
market participants in order to facilitate the most cost-effective and
timely implementation.\307\ Commenting on the shortage pricing
proposal, Concerned Cooperatives, who also contend stakeholders need to
work cooperatively with RTOs/ISOs, assert that the implementation
timeline is not long enough, and that the Commission should allow at
least a year for the RTOs/ISOs to vet the shortage pricing
implementation details with their stakeholders.\308\
---------------------------------------------------------------------------

    \305\ DTE Comments at 4-5. DTE explains that these changes would
include, among other things, evaluating its meters and computer
systems, as well as re-evaluating many of its current contracts. Id.
    \306\ Duke Comments at 6-7; DTE Comments at 4-5. DTE explains
that these changes would include, among other things, evaluating its
meters and computer systems, as well as re-evaluating many of its
current contracts. Id.
    \307\ DTE Comments at 5; Duke Comments at 6-7.
    \308\ Concerned Cooperatives Comments at 26-27.
---------------------------------------------------------------------------

    198. APPA and NRECA request that RTOs/ISOs ensure all market
participants either have the necessary metering and billing systems in
place or have sufficient time to add required systems.\309\
---------------------------------------------------------------------------

    \309\ APPA and NRECA Comments at 4-5.
---------------------------------------------------------------------------

    199. Only one entity, Direct Energy, requested an indefinite delay
of implementation: Specifically, for the five-minute settlement
proposal, arguing that the underlying technology of many supply
resources is not advanced enough to ensure the efficiency the
Commission states it seeks in the NOPR.\310\
---------------------------------------------------------------------------

    \310\ Direct Energy Comments at 6.
---------------------------------------------------------------------------

e. Simultaneous Implementation
    200. Some commenters argue that the Commission should synchronize
implementation of the shortage pricing reform with the settlement
interval proposal due to their interrelated nature.\311\
---------------------------------------------------------------------------

    \311\ PJM Comments at 10; EEI Comments at 10-11; DTE Comments at
6; EPSA Comments at 8; PSEG Comments at 15-16; Inertia Power and DC
Energy Comments at 8-9.
---------------------------------------------------------------------------

f. Costs
    201. In the NOPR, the Commission noted that while adopting the
proposed reforms might provide significant benefits, implementing and
modifying settlement systems can be complex and costly.\312\ Various
commenters provided settlement implementation cost estimates: PJM ($3
to $5.6 million),\313\ Ameren ($3 million, plus an additional $13 to
$20 million if the settlement interval proposal is applied to
load),\314\ Duke ($1 to $3.25 million, plus an additional $4 million if
the settlement interval proposal is applied to load),\315\ and
Concerned Cooperatives ($1.5 to $2 million capital costs and $300,000
to $600,000 annual costs).\316\
---------------------------------------------------------------------------

    \312\ NOPR, FERC Stats. & Regs. ] 32,710 at P 60.
    \313\ PJM Comments at 3-4.
    \314\ Ameren Comments at 5-6.
    \315\ Duke Comments at 6.
    \316\ Concerned Cooperatives Comments at 9.
---------------------------------------------------------------------------

    202. While the NOPR did not propose that a cost-benefit analysis
must be performed in conjunction with the proposed reforms, some
commenters discuss whether a formal cost-benefit analysis is necessary
prior to implementation of the proposals. APPA and NRECA, Concerned
Cooperatives, Ameren, and IPL claim that a cost-benefit analysis is
necessary before implementation.\317\ IPL asserts this

analysis will prove that market benefits will be small in comparison to
the costs of implementation.\318\ Conversely, EPSA and the PJM Market
Monitor state that they should not be required to do a cost-benefit
analysis (specifically in reference to sub-hourly pricing) because it
would be too difficult to accurately measure or approximate the
potential long-term benefits.\319\
---------------------------------------------------------------------------

    \317\ APPA and NRECA Comments at 4-5; Concerned Cooperatives
Comments at 12; Ameren Comments at 4; IPL Comments at 2.
    \318\ IPL Comments at 2.
    \319\ EPSA Comments, Pope Aff. at 13-14; PJM Market Monitor
Comments at 2-3.
---------------------------------------------------------------------------

    203. Some commenters opine on how they perceive the costs relate to
the benefits of the proposed reforms. Duke expresses concerns that the
costs of aligning dispatch and settlement intervals will exceed the
benefits. Duke acknowledges that the potential impact of these reforms
is not currently knowable, given that MISO and PJM have not proposed
new market rules and system changes.\320\ However, Duke states that if
RTOs/ISOs determine that costs associated with the proposed reform will
not exceed the benefits, stakeholder discussions could involve software
system changes and relevant costs and impacts on market
participants.\321\ In contrast, Inertia Power states that, although the
long-term benefits are not quantifiable, the direct savings to
consumers and market participants will warrant the costs. Inertia Power
suggests that the Commission should consider the ``immeasurable cost of
muted price signals'' when comparing costs to benefits.\322\
---------------------------------------------------------------------------

    \320\ Duke Comments at 6.
    \321\ Duke Comments at 5.
    \322\ Inertia Power Comments at 7.
---------------------------------------------------------------------------

3. Commission Determination
    204. Because the reforms required in this Final Rule are targeted
and specific, we believe RTOs/ISOs will have sufficient time to develop
and file tariff changes to adopt these limited reforms, contrary to the
concerns of commenters such as Concerned Cooperatives and TAPS. In the
NOPR, the Commission recognized that implementation of the settlement
reform could take up to a year after the compliance filings were
submitted.\323\ With regard to shortage pricing, any revisions an RTO/
ISO may propose to shortage pricing levels (which are not required by
this Final Rule) must be filed under section 205 and could be submitted
prior to the actual implementation of the shortage pricing provisions
of this Final Rule, thereby permitting stakeholders and the RTO/ISO
additional time to work through the implementation details.
---------------------------------------------------------------------------

    \323\ NOPR, FERC Stats. & Regs. ] 32,710 at P 55.
---------------------------------------------------------------------------

    205. Of the entities required to submit a compliance filing, PJM,
MISO, and ISO-NE either support the compliance deadline or believe that
they can meet the compliance deadline once a Final Rule is published in
the Federal Register. Further, neither SPP nor NYISO submitted comments
opposing the compliance deadline. CAISO expressed concern about its
ability to submit a compliance filing within 120 days of the effective
date of this Final Rule. We believe that, with the various
clarifications provided in this Final Rule, CAISO should be able to
submit a compliance filing within four months of the effective date of
the Final Rule. Accordingly, we adopt the proposal in the NOPR and
require each RTO/ISO to submit, within 120 days of the effective date
of this Final Rule, a compliance filing that includes tariff changes
that adopt the requirements in this Final Rule, or demonstrates how the
RTO/ISO already complies. We will allow a further 12 months from the
compliance filing date for the tariff changes implementing reforms to
settlement intervals to be effective, and 120 days from that same
compliance filing date for the tariff changes implementing shortage
pricing reforms to be effective.\324\
---------------------------------------------------------------------------

    \324\ The Commission has followed a similar approach with the
timelines for compliance and implementation in the past. See, e.g.,
Order No. 755, FERC Stats. & Regs. ] 31,324 at P 201, reh'g denied,
Order No. 755-A, 138 FERC ] 61,123.
---------------------------------------------------------------------------

    206. As previously noted, comments on the implementation schedule
focused on two areas: (1) Whether the Commission provided enough time
to implement the settlement reform proposal; and (2) whether the
Commission should extend implementation of the shortage pricing reform
proposal to allow for simultaneous implementation of shortage pricing
with settlement reform. Based upon the comments received, we retain the
current implementation schedule, but will consider requests for
extensions of time to extend the implementation dates when the RTOs/
ISOs submit their compliance filings. The RTOs/ISOs will have had 120
days as they prepare their compliance filings to assess the feasibility
of implementing the reforms set forth in this Final Rule. It is
premature at this time to extend the implementation timelines when
affected parties are only just starting to analyze what actions they
must take in order to implement the requirements of the Final Rule.
    207. Moreover, when the RTOs/ISOs submit their respective
compliance filings, we will consider whether it is appropriate to
permit the RTO/ISO to synchronize implementation of shortage pricing
with the settlement interval based upon the facts presented at that
time. We expect that any RTO/ISO seeking to synchronize shortage
pricing with the settlement interval will set forth compelling reasons
as to why it is necessary based upon the unique nature of the RTO/ISO.
    208. We will not dictate how RTOs/ISOs must implement the reforms
set forth in the Final Rule from a technical perspective. Nevertheless,
we recommend that wherever possible, the RTO/ISO should consider using
existing metering equipment and current data collection processes, such
as the process currently being explored by PJM.\325\
---------------------------------------------------------------------------

    \325\ PJM Comments at 3.
---------------------------------------------------------------------------

    209. With regard to the comments concerning the costs of
implementing the NOPR proposals, we find that some of these costs
appear to be overstated, taken as a whole. For example, PJM's use of
its state estimator and telemetry may reduce, if not eliminate, the
need for new five-minute revenue quality meters; and it is unclear, in
the case of the Concerned Cooperatives, why costs equal to several more
full-time employees would need to be incurred on an annual basis as a
result of the NOPR reform. In any event, we find that the value of the
benefits of more accurate pricing under the proposed rule described in
the NOPR, as recognized by the vast majority of commenters in this
proceeding, and the net present value of the future increases in market
surplus, although difficult to quantify with precision, are likely to
outweigh any one-time implementation costs.
    210. We reject the proposal to require RTOs/ISOs to conduct a cost-
benefit analysis before implementing the settlement reform.\326\ The
Commission has not previously conducted such analyses when it has
considered whether to require various market reforms.\327\ Also, since
many of the expected benefits will occur in the long-run due to changes
in marginal investments and enhancements resulting from other price
formation reforms, there is limited ability to quantify the short-run
benefits before adopting these reforms.\328\ We agree with the PJM
Market Monitor's assertion that, while the costs of implementation

may be approximated, calculating the efficiency benefits of
implementing five-minute settlements is effectively impossible.\329\
---------------------------------------------------------------------------

    \326\ APPA and NRECA Comments at 4.
    \327\ Cf. Order No. 719-A, FERC Stats. & Regs. ] 31,292 at P 179
(``For instance, although we believe that cost-benefit analyses can
be useful in analyzing new projects, we are unconvinced that the
Commission should mandate cost-benefit analyses in all circumstances
where an RTO or ISO engages in a major initiative'').
    \328\ EPSA Comments, Pope Aff. at 13-14.
    \329\ PJM Market Monitor Comments at 2-3.
---------------------------------------------------------------------------

D. Requests Beyond the Scope of This Proceeding

1. Comments
    211. Commenters raised issues that are not discussed above and that
are outside of the scope of this rulemaking. EPSA states that the
Commission and RTOs/ISOs must move expeditiously on the reforms
proposed in the NOPR as well as others identified in the price
formation proceeding that encourage economically efficient decisions
about resource entry and exit.\330\
---------------------------------------------------------------------------

    \330\ EPSA Comments at 11.
---------------------------------------------------------------------------

    212. PJM Power Providers and Exelon urge the Commission to focus on
reducing uplift and remedying its causes as well as market power
mitigation, operator actions, and other issues.\331\ PJM Power
Providers, Exelon, EPSA, and NGSA also encourage Commission action on
reforming the energy offer cap.\332\
---------------------------------------------------------------------------

    \331\ PJM Power Providers Comments at 7; Exelon Comments at 8.
    \332\ PJM Power Providers Comments at 6; EPSA Comments at 13-15;
Exelon Comments at 8-9; NGSA Comments at 6 (citing NGSA Comments,
Docket No. ER15-623-000 (filed Jan. 20, 2015)).
---------------------------------------------------------------------------

    213. ELCON, Westar, TAPS, and Inertia Power and DC Energy recognize
the interconnected nature of the issues in the price formation
proceeding. ELCON urges the Commission to consolidate any additional
price formation proposals into a single NOPR.\333\ Westar states that
the Commission should consider the NOPR in conjunction with other items
identified in the price formation proceedings.\334\ TAPS states that
RTOs/ISOs should have the flexibility to comply with all price
formation rulemakings in a way that coordinates implementation and
reduces the possibility of overlapping modifications of software and
hardware.\335\ Inertia Power and DC Energy asks the Commission to be
mindful of other system benefits that may result from the required
software and hardware upgrades in the RTO/ISOs.\336\
---------------------------------------------------------------------------

    \333\ ELCON Comments at 7.
    \334\ Westar Comments at 2-3.
    \335\ TAPS Comments at 6.
    \336\ Inertia Power and DC Energy Comments at 8.
---------------------------------------------------------------------------

    214. EEI and EPSA reiterate their prior comments regarding common
principles that should guide the discussion of price formation: (1)
Dispatch-based pricing; (2) efficient commitment that will provide
accurate day-ahead and real-time price signals; and (3) transparency
with regard to out-of-market actions and payments.\337\ EEI further
states that the Commission should consider issues related to improving
the transparency of LMPs by addressing the treatment of start-up and
no-load costs, and operator actions that result in out-of-market
payments.\338\
---------------------------------------------------------------------------

    \337\ EEI Comments at 4-5 (citing EEI Comments, Docket No. AD14-
14-000, at 2 (filed Mar. 6, 2015)); EPSA Comments at 12 and Att. B.
    \338\ EEI Comments at 6.
---------------------------------------------------------------------------

    215. Westar requests that the Commission encourage RTOs/ISOs to
clarify what costs may constitute marginal costs.\339\ Additionally, XO
Energy lists many benefits of a day-ahead transmission product, and
recommends the implementation of such a product across all RTOs/
ISOs.\340\
---------------------------------------------------------------------------

    \339\ Westar Comments at 3.
    \340\ XO Energy Comments at 2-3 (citing MISO, Virtual Spread Bid
Proposal Stakeholder Workshop, at 10 (Nov. 18, 2013)).
---------------------------------------------------------------------------

    216. Financial Marketers Coalition and XO Energy assert that while
the NOPR addresses settlement intervals for generation (supply),
similar reforms are needed for the intervals in which load is
forecasted, bid and settled in order to eliminate the mismatch between
generation and load.\341\
---------------------------------------------------------------------------

    \341\ Financial Marketers Coalition Comments at 4-6; XO Energy
Comments at 3-4.
---------------------------------------------------------------------------

    217. Entergy Nuclear Power Marketing and NEI state that although
the reforms proposed in the NOPR will improve price formation for
resources operating in real-time, they will not improve the outlook for
baseload resources such as nuclear plants typically fully committed in
the day-ahead market.\342\
---------------------------------------------------------------------------

    \342\ Entergy Nuclear Power Marketing Comments at 2-3; NEI
Comments at 15.
---------------------------------------------------------------------------

    218. NEI recommends various changes to price formation to better
ensure that the market clearing price reflects all of the costs
associated with reliably providing service to the market.\343\
---------------------------------------------------------------------------

    \343\ NEI Comments at 15-16.
---------------------------------------------------------------------------

    219. With respect to other issues, DTE requests clarification from
the Commission that market participants will not have to change the
manner in which they currently net purchases and sales for purposes of
FERC Form No. 1.\344\ The SPP Market Monitor raises look-ahead modeling
concerns.\345\ Powerex has concerns regarding steps CAISO takes to
minimize the occurrence of shortages (as opposed to when shortage
pricing occurs) \346\ and Public Interest Organizations have a concern
regarding possible barriers to the participation of demand response in
RTO/ISO markets.\347\
---------------------------------------------------------------------------

    \344\ DTE Comments at 6.
    \345\ PSEG Comments at 14; SPP Market Monitor at 4-7; Westar
Comments at 3.
    \346\ Powerex Comments at 9-13.
    \347\ Public Interest Organizations Comments at 4-5.
---------------------------------------------------------------------------

    220. Referencing the NOPR's discussion of the role that look-ahead
tools can play in mitigating seemingly artificial shortages, the SPP
Market Monitor also requests the Commission clarify that look-ahead
models incorporate administrative pricing in their least cost
evaluation before choosing unit commitments to relieve shortages.\348\
---------------------------------------------------------------------------

    \348\ SPP Market Monitor Comments at 7.
---------------------------------------------------------------------------

    221. Powerex argues that further Commission action is necessary to
ensure that RTOs/ISOs refrain from using more general tariff provisions
and non-tariff protocols, including out-of-market procurement and other
operator interventions, to prevent shortage pricing from being
triggered or otherwise prevent scarcity from being reflected in market
prices.\349\
---------------------------------------------------------------------------

    \349\ Powerex Comments at 9.
---------------------------------------------------------------------------

    222. Dominion questions if the proposed settlement reforms require
further consideration of the interactions between the day-ahead and
real-time markets. Specifically, Dominion suggests that changes may be
necessary to how the RTOs/ISOs calculate generator deviations in the
real-time market from their day-ahead schedules.\350\
---------------------------------------------------------------------------

    \350\ Dominion Comments at 3-4.
---------------------------------------------------------------------------

    223. ESA requests that the Commission consider five-minute
scheduling once it implements five-minute intervals to better access
the greater operational flexibility of fast-ramping resources like
energy storage.\351\
---------------------------------------------------------------------------

    \351\ ESA Comments at 4-5.
---------------------------------------------------------------------------

    224. Powerex requests that the Commission require each RTO/ISO to:
(1) Identify all out-of-market actions or procurement tools that it
uses, or is authorized to use, to manage its system; and (2) propose
tariff amendments to ensure that these actions are appropriately
reflected in prices or, alternatively, demonstrate that its existing
tariff provisions already achieve such a result.\352\
---------------------------------------------------------------------------

    \352\ Powerex Comments at 12-13.
---------------------------------------------------------------------------

    225. Appian Way states that the instant proposals encompassed by
this NOPR are insufficient to ensure proper shortage pricing. Appian
Way adds that some RTOs/ISOs will continue to have defective pricing
unless and until the Commission requires them to establish pricing
rules that ensure prices rise to scarcity levels when shortage
conditions occur that require the RTO/ISO to call

demand response in order to serve load.\353\
---------------------------------------------------------------------------

    \353\ Appian Way Comments at 2.
---------------------------------------------------------------------------

    226. Inertia Power and DC Energy state that when operating reserves
and other ancillary services are priced ``out of market,'' it prevents
the triggering of shortage pricing and circumvents the intent of the
NOPR.\354\
---------------------------------------------------------------------------

    \354\ Inertia Power Comments at 5-6.
---------------------------------------------------------------------------

    227. Potomac Economics states that the Commission's focus on
shortage pricing should extend to transmission shortages.\355\
---------------------------------------------------------------------------

    \355\ Potomac Economics Comments at 11.
---------------------------------------------------------------------------

    228. Public Interest Organizations state that if the Commission
carries out the shortage pricing proposal as set forth in the NOPR, it
should simultaneously ensure that demand-side resources can respond to
those prices to reduce the potential for unjust and unreasonable
rates.\356\
---------------------------------------------------------------------------

    \356\ Public Interest Organizations Comments at 3-5.
---------------------------------------------------------------------------

    229. Mr. Lively maintains that shortages should be viewed as a
continuum, not as a shortage versus non-shortage issue. Mr. Lively
cites a paper he wrote that discusses using Area Control Error (ACE) in
a pricing mechanism to adjust the nominal price of electricity to
determine a settlement price.\357\
---------------------------------------------------------------------------

    \357\ Mr. Lively Comments at 3-4 (filed Nov. 23, 2015).
---------------------------------------------------------------------------

2. Commission Determination
    230. 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. Many of the issues raised by commenters
may be relevant in other price formation proceedings,\358\ but they go
beyond the limited issues in this proceeding, which deals only with the
settlement interval proposal and the trigger for shortage pricing.
Accordingly, we will not address those issues here.
---------------------------------------------------------------------------

    \358\ See, e.g., Offer Caps in Markets Operated by Regional
Transmission Organizations and Independent System Operators, Notice
of Proposed Rulemaking, 81 FR 5591 (Feb. 4, 2016), FERC Stats. &
Regs. ] 32,714 (2016), Price Formation in Energy and Ancillary
Services Markets Operated by Regional Transmission Organizations and
Independent System Operators, 153 FERC ] 61,221 (2015).
---------------------------------------------------------------------------

IV. Information Collection Statement

    231. The Paperwork Reduction Act (PRA) \359\ 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,\360\ 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.
---------------------------------------------------------------------------

    \359\ 44 U.S.C. 3501-3520 (2012).
    \360\ 5 CFR part 1320 (2015).
---------------------------------------------------------------------------

    232. In this Final Rule, we are amending the Commission's
regulations to improve the operation of organized wholesale electric
power markets operated by RTOs and ISOs. We require that each RTO/ISO
align settlement and dispatch intervals by: (1) Settling energy
transactions in its real-time markets at the same time interval it
dispatches energy; (2) settling operating reserves transactions in its
real-time markets at the same time interval it prices operating
reserves; and (3) settling intertie transactions in the same time
interval it schedules intertie transactions. We also require that each
RTO/ISO trigger shortage pricing for any interval that prices both
energy and operating reserves in which a shortage of energy or
operating reserves is indicated during the pricing of resources for
that interval. The reforms required in this Final Rule require a one-
time tariff filing due 120 days after the effective date of this Final
Rule. With regard to those RTOs/ISOs that believe that they already
comply with the reforms required here, they can demonstrate their
compliance in their compliance filing. The Commission will submit the
proposed reporting requirements to OMB for its review and approval
under section 3507(d) of the Paperwork Reduction Act.\361\
---------------------------------------------------------------------------

    \361\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    233. Although the Commission stated in the NOPR that it expects the
adoption of the reforms proposed to provide significant benefits,\362\
the Commission solicited comments on the accuracy of provided burden
and cost estimates set forth in the NOPR 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) hardware, software,
and business processes changes; (2) increased data storage and
validation; (3) changes to market participant metering or other
equipment; and (4) processes for RTOs/ISOs to vet proposed changes
amongst their stakeholders. The Commission also sought comment on
whether changes in settlement systems would disrupt existing
contractual relationships and, if so, what burdens this might impose
and how the Commission should address any potential issues resulting
from such disruption.
    234. The Commission received responses regarding the costs of
implementing the reforms described in the NOPR; \363\ however we find
that those costs do not fall under the definition of ``burden'' as
defined by OMB's regulations.\364\ Therefore, an analysis of those
costs is not relevant to our analysis under the PRA.
---------------------------------------------------------------------------

    \363\ See supra PP 201-203.
    \364\ ``Burden'' is defined as ``the total time, effort, or
financial resources expended by persons to generate, maintain,
retain, or disclose or provide information to or for a Federal
Agency, including . . . (ii) Developing, acquiring, installing, and
utilizing technology and systems for the purpose of collecting,
validating, and verifying information; (iii) Developing, acquiring,
installing, and utilizing technology and systems for the purpose of
processing and maintaining information; (iv) Developing, acquiring,
installing, and utilizing technology and systems for the purpose of
disclosing and providing information. . . .'' 5 CFR 1320.3(b)(1)
(2015). We respond to comments regarding other costs not related to
``burden'' (such as hardware and software) in PP 209-210 above.
---------------------------------------------------------------------------

    Burden Estimate and Information Collection Costs: We believe that
the burden estimates below are representative of the average burden on
respondents. The estimated burden and cost \365\ for the requirements
contained in this Final Rule follow.\366\
---------------------------------------------------------------------------

    \365\ The estimated hourly cost (salary plus benefits) provided
in this section are 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#00-0000)
and scaled to reflect benefits using the relative importance of
employer costs in employee compensation from December 2015 (released
March 10, 2016 and 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 Security Analyst (code 15-1122), $57.99
    Accountant and Auditor (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
    Computer and Information Systems Manager (code 11-3021), $91.63
    Management (code 11-0000), $88.94
    The average hourly cost (salary plus benefits), weighting all of
these skill sets evenly, is $73.13. For the calculations here, the
Commission rounds it to $73 per hour.
    \366\ The RTOs/ISOs (CAISO, ISO-NE., MISO, NYISO, PJM, and SPP)
are required to comply with the reforms in this Final Rule. Three
RTOs/ISOs (ISO-NE., MISO, and PJM) currently do not align real-time
settlement with dispatch intervals and thus likely would be burdened
more by that aspect of the reforms in this Final Rule.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         Annual number of
FERC 516D,\367\ as implemented in       Number of         responses per     Total number of    Average burden hours & cost   Annual burden hours & total
    final rule in RM15-24-000          respondents          respondent         responses              per response                   annual cost
                                   (1)................                (2)    (1) x (2) = (3)  (4).........................  (3) x (4) = (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Tariff filings one-time in Year    3 RTOs or ISOs.....                  1                  3  80 hrs; $5,840..............  240 hrs; $17,520.
 1, for RTOs/ISOs that currently
 align real-time settlement with
 dispatch intervals.
Tariff filings one-time in Year    3 RTOs or ISOs.....                  1                  3  160 hrs; 11,680.............  480 hrs; 35,040.
 1, for RTOs/ISOs that do not
 currently align real-time
 settlement with dispatch
 intervals.
                                                       -------------------------------------------------------------------------------------------------
    Total (one-time in Year 1)     6..................  .................                  6  ............................  720 hrs.; 52,560.
     \368\.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Title: FERC-516D, Electric Rate Schedules and Tariff Filings in
Docket RM15-24.
    Action: A new information collection.
    OMB Control No.: To Be Determined.
    Respondents for This Rulemaking: RTOs and ISOs.
    Frequency of Information: One-time during Year one.
    Necessity of Information: The Federal Energy Regulatory Commission
implements this rule to improve competitive wholesale electric markets
in the RTO and ISO regions.
---------------------------------------------------------------------------

    \367\ The information collection requirements and related burden
for the NOPR in Docket No. RM15-24 were submitted to OMB under FERC-
516 (Electric Rate Schedules and Tariff Filings, OMB Control No.
1902-0096). Currently, there is an unrelated package (in Docket No.
PL15-3) pending OMB review under FERC-516. Because only one item per
OMB Control No. can be pending OMB review at a time, the reporting
requirements in the Final Rule in RM15-24 are being submitted to OMB
for review under FERC-516D (a temporary `placeholder' collection
number, OMB Control No. to be determined). Long-term, the staff
expects to transfer administratively the requirements and burden of
this final rule to FERC-516 (OMB Control No. 1902-0096) from FERC-
516D.
    \368\ The burden costs (one-time in Year 1) consist of filing
proposed tariff changes to the Commission within four months of the
effective date of the Final Rule.
---------------------------------------------------------------------------

    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.
    235. 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]. Due to security concerns, comments
should be sent electronically to the following email address:
<EMAIL_ADDRESS>Comments submitted to OMB should refer to
FERC-516D and OMB Control No. To Be Determined.

V. Environmental Analysis

    236. 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.\369\ We
conclude 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 FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\370\
---------------------------------------------------------------------------

    \369\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \370\ 18 CFR 380.4(a)(15) (2015).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    237. The Regulatory Flexibility Act of 1980 (RFA) \371\ 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.
---------------------------------------------------------------------------

    \371\ 5 U.S.C. 601-612 (2012).
---------------------------------------------------------------------------

    238. This rule applies to six RTOs/ISOs (all of which are
transmission organizations). The three RTOs/ISOs that do not currently
align real-time settlement with dispatch intervals will have to incur a
one-time cost to upgrade their hardware and software. These
enhancements will be needed to allow the RTOs/ISOs to process
settlement data on a more granular level. That one-time cost (spread
over Years 1 and 2) for hardware and software for each of those three
RTOs/ISOs is estimated to be an average of $3 million (a total of $9
million for those three RTOs/ISOs). The average estimated burden cost
(one-time in Year 1) to each of the RTOs/ISOs is $8,760 (total of
$52,560 for all six RTOs/ISOs). Therefore the estimated total cost
(burden, hardware, and software) over Years 1 and 2 for all six RTOs/
ISOs is $9,052,560.

    239. The RTOs/ISOs, however, are not small entities, as defined by
the RFA.\372\ 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 of a small entity: ``Not dominant in its field of
operation.'' As a result, we certify that the reforms required by this
Final Rule would not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------

    \372\ 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 Administration's regulations at 13 CFR 121.201 (2015)
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) (2012) (citing to section 3 of the Small Business Act,
15 U.S.C. 632 (2012)).
---------------------------------------------------------------------------

VII. Document Availability

    240. 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 FERC's Home Page (http://www.ferc.gov) and in FERC'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.
    241. From FERC'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 excluding the last three digits of this document in the docket
number field.
    242. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at (202)
502-6652 (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>
VIII. Effective Date and Congressional Notification

    243. These regulations are effective September 13, 2016. 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, Reporting and
recordkeeping requirements.

    By the Commission.
    Issued: June 16, 2016.
Kimberly D. Bose,
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 as follows:
0
a. Revise paragraph (g)(1)(iv)(A).
0
b. Add paragraph (g)(1)(vi).

Sec.  35.28  Non-discriminatory open access transmission tariff

* * * * *
    (g) * * *
    (1) * * *
    (iv) * * *
    (A) Each Commission-approved independent system operator and
regional transmission organization must modify its market rules to
allow the market-clearing price during periods of operating reserve
shortage to reach a level that rebalances supply and demand so as to
maintain reliability while providing sufficient provisions for
mitigating market power. Each Commission-approved independent system
operator and regional transmission organization must trigger shortage
pricing for any interval in which a shortage of energy or operating
reserves is indicated during the pricing of resources for that
interval.
* * * * *
    (vi) Settlement intervals. Each Commission-approved independent
system operator and regional transmission organization must settle
energy transactions in its real-time markets at the same time interval
it dispatches energy, must settle operating reserves transactions in
its real-time markets at the same time interval it prices operating
reserves, and must settle intertie transactions at the same time
interval it schedules intertie transactions.
* * * * *
    Note: The following appendix will not be published in the Code of
Federal Regulations.

Appendix: List of Commenters

    The following is a list of the entities that filed comments in
this proceeding, along with the short name/acronym used in this
Final Rule. Unless otherwise noted, all comments were submitted on
November 30, 2015.

Comments

------------------------------------------------------------------------
               Short name/acronym                       Commenter
------------------------------------------------------------------------
AEMA...........................................  Advanced Energy
                                                  Management Alliance.
Ameren.........................................  Ameren Services Company
                                                  (on behalf of Ameren
                                                  Illinois Company and
                                                  Union Electric
                                                  Company).
ANGA...........................................  America's Natural Gas
                                                  Alliance.
APPA and NRECA.................................  American Public Power
                                                  Association and
                                                  National Rural
                                                  Electric Cooperative
                                                  Association.
Appian Way.....................................  Appian Way Energy
                                                  Partners.
CAISO..........................................  California Independent
                                                  System Operator
                                                  Corporation.
CEA............................................  Canadian Electricity
                                                  Association.
Concerned Cooperatives.........................  Hoosier Energy Rural
                                                  Electric Cooperative,
                                                  Inc., Kansas Electric
                                                  Power Cooperative,
                                                  Inc., and North
                                                  Carolina Electric
                                                  Membership
                                                  Corporation.
Delaware Commission............................  Delaware Public Service
                                                  Commission.
Direct Energy..................................  Direct Energy Business,
                                                  LLC and Direct Energy
                                                  Business Marketing,
                                                  LLC.
Dominion.......................................  Dominion Resources
                                                  Services, Inc.
DTE............................................  DTE Electric Company.

Duke...........................................  Duke Energy
                                                  Corporation, Duke
                                                  Energy Progress, LLC,
                                                  Duke Energy Carolinas,
                                                  LLC, Duke Energy
                                                  Kentucky, Inc., Duke
                                                  Energy Indiana, Inc.,
                                                  and Duke Energy Ohio,
                                                  Inc.
EDP Renewables.................................  EDP Renewables North
                                                  America LLC.
EEI............................................  Edison Electric
                                                  Institute.
ELCON..........................................  Electricity Consumers
                                                  Resource Council.
ESA............................................  Energy Storage
                                                  Association.
EPSA...........................................  Electric Power Supply
                                                  Association.
Entergy Nuclear Power Marketing................  Entergy Nuclear Power
                                                  Marketing, LLC.
Exelon.........................................  Exelon Corporation.
Financial Marketers Coalition..................  Financial Marketers
                                                  Coalition.
Golden Spread..................................  Golden Spread Electric
                                                  Cooperative, Inc.
Inertia Power and DC Energy....................  Inertia Power, LP and
                                                  DC Energy, LLC.
IPL............................................  Indianapolis Power &
                                                  Light Company.
ISO/RTO Council................................  ISO/RTO Council.
ISO-NE.........................................  ISO New England Inc.
Mr. Lively.....................................  Mark B. Lively, Utility
                                                  Economic Engineers.
MISO...........................................  Midcontinent
                                                  Independent System
                                                  Operator, Inc.
NEPOOL.........................................  New England Power Pool
                                                  Participants
                                                  Committee.
NEI............................................  Nuclear Energy
                                                  Institute.
New Jersey Board...............................  New Jersey Board of
                                                  Public Utilities.
NGSA...........................................  Natural Gas Supply
                                                  Association.
NYISO..........................................  New York Independent
                                                  System Operator, Inc.
ODEC...........................................  Old Dominion Electric
                                                  Cooperative.
Mr. Centolella.................................  Paul Centolella and
                                                  Associates, L.L.C.
PG&E...........................................  Pacific Gas & Electric
                                                  Company.
PJM............................................  PJM Interconnection,
                                                  L.L.C.
PJM Market Monitor.............................  Monitoring Analytics,
                                                  LLC, Independent
                                                  Market Monitor for
                                                  PJM.
PJM Power Providers............................  PJM Power Providers
                                                  Group.
Potomac Economics..............................  Potomac Economics, Ltd.
Powerex........................................  Powerex Corp.
PSEG...........................................  PSEG Companies (Public
                                                  Service Electric and
                                                  Gas Company, PSEG
                                                  Power LLC, and PSEG
                                                  Energy Resources &
                                                  Trade LLC).
Public Interest Organizations..................  Acadia Center,
                                                  Americans for a Clean
                                                  Energy Grid, Climate +
                                                  Energy Project, Great
                                                  Plains Institute,
                                                  Natural Resources
                                                  Defense Council,
                                                  Sierra Club,
                                                  Sustainable FERC
                                                  Project, Union of
                                                  Concerned Scientists,
                                                  and Wind on the Wires.
SCE............................................  Southern California
                                                  Edison Company.
SPP............................................  Southwest Power Pool,
                                                  Inc.
SPP Market Monitor.............................  Southwest Power Pool,
                                                  Inc. Independent
                                                  Market Monitoring
                                                  Unit.
TAPS...........................................  Transmission Access
                                                  Policy Study Group.
Westar.........................................  Westar Energy, Inc.
XO Energy......................................  XO Energy, LLC.
------------------------------------------------------------------------

                                         Reply or Supplemental Comments
----------------------------------------------------------------------------------------------------------------
             Short name/acronym                         Commenter                       Date submitted
----------------------------------------------------------------------------------------------------------------
Golden Spread..............................  Golden Spread Electric          December 14, 2015.
                                              Cooperative, Inc.
Direct Energy..............................  Direct Energy Business, LLC     March 4, 2016.
                                              and Direct Energy Business
                                              Marketing, LLC.
----------------------------------------------------------------------------------------------------------------

                                                  Late Comments
----------------------------------------------------------------------------------------------------------------
             Short name/acronym                         Commenter                       Date submitted
----------------------------------------------------------------------------------------------------------------
New Jersey Board...........................  New Jersey Board of Public      December 3, 2015.
                                              Utilities.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2016-15196 Filed 6-29-16; 8:45 am]
BILLING CODE 6717-01-P