Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, 42881-42910 [2016-15196]
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Vol. 81
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June 30, 2016
Part III
Department of Energy
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Federal Energy Regulatory Commission
18 CFR Part 35
Settlement Intervals and Shortage Pricing in Markets Operated by Regional
Transmission Organizations and Independent System Operators; Final Rule
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Federal Register / Vol. 81, No. 126 / Thursday, June 30, 2016 / Rules and Regulations
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM15–24–000; Order No. 825]
Settlement Intervals and Shortage
Pricing in Markets Operated by
Regional Transmission Organizations
and Independent System Operators
Federal Energy Regulatory
Commission.
ACTION: Final rule.
AGENCY:
The Federal Energy
Regulatory Commission (Commission) is
revising its regulations to address
certain practices that fail to compensate
resources at prices that reflect the value
of the service resources provide to the
system, thereby distorting price signals,
and in certain instances, creating a
disincentive for resources to respond to
SUMMARY:
dispatch signals. We require that each
regional transmission organization and
independent system operator align
settlement and dispatch intervals by:
Settling energy transactions in its realtime markets at the same time interval
it dispatches energy; settling operating
reserves transactions in its real-time
markets at the same time interval it
prices operating reserves; and settling
intertie transactions in the same time
interval it schedules intertie
transactions. We also require that each
regional transmission organization and
independent system operator 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. Adopting
these reforms will align prices with
resource dispatch instructions and
operating needs, providing appropriate
incentives for resource performance.
DATES: This rule will become effective
September 13, 2016.
FOR FURTHER INFORMATION CONTACT:
Stanley Wolf (Technical Information),
Office of Energy Policy and
Innovation, Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
6841, Stanley.Wolf@ferc.gov
Pamela Quinlan (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
6179, Pamela.Quinlan@ferc.gov
Alicia Cobb (Legal Information), Office
of the General Counsel—Energy
Markets, Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
8501, Alicia.Cobb@ferc.gov
SUPPLEMENTARY INFORMATION:
Order No. 825
Final Rule
Table of Contents
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Paragraph No.
I. Introduction ...............................................................................................................................................................................
II. Background ...............................................................................................................................................................................
III. Discussion ...............................................................................................................................................................................
A. Settlement Interval Reform ..............................................................................................................................................
1. Need for Reform .........................................................................................................................................................
2. Settlement Interval Reform for Energy Transactions and Operating Reserves ......................................................
a. Proposal ...............................................................................................................................................................
i. Energy Transactions .....................................................................................................................................
ii. Operating Reserves ......................................................................................................................................
b. Current Practices in the RTOs/ISOs ..................................................................................................................
i. Energy Transactions .....................................................................................................................................
ii. Operating Reserves ......................................................................................................................................
c. Comments on the Proposed Settlement Interval Reform .................................................................................
i. Comments From the RTOs/ISOs .................................................................................................................
ii. Comments by Market Monitors ..................................................................................................................
iii. Comments Supporting the Proposed Settlement Interval Reform ..........................................................
iv. Comments Opposed to the Proposed Settlement Interval Reform ..........................................................
d. Commission Determination ................................................................................................................................
i. Energy Transactions .....................................................................................................................................
ii. Operating Reserves ......................................................................................................................................
3. Interties .......................................................................................................................................................................
a. Commission Request for Comments ..................................................................................................................
i. Comments by RTOs/ISOs .............................................................................................................................
ii. Comments by Market Monitors ..................................................................................................................
iii. Comments in Support of Applying Settlement Reform to Interties .......................................................
iv. Comments Opposed To Applying Settlement Reform to Interties ..........................................................
b. Commission Determination ................................................................................................................................
4. Demand Response Resources ....................................................................................................................................
a. Comments ............................................................................................................................................................
b. Commission Determination ................................................................................................................................
5. Load ............................................................................................................................................................................
a. Comments ............................................................................................................................................................
b. Commission Determination ................................................................................................................................
B. Shortage Pricing Reform ...................................................................................................................................................
1. Need for Reform .........................................................................................................................................................
2. NOPR Proposal ...........................................................................................................................................................
3. Comments on the Proposed Shortage Pricing Reform .............................................................................................
a. Comments by RTOs/ISOs ...................................................................................................................................
b. Comments by Market Monitors ..........................................................................................................................
c. Comments Supporting the Shortage Pricing Reform ........................................................................................
d. Comments Recommending Changes to the Shortage Pricing Reform .............................................................
e. Comments Opposed to the Proposed Shortage Pricing Reform .......................................................................
4. Commission Determination .......................................................................................................................................
C. Compliance and Implementation .....................................................................................................................................
1. Commission Proposal ................................................................................................................................................
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42883
Paragraph No.
2. Comments ...................................................................................................................................................................
a. Comments From RTOs/ISOs ..............................................................................................................................
b. Comments Urging Flexibility in Implementation .............................................................................................
c. Compliance Filing Deadline ...............................................................................................................................
d. Implementation Deadline ...................................................................................................................................
e. Simultaneous Implementation ...........................................................................................................................
f. Costs .....................................................................................................................................................................
3. Commission Determination .......................................................................................................................................
D. Requests Beyond the Scope of This Proceeding .............................................................................................................
1. Comments ...................................................................................................................................................................
2. Commission Determination .......................................................................................................................................
IV. Information Collection Statement ..........................................................................................................................................
V. Environmental Analysis ..........................................................................................................................................................
VI. Regulatory Flexibility Act ......................................................................................................................................................
VII. Document Availability ..........................................................................................................................................................
VIII. Effective Date and Congressional Notification ...................................................................................................................
APPENDIX: List of Commenters.
I. Introduction
1. In this Final Rule, we address
certain practices that fail to compensate
resources at prices that reflect the value
of the service resources provide to the
system, thereby distorting price signals,
and in certain instances, creating a
disincentive for resources to respond to
dispatch signals. We require, pursuant
to section 206 of the Federal Power Act
(FPA),1 that each regional transmission
organization (RTO) and independent
system operator (ISO) align settlement
and dispatch 2 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; 3 and (3) settling
1 16
U.S.C. 824e (2012).
mentioned in the Notice of Proposed
Rulemaking, the Commission sometimes uses the
term ‘‘dispatch’’ as shorthand when describing how
RTOs/ISOs acquire and price energy and operating
reserves. With respect to operating reserves, the
Commission uses dispatch to describe the intervals
at which they are acquired and priced. See
Settlement Intervals and Shortage Pricing in
Markets Operated by Regional Transmission
Organizations and Independent System Operators,
80 FR 58,393 (Sept. 29, 2015), FERC Stats. & Regs.
¶ 32,710, at P 1 (2015) (NOPR).
3 Operating reserves refer to certain ancillary
services procured in the wholesale market, although
they are often defined differently in each RTO/ISO.
Operating reserves typically include: (a) Regulating
Reserve, used to account for very short-term
deviations between supply and demand (e.g., 4 to
6 seconds); (b) Spinning, or Synchronous Reserve,
which is capacity held in reserve and synchronized
to the grid and able to respond within a relatively
short amount of time (e.g., within 10 minutes), to
be used in case of a contingency, such as the loss
of a generator; and (c) Non-Spinning Reserve,
capacity that is not synchronized to the grid and
which can take longer to respond (e.g., within 10–
30 minutes) in case of a contingency. Federal
Energy Regulatory Commission, Price Formation in
Organized Wholesale Electricity Markets: Staff
Analysis of Shortage Pricing, Docket No. AD14–14–
000, at 3 n.7 (Oct. 2014), http://www.ferc.gov/legal/
staff-reports/2014/AD14-14-pricing-rto-isomarkets.pdf (Shortage Pricing Paper).
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2 As
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intertie transactions 4 in the same time
interval it schedules intertie
transactions (settlement interval
requirements). We also require,
pursuant to section 206 of the FPA, that
each RTO/ISO establish a mechanism 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
(shortage pricing requirement).
2. Some current RTO/ISO settlement
practices fail to reflect the value of
providing a given service, thereby
distorting price signals and failing to
provide appropriate signals for
resources to respond to the actual
operating needs of the market. One such
practice occurs when RTOs/ISOs
dispatch resources every five minutes
but perform settlements based on an
hourly integrated price, or when RTOs/
ISOs schedule intertie transactions
every fifteen minutes, but perform
settlements on an hourly integrated
price. This misalignment between
dispatch and settlement intervals
distorts the price signals sent to
resources and fails to reflect the actual
value of resources responding to
operating needs because compensation
will be based on average output and
average prices across an hour, rather
than output and prices during the
periods of greatest need within a
particular hour.
3. We also find that a second problem
occurs if there is a mismatch between
the time when a system experiences a
shortage of energy and operating
reserves and the time when prices
reflect the shortage condition. This can
be particularly problematic when, for
example, an RTO’s/ISO’s market rules
require a shortage to last a minimum
time period before triggering shortage
4 Intertie transactions are transactions across
RTO/ISO borders, including imports, exports and
wheel-through transactions.
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188
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236
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243
pricing. In this instance, short-term
prices fail to reflect system conditions
and potential reliability costs, as well as
the value of both internal and external
market resources responding to a
dispatch signal. In addition, inaccurate
price signals are provided to market
participants if shortage pricing is still in
effect after the shortage has been
resolved.
4. To address these problems
associated with differing dispatch
intervals and settlement intervals, as
well as with shortage pricing triggers,
we are setting forth the settlement
interval requirements and the shortage
pricing requirement in this Final Rule.5
These settlement interval and shortage
pricing requirements will help ensure
that resources have price signals that
provide incentives to conform their
output to dispatch instructions, and that
prices reflect operating needs at each
dispatch interval.
5. As set forth in the NOPR, we
reiterate the goals of price formation are
to: (1) Maximize market surplus for
consumer and suppliers; (2) provide
correct incentives for market
participants to follow commitment and
dispatch instructions, make efficient
investments in facilities and equipment,
and maintain reliability; (3) provide
transparency so that market participants
understand how prices reflect the actual
marginal cost of serving load and the
operational constraints of reliably
operating the system; and, (4) ensure
that all suppliers have an opportunity to
recover their costs.6
6. As noted in the NOPR, the reforms
adopted in this Final Rule advance at
least two of the Commission’s goals
5 We are not at this time proposing to change the
price paid by any RTO/ISO when shortage pricing
is triggered.
6 See Notice Inviting Post-Technical Workshop
Comments, Docket No. AD14–14–000, at 1 (Jan. 16,
2015); Notice, Docket No. AD14–14–000 (June 19,
2014).
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with respect to price formation. First,
the proposed reforms will help provide
correct incentives for market
participants to follow commitment and
dispatch instructions,7 to make efficient
investments in facilities and equipment,
and to maintain reliability. Specifically,
requiring RTOs/ISOs to align the
settlement and dispatch intervals will
more accurately reward resources that
are providing energy and ancillary
services in periods of the greatest need
and will discourage provision of energy
and ancillary services immediately
following periods of system stress.
Doing so will enhance the incentive to
follow an RTO’s/ISO’s dispatch signal
and thus help maintain system
reliability. This reform will also reward
resources that can flexibly respond to
system needs, thus creating an incentive
for resources to make efficient
investments in facilities and equipment.
Similarly, implementing shortage
pricing for any dispatch interval during
which a shortage of energy or operating
reserves occurs will provide an
incentive for resources to ensure that
they are available to respond to high
prices, which should help alleviate
shortages and avoid shortage pricing
during subsequent dispatch intervals.
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.
7. Second, the proposed reforms will
also help provide transparency and
certainty so that market participants
understand how compensation and
prices reflect the actual marginal cost of
serving load and the operational
constraints of reliably operating the
system. Requiring settlement intervals
to match dispatch intervals will make
resource compensation more
transparent by, among other things,
increasing the proportion of resource
payment provided through payments of
energy and operating reserves rather
than uplift. Further, requiring RTOs/
ISOs to trigger shortage pricing for an
interval in which a shortage of energy or
operating reserves is indicated during
the pricing of resources for that interval
will ensure that prices transparently
reflect the operational constraints of
7 The Commission notes that the reforms
proposed herein would further augment existing
mechanisms in each RTO/ISO market that provide
incentives to follow dispatch instructions, such as
penalties for excessive or deficient energy and the
allocation of commitment and dispatch costs to
deviations from energy dispatch targets. See, e.g.,
MISO, FERC Electric Tariff, 40.3.3(a) (36.0.0)
(allocating Revenue Sufficiency Guarantee costs to,
inter alia, resources providing excessive or deficient
energy), 40.3.4 (33.0.0) (charges for excessive or
deficient energy deployment).
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reliably operating the system. This
increased transparency, in turn, better
informs decisions to build or maintain
resources and enhances consumers’
ability to hedge. The benefits
summarized above and discussed in
detail below would ultimately help to
ensure just and reasonable rates.
8. As discussed below, we require
each RTO/ISO to submit a compliance
filing with the tariff changes needed to
implement this Final Rule within 120
days of the Final Rule’s effective date.
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.8
II. Background
9. The Commission has addressed
price formation in organized markets on
prior occasions. For example, in Order
No. 719, the Commission addressed
shortage pricing 9 and required RTOs/
ISOs to develop and implement shortage
pricing rules that would apply during
operating reserve shortages to ‘‘ensure
that the market price for energy reflects
the value of energy during an operating
reserve shortage.’’ 10 The Commission
required such rules out of concern that
inappropriate price signals during an
operating reserve shortage would
provide an insufficient incentive for
market participants to take appropriate
actions.
10. In June 2014, the Commission
initiated a proceeding, in Docket No.
AD14–14–000, to evaluate issues
regarding price formation in the energy
and ancillary services markets operated
by RTOs/ISOs (price formation
proceeding). In the notice initiating that
proceeding, the Commission stated that
there may be opportunities for the
RTOs/ISOs to improve the energy and
ancillary services price formation
process. As set forth in the notice,
locational marginal prices (LMP) and
market-clearing prices used in energy
and ancillary services markets ideally
8 The Commission has followed a similar
approach with the timelines for compliance and
implementation in the past. See, e.g., Frequency
Regulation Compensation in the Organized
Wholesale Power Markets, Order No. 755, FERC
Stats. & Regs. ¶ 31,324, at P 201 (2011), reh’g
denied, Order No. 755–A, 138 FERC ¶ 61,123
(2012).
9 Wholesale Competition in Regions with
Organized Electric Markets, Order No. 719, FERC
Stats. & Regs. ¶ 31,281, at PP 192–194 (2008), order
on reh’g, Order No. 719–A, FERC Stats. & Regs.
¶ 31,292, order on reh’g, Order No. 719–B, 129
FERC ¶ 61,252 (2009).
10 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at
P 194.
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‘‘would reflect the true marginal cost of
production, taking into account all
physical system constraints, and these
prices would fully compensate all
resources for the variable cost of
providing service.’’ 11 Pursuant to the
notice, staff conducted outreach and
convened technical workshops on the
following four general issues: (1) Use of
uplift payments; (2) offer price
mitigation and offer price caps; (3)
scarcity and shortage pricing; and (4)
operator actions that affect prices.12 The
Commission also released staff reports
on these topics. In one of those reports,
issued in October 2014, staff analyzed
shortage pricing issues.13
11. In its January 2015 Notice Inviting
Comments, the Commission requested
comments on questions that arose from
the price formation technical
workshops.14 In response, among other
price formation issues, commenters
addressed settlement intervals and
shortage pricing.
12. On September 17, 2015, the
Commission issued a NOPR proposing
to require that each RTO/ISO: (1) Settle
energy transactions in its real-time
markets at the same time interval it
dispatches and prices energy, and settle
operating reserves transactions in its
real-time markets at the same time
interval it prices operating reserves; and
(2) trigger shortage pricing for any
dispatch interval during which a
shortage of energy or operating reserves
occurs.15 The Commission sought
comments on these proposals, and
sought comment on: (1) Whether
settlement interval reforms are
appropriate for intertie transactions that
are scheduled on intervals different
from the intervals on which RTOs/ISOs
dispatch internal real-time energy; and
(2) whether it is appropriate to align the
settlement interval for intertie
transactions with external scheduling
intervals, e.g., fifteen minutes.16
Additionally, the Commission sought
comment on whether to require that
RTOs/ISOs settle real-time operating
reserves transactions at the same
interval as real-time energy dispatch
and settlement intervals or whether a
settlement interval that differs from an
RTO’s/ISO’s real-time energy dispatch
interval would be appropriate for some
operating reserves transactions.17
11 Notice, Docket No. AD14–14–000, at 2 (June 19,
2014).
12 Id. at 1, 3–4.
13 See Shortage Pricing Paper.
14 Notice Inviting Post-Technical Workshop
Comments, Docket No. AD14–14–000 (Jan. 16,
2015).
15 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 14.
16 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 39.
17 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 40.
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Finally, the Commission sought
comment on the implementation
schedule and the costs of
implementation.18 A list of commenters
and the abbreviated names used for
them in this Final Rule appears in the
Appendix.
III. Discussion
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A. Settlement Interval Reform
1. Need for Reform
13. In the NOPR,19 the Commission
preliminarily found that the current
RTO/ISO settlement practice of using
hourly integrated prices for real-time
settlement and five-minute dispatch
instructions may fail to reflect the value
of providing a given service, and may
contribute to lack of a response to the
actual operating needs of those markets.
In addition, the Commission stated that
the use of hourly integrated prices for
real-time settlement may discourage
resources from following five-minute
dispatch instructions, and may increase
the need for uplift payments. Therefore,
the Commission preliminarily found
that the use of hourly integrated prices
for real-time settlement may result in
rates that are unjust and unreasonable.
14. Commenters generally agree with
the Commission’s preliminary finding
regarding the settlement interval
proposal. For example, EPSA states that
‘‘[w]hen real-time settlements for
generation or dispatchable demand are
calculated based on hourly prices that
are the simple average of sub-hourly
prices resulting from the actual
dispatch, there is a distortion to the realtime price signal impacting both
reliability and efficiency.’’ 20 Similarly,
Potomac Economics states that the
inconsistency between five-minute
dispatch instructions and hourlyaverage price settlement intervals
‘‘creates incentives for generators to not
follow the dispatch signal or to simply
be inflexible by (a) restricting dispatch
range (the difference between a
generator’s minimum dispatch level and
maximum dispatch level) or (b) offering
a slower dispatch ramp rate.’’ 21
Potomac Economics notes that while
MISO makes uplift payments to
generators to alleviate these incentive
issues, such payments are ‘‘an inferior
substitute for a true alignment where
each generator, importer or exporter
would settle based on the actual value
of energy corresponding with its
production or transactions in each five18 NOPR,
FERC Stats. & Regs. ¶ 32,710 at PP 56,
2. Settlement Interval Reform for Energy
Transactions and Operating Reserves
a. Proposal
i. Energy Transactions
17. In the NOPR, the Commission
proposed to require that each RTO/ISO
settle energy transactions in its real-time
markets at the same time interval it
dispatches energy. The Commission
preliminarily found the use of hourly
integrated prices for real-time settlement
may have the unintended effect of
distorting price signals, and, in certain
instances, contributing to market
participants’ failing to respond
appropriately to operating needs.26
Specifically, the Commission stated that
hourly integrated prices for real-time
settlement may: (1) Not accurately
reflect the value a resource provides to
the system; (2) discourage resources
from following dispatch instructions;
22 Potomac
Economics Comments at 4–5.
Comments at 2.
24 APPA and NRECA Comments at 4.
25 Direct Energy Comments at 6.
26 NOPR, FERC Stats. & Regs. ¶ 32,710 at PP 26–
33.
and (3) cause increased uplift payments.
Therefore, the Commission
preliminarily found that the use of
hourly integrated prices for real-time
settlement may result in rates that are
unjust and unreasonable.
18. To remedy any potentially unjust
and unreasonable rates caused by the
use of hourly integrated prices for realtime settlement, the Commission
proposed in the NOPR to require that
each RTO/ISO settle energy transactions
in its real-time markets at the same time
interval it dispatches energy.27
19. The Commission explained that in
the short-term, the settlement interval
proposal should improve incentives for
resources to respond quickly to dispatch
instructions, which should in turn lead
to operators taking fewer out-of-market
actions to ensure that supply meets
demand. The Commission noted that by
improving resources’ response to
dispatch instructions, the settlement
interval proposal would result in a more
efficient use of generation resources to
the benefit of all consumers. In the longterm, the Commission maintained that
these reforms should provide more
accurate price signals, which should
provide, together with other market
price signals, the appropriate incentives
to build or maintain resources that can
respond to energy or operating reserve
deficiencies.28
20. In addition, the Commission
noted, where settlement and dispatch
intervals are aligned, resources
dispatched economically during highpriced periods would receive those
higher prices rather than an hourly
average of the dispatch interval LMPs,
thereby reducing the need to make
uplift payments.
ii. Operating Reserves
21. The Commission proposed
requiring that each RTO/ISO ‘‘settle
operating reserves transactions in its
real-time markets at the same time
interval it prices operating reserves.’’ 29
Although the Commission noted that
dispatch and pricing of energy and
operating reserves are closely linked
through co-optimization in the real-time
market, it also noted that certain RTOs/
ISOs acquire operating reserves on a
different time interval than they
dispatch energy.30 The Commission
sought comment on whether the
Commission should require RTOs/ISOs
to settle all real-time operating reserves
transactions at the same time interval as
real-time energy dispatch and
23 ELCON
60.
19 NOPR,
FERC Stats. & Regs. ¶ 32,710 at PP 26–
33.
20 EPSA
minute interval.’’ 22 ELCON asserts that
hourly prices do not ‘‘reflect system
needs and costs, and may result in over
or under recovery of costs depending on
how the shortage plays out during the
hour. When SPP moved to sub-hourly
settlements, overall system costs were
lower.’’ 23
15. In some instances, commenters
assert that the Commission should not
affirm its preliminary finding on the
settlement interval proposal. APPA and
NRECA assert that Commission
approval of any five-minute settlement
implementation process should require
vetting and approval by the RTOs’/ISOs’
stakeholders.24 Direct Energy asserts
that the Commission should solicit
further information from the RTOs/ISOs
before determining whether or not to
direct settlement interval reforms.25
16. Based on analysis of the record,
we adopt our preliminary findings, and,
as described in detail below, conclude
that certain RTO/ISO settlement
practices are not just and reasonable and
are unduly discriminatory and
preferential. Accordingly, we direct
each RTO/ISO to align its settlement
and dispatch intervals by settling energy
transactions in its real-time markets at
the same time interval it dispatches
energy, settling operating reserves
transactions in its real-time markets at
the same time interval it prices
operating reserves, and settling intertie
transactions in the same time interval it
schedules intertie transactions, as
discussed further herein.
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Comments, Pope Aff. at 2–3.
Economics Comments at 4.
21 Potomac
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27 NOPR,
FERC Stats. & Regs. ¶ 32,710 at P 34.
FERC Stats. & Regs. ¶ 32,710 at P 35.
29 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.
30 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 40.
28 NOPR,
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settlement intervals, or whether a
settlement interval that differs from an
RTO’s/ISO’s real-time energy dispatch
interval would be appropriate for some
operating reserves transactions.31
b. Current Practices in the RTOs/ISOs
i. Energy Transactions
22. The following table describes how
each RTO/ISO currently dispatches and
settles real-time energy transactions:
TABLE 1—RTO/ISO DISPATCH AND
SETTLEMENT INTERVALS FOR ENERGY
Real-time
dispatch 32
(minutes)
CAISO
ISO–NE
MISO
NYISO
PJM
SPP
5
5
5
5
5
5
Real-time
settlement 33
5 minute.
hourly average.
hourly average.
5 minute.
hourly average.
5 minute.
ii. Operating Reserves
23. The RTOs/ISOs vary in how they
settle and treat operating reserves. For
example, CAISO represents that it
settles its operating reserve transactions
on fifteen-minute intervals and
dispatches energy on five-minute
intervals.34 MISO states that it currently
calculates settlements for real-time
operating reserves transactions at the
same interval that they are dispatched,
i.e., five minutes, but that actual
settlements are on an hourly basis due
to the specific calculations MISO makes.
24. The PJM Market Monitor explains
that the synchronized and regulation
reserves markets in PJM clear hourly but
already incorporate five-minute LMP
data for calculating opportunity costs.
The PJM Market Monitor states that the
offer price in PJM’s synchronized
reserve market includes both the direct
short-run marginal cost of providing
31 NOPR,
FERC Stats. & Regs. ¶ 32,710 at P 40.
CAISO, eTariff, 34.5 (17.0.0); ISO–NE.,
Transmission, Markets and Services Tariff, Market
Rule 1, III.2.3 (15.0.0); MISO, FERC Electric Tariff,
40.2 (34.0.0); NYISO Markets and Services Tariff,
4.4.2.1 (17.0.0); PJM OATT, Attachment K,
Appendix, 2.3 (2.0.0); SPP, OATT, Sixth Revised
Volume No. 1, Attachment AE, 6.2.2 (1.0.0).
33 See CAISO, eTariff, 11.5 (2.0.0), Appendix A,
Settlement Interval (2.0.0); ISO–NE., Transmission,
Markets and Services Tariff, Market Rule 1,
III.2.2(b) (15.0.0); MISO, FERC Electric Tariff, 40.3
(32.0.0), 40.3.1 (32.0.0), 40.3.3 (36.0.0); NYISO,
NYISO Tariffs, NYISO Markets and Services Tariff,
4.4.2.1, 4.4.2.8 (17.0.0); PJM, Intra-PJM Tariffs,
OATT, Attachment K, Appendix, 2.5(e), (4.0.0),
3.2.1(e), (f) (28.0.0); SPP, OATT, Sixth Revised
Volume No. 1, Attachment AE, 8.6, 8.6.1 (2.1.0).
The above tariff citations refer to internal
transactions. CAISO settles its intertie interchange
transactions on fifteen-minute intervals. See CAISO,
eTariff, HASP Block Intertie Schedule (0.0.0).
34 CAISO Comments at 8.
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synchronized reserves, which does not
vary every five minutes, and the
opportunity cost of providing
synchronized reserves, which does vary
with five-minute LMPs. The PJM Market
Monitor explains that PJM currently
updates the opportunity cost every five
minutes using five-minute LMP data for
the Tier 2 synchronized reserve market
and recalculates the market clearing
price every five minutes, with
settlement based on the average of the
five-minute clearing price.35
25. The PJM Market Monitor explains
that, in PJM’s regulation market, the
offer price includes both the direct
short-run marginal cost of providing
regulation, which does not vary every
five minutes, and the opportunity cost
of providing regulation, which varies
with five-minute LMPs. The PJM Market
Monitor adds that PJM currently
updates the opportunity cost every five
minutes using five-minute LMP data for
the regulation market and recalculates
the clearing price every five minutes,
with settlement based on the average of
five-minute clearing prices. The PJM
Market Monitor also notes that PJM
purchases other forms of operating
reserves on a cost basis, including Tier
1 synchronized reserves, nonsynchronized reserves, and day-ahead
scheduling reserves.36
26. NYISO explains that it uses fiveminute intervals to settle its real-time
markets for energy, regulation service,
and operating reserves.37 ISO–NE
currently has hourly integrated
settlement for its real-time energy
transactions and its real-time operating
reserves. However, ISO–NE states it
intends to implement five-minute
settlement of real-time operating
reserves in connection with
implementing five-minute settlement of
real-time energy transactions, which is a
current discussion among ISO–NE
stakeholders.38 SPP prices and settles
operating reserve products in its realtime market on a dispatch interval, or
five minute, basis.39
c. Comments on the Proposed
Settlement Interval Reform
27. Twenty-seven of the thirty
commenters providing input on this
issue generally support the NOPR’s
proposed settlement interval reform.40
35 PJM
Market Monitor Comments at 8.
Market Monitor Comments at 8.
37 NYISO Comments at 2–3.
38 ISO–NE Comments at 2–3.
39 SPP Market Protocols, Sections 4.5.4 and 4.5.9.
40 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
36 PJM
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As described below, many assert that
the proposed reform will align the price
signals with system conditions and
provide accurate incentives for
generation units to follow dispatch
instructions.41 Others point to
additional benefits.
i. Comments From the RTOs/ISOs
28. The ISO/RTO Council supports
the Commission’s goals of aligning
prices with resource dispatch
instructions and operating needs and
specifically supports the settlement
interval proposal for energy
transactions. The ISO/RTO Council
states that the proposed settlement
interval reform will make resource
compensation more transparent by
increasing the proportion of payments
to resources through the price paid for
energy as opposed to uplift.42
29. In separate comments, NYISO,
ISO–NE., MISO, and PJM support the
settlement interval proposal for both
energy and operating reserve
transactions. Likewise, in separate
comments, CAISO supports the
settlement interval proposal for energy
transactions, but does not support
requiring RTOs/ISOs to settle all realtime operating reserves transactions at
the same interval as real-time energy
dispatch and settlement intervals.
30. CAISO states that the settlement
interval proposal would improve market
efficiency, and that accurate price
signals provide market participants with
incentives to develop needed
capabilities and to offer those
capabilities into the market.43 CAISO
states that where settlement and
dispatch intervals are aligned, resources
dispatched economically during highpriced periods should receive high
prices, thus reducing the need to pay
uplift caused by non-alignment of
settlement and dispatch intervals.44
31. However, CAISO does not support
requiring RTOs/ISOs to settle all realtime operating reserves transactions at
the same interval as real-time energy
dispatch and settlement intervals.
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; ODEC Comments at 3; 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.
41 Inertia Power and DC Energy Comments at 2;
Potomac Economics Comments at 1; Westar
Comments at 1; PSEG Comments at 3.
42 ISO/RTO Council Comments at 2.
43 CAISO Comments at 7.
44 CAISO Comments at 7.
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Instead, CAISO asserts that it is
appropriate to maintain its current
fifteen-minute procurement and
settlement interval for operating
reserves transactions, which differs from
the five-minute real-time energy
dispatch interval. CAISO explains that
its current settlement methodology
aligns ancillary services commitment
with internal generation commitment
and intertie transactions scheduling so
that the market accurately reflects the
overall amount of supply resources
available to provide energy and
ancillary services.45
32. NYISO supports the settlement
interval proposal and asserts that its use
of five-minute intervals to settle its realtime markets for energy, regulation
service, and operating reserves, has
provided significant incentives for
resources to follow dispatch
instructions and opportunities for
supply resources to obtain full payment
for their performance based on actual
system conditions.46
33. ISO–NE contends that settling on
sub-hourly or five-minute intervals
would help to improve price signals and
resource compensation.47 ISO–NE states
that five-minute settlements will help
improve price formation by ensuring
that compensation for real-time
performance sends more accurate
market signals of power system
conditions when energy is provided.48
ISO–NE supports the settlement interval
proposal for operating reserve
transactions. It asserts that settling all
real-time operating reserves transactions
at the same interval as real-time energy
dispatch and settlement intervals would
assist in aligning dispatch following
incentives in markets that
simultaneously co-optimize energy and
reserve dispatch in real-time. ISO–NE
states it intends to implement fiveminute settlement of real-time operating
reserves in connection with
implementing five-minute settlement of
real-time energy transactions, which is a
current discussion among ISO–NE
stakeholders.49
34. MISO asserts that the
inconsistency between dispatch and
settlements may produce financial
outcomes that do not align with the
guiding principles of co-optimized
(energy and ancillary services) security
constrained economic dispatch.50 If the
Commission requires five-minute
settlements of operating reserves, MISO
Comments at 17–18.
Comments at 2–3.
47 ISO–NE Comments at 2.
48 ISO–NE Comments at 2.
49 ISO–NE Comments at 2–3.
50 MISO Comments at 2.
states that it would modify its operating
reserves settlements from its current
hourly method of settling operating
reserves to align with real-time energy
transactions.51
35. PJM states that ancillary services,
including operating reserves, should
settle on the same interval as energy
because they are co-optimized. PJM
argues that not doing so could yield
discrepancies between the prices used
to settle each product and could
therefore undo enhancements made
since implementation of Order No. 719,
reduce market efficiencies, disrupt
operations, and hinder proper price
formation.52 PJM states that it intends to
change its market rules to settle energy
and ancillary services transactions in its
real-time energy market at the same
interval on which it dispatches
resources.53
ii. Comments by Market Monitors
36. The PJM Market Monitor agrees
that it would be appropriate to
implement five-minute pricing for the
reasons stated in the NOPR, and that
implementing five-minute settlements
will contribute significantly to reducing
uplift payments in PJM, an ongoing goal
in the PJM region.54 The PJM Market
Monitor states that, while it is
appropriate to include the impact of
five-minute LMP changes on the cost of
operating reserves in the form of
synchronized reserves and regulation,
the PJM design for these markets
currently incorporates those impacts.
The PJM Market Monitor asserts that no
additional changes to PJM market and
non-market mechanisms for acquiring
operating reserves are currently
necessary to incorporate changes in fiveminute LMPs.55
37. Potomac Economics, which serves
as the market monitor for ISO–NE.,
MISO, and NYISO, argues that hourly
settlements encourage resources not to
follow dispatch instructions or to
decrease their flexibility by restricting
dispatch ranges and offering slower
ramp rates, and states that MISO pays
uplift to alleviate these issues. Potomac
Economics cites its 2014 MISO State of
the Market Report to show how fiveminute settlements would change total
payments to resources compared to
current hourly settlements. This
analysis showed that fossil-fueled
resources in 2014 received settlements
that were $35 million less than they
would have received if the settlement
45 CAISO
46 NYISO
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51 MISO
Comments at 7–8.
Comments at 9.
53 PJM Comments at 2.
54 PJM Market Monitor Comments at 2, 4.
55 PJM Market Monitor Comments at 8–9.
52 PJM
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42887
were based on five-minute prices and
output, and that only one-fifth of this
lost value was paid via uplift. In
contrast, Potomac Economics represents
that non-fossil resources were paid on
net in hourly revenues slightly above
what they would have received with
five-minute settlements. Potomac
Economics asserts that five-minute
settlement provides greater
compensation to fossil resources, more
accurately representing the flexibility
fossil resources provide to the system.
In contrast, Potomac Economics argues
that hourly settlement overvalues wind
resources because such resources cannot
ramp up in response to higher prices,
are negatively correlated with load and
contribute to higher congestion at higher
output levels.56 Potomac Economics
states that the settlement interval
proposal will provide incentives for
better resource performance, will
improve price signals, and will improve
markets’ short-run commitment and
dispatch of existing resources.57
38. The SPP Market Monitor agrees
with the Commission’s preliminary
finding that aligning settlement and
dispatch intervals would make resource
compensation more transparent by
increasing the proportion of resource
payments made through energy and
operating reserve payments instead of
uplift.58 The SPP Market Monitor states
that aligning dispatch and settlement
intervals in neighboring markets would
enhance price signals at seams and
enhance market efficiency.59
iii. Comments Supporting the Proposed
Settlement Interval Reform
39. Many commenters expressly
support the NOPR’s settlement interval
proposal, citing many of the benefits
that were outlined in the NOPR.60 They
generally argue that the settlement
interval proposal will provide
incentives for generators to follow
dispatch more precisely, thus leading to
56 Potomac
Economics Comments at 6.
Economics Comments at 1.
58 SPP Market Monitor Comments at 2.
59 SPP Market Monitor Comments at 2–3.
60 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; AEMA Comments at 2; XO Energy Comments
at 1; PJM Market Monitor at 2; ODEC at 3.
57 Potomac
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better resource performance, and
improved reliability.61 They also assert
that the settlement interval proposal
will properly compensate resources for
the service they provide and will more
fully recognize the value of flexible or
fast-ramping resources.62 In addition,
they generally state that the settlement
interval proposal will lead to fewer outof-market payments, will increase
transparency, and will support more
efficient market outcomes.63
40. More specifically, Exelon asserts
that the settlement interval proposal
will support ongoing market
improvements, such as ISO–NE’s
performance incentive mechanism,
effective in June 2018, that will pay
resources bonuses or impose penalties
based on performance during operating
reserve shortages that last five minutes
or longer. Exelon argues that ISO–NE’s
market must settle at five-minute
intervals to implement this mechanism
completely.64
41. According to EDP Renewables,
greater participation of fast ramping
renewable resources will also enhance
resource adequacy, produce cost savings
for consumers, and improve grid
resilience.65
42. Some commenters also argue that
the settlement interval proposal will
reduce market inefficiencies and lead to
greater investment. PSEG asserts that
the proposed reforms correct market
flaws that have caused inefficiencies in
both price signals and resource dispatch
decisions.66 ELCON states that the
proposed settlement reform addresses
an embedded inconsistency in market
operation that promotes gaming and
other forms of ill behavior or
inefficiencies.67 EDP Renewables argues
that the proposed reforms will also yield
savings, remove opportunities for
market manipulation, and encourage
investment in new services and new
technologies, all of which will result in
a more robust and resilient grid and
help both consumers and suppliers
through more efficient market
operation.68
43. EPSA argues that implementing
sub-hourly settlement intervals is
61 Inertia Power and DC Energy Comments at 2;
Westar Comments at 1, 3; EEI Comments at 6–7;
Exelon Comments at 4–5.
62 Public Interest Organizations Comments at 2–
3; ELCON Comments at 2–3; EDP Renewables
Comments at 2–3; ESA Comments at 3; NEI
Comments at 14.
63 See supra note 60; ELCON Comments at 3;
Exelon Comments at 4–5.
64 Exelon Comments at 5.
65 EDP Renewables Comments at 3.
66 PSEG Comments at 3.
67 Public Interest Organizations Comments at
2–3; ELCON Comments at 2–3.
68 EDP Renewables Comments at 2.
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needed to obtain the full benefits of
other price formation reforms to
improve the accuracy with which realtime prices communicate the timedependent and location-dependent
value of incremental energy and
ancillary services.69
44. TAPS does not oppose the
settlement interval proposal, as long as
it does not impose an undue burden on
load serving entities.70
45. EPSA supports the settlement
interval proposal for operating reserves.
It argues that real-time operating
reserves should be co-optimized in the
dispatch and settled with energy for
every hourly sub-interval (generally five
minutes) to ensure that resources are
compensated for following RTO/ISO
instructions and are indifferent to
providing either energy or operating
reserves during periods of high energy
or operating reserves prices.71 EPSA
emphasizes the importance of sending
sub-hourly price signals to ensure that
operating reserves are available in subhourly intervals due to their
contribution to maintaining reliability,
further stating that sub-hourly
settlements for operating reserves send
information to the market relating to the
potential profitability of incremental
investments to enhance the sub-hourly
availability of such reserves.72 EPSA
argues that to ensure accurate prices for
both energy and operating reserves,
RTOs/ISOs should be required to cooptimize these products in real-time
because suppliers should be indifferent
to providing incremental energy and
operating reserves in each sub-hourly
interval to allow the RTO/ISO to
perform a reliable least-cost dispatch.73
46. Dominion supports the settlement
interval proposal for operating reserves.
However, Dominion argues that only
specific reserve products should settle
at the same interval that they are priced
and that other types of settlement
provisions, such as make-whole
payments, should not.74 Dominion
explains that, in PJM, for example,
‘‘balancing Operating Reserves’’
includes the costs to dispatch resources
out-of-merit for reliability or to cover
deficiencies in the day-ahead market
solution.75 According to Dominion,
these resources do not provide a specific
reserve product; rather, these resources
are made whole when they are
dispatched to address a mismatch
Comments at 6–7, Pope Aff. at 4–5.
Comments at 4.
71 EPSA Comments, Pope Aff. at 11.
72 EPSA Comments, Pope Aff. at 11.
73 EPSA Comments, Pope Aff. at 12–13.
74 Dominion Comments at 3.
75 Dominion Comments at 3.
between day-ahead commitment and
real-time requirements. Dominion
therefore requests that the Commission
not require the settlement intervals for
these types of operating reserve to
change.76
47. PSEG supports applying the
proposed settlement intervals to both
real-time energy transactions and realtime operating reserves. PSEG explains
that given the linkage between energy
transactions and reserve services,
settling those products on different
intervals would introduce dislocations,
and incent resource actions that could
disrupt these co-optimization objectives,
essentially undermining the
Commission’s objectives in the NOPR.77
48. The New Jersey Board concurs
with the PJM Market Monitor that no
changes should be made in PJM’s
synchronized reserve and regulation
markets given that the opportunity cost
component in these ancillary services
markets, which is the only cost
component subject to five-minute
changes in LMP, already accounts for
the five-minute interval changes.78 Duke
acknowledges potential benefits from
aligning operating reserve transactions
with their respective settlement
intervals but argues that stakeholders
should consider whether operating
reserves transactions should be aligned
with settlement intervals for energy
given the costs of doing so.79 Although
it takes no position on the operating
reserves proposal, EEI states that
additional clarity from the Commission
on the definition of operating reserve
transactions would be helpful, given the
varied definitions of reserve products
among regions. EEI states that such
regional variation warrants further
consideration.80
iv. Comments Opposed to the Proposed
Settlement Interval Reform
49. Several commenters oppose the
settlement interval proposal. Direct
Energy states that the Commission
should solicit information from RTOs/
ISOs to determine whether existing
generation resources are able to respond
effectively to five-minute price signals
before determining whether any
settlement interval reform is
warranted.81 Direct Energy doubts the
ability of longer lead-time resources to
respond to five-minute price signals
69 EPSA
70 TAPS
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76 Dominion
Comments at 3.
Comments at 4–5.
78 New Jersey Board Comments at 4.
79 Duke Comments at 5.
80 EEI Comments at 9–10 & n.16.
81 Direct Energy Comments at 6.
77 PSEG
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during periods of extreme price
volatility, and surmises that look-ahead
unit commitment and dispatch software
results could exacerbate swings in
generation and load balance. Direct
Energy states that a high-priced dispatch
interval could encourage dispatch of
peaking generation, which would take
several minutes with longer ramp times
and cause other resources to ramp up
more quickly. Direct Energy argues that
this could lead to an oversupply and to
depressed prices, thus making the
longer-ramping resources responding to
the original signal uneconomic by
running below their costs and incurring
uplift—the opposite of the goal of the
settlement interval proposal.82
50. Duke, APPA and NRECA, and
Concerned Cooperatives argue that the
Commission should refrain from
requiring a one-size-fits-all approach.83
Duke, APPA and NRECA, and
Concerned Cooperatives contend that
RTO/ISO stakeholder processes should
vet this issue and consider issues such
as the costs, benefits, types of changes
needed to implement this reform, price
formation issues more generally, and
unintended consequences.84 Duke states
that this approach would notify the
Commission with regard to possible
solutions, cost of implementation, and
the timeframe in which the RTO/ISO
could reasonably address each issue.85
Additionally, Concerned Cooperatives
disagree with the Commission’s
conclusion that reforming the settlement
intervals will result in more efficient
use of generating resources.
51. Concerned Cooperatives argue that
the benefits of moving to five-minute
settlements will not offset the cost. They
state that the Potomac Economics report
cited in the NOPR shows that switching
to matching intervals would force MISO
market participants to expend millions
of dollars on upgrades and operation
and maintenance (O&M) costs, without
realizing lower rates. Instead, those
participants would face an annual
increase of approximately $28 million,
after netting the estimated $6.6 million
system benefit from the increased
payments to generators of about $35
million dollars.86
52. Concerned Cooperatives further
argue that the Commission relies solely
82 Direct
Energy Comments at 3–5.
Comments at 2–3; APPA and NRECA
Comments at 4–5; Concerned Cooperatives
Comments at 4–5.
84 Duke Comments at 4; APPA and NRECA
Comments at 3; Concerned Cooperatives Comments
at 1.
85 Duke Comments at 4–5.
86 Concerned Cooperatives Comments at 10
(citing Potomac Economics, 2014 State of the
Market Report for the MISO Electricity Markets, at
43–44, Figure 19 (2015)).
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83 Duke
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upon a letter filed in Docket No. AD14–
14–000 87 to support its finding with no
analysis as to whether the observed
increase in capacity factors for internal
combustion engines in SPP was the
result of SPP’s adoption of five-minute
settlement intervals or other factors.88
Concerned Cooperatives argue that,
even if there was some marginal benefit
to the settlement interval proposal,
many market participants would not
benefit from the reform even though
they would be responsible for funding
it.89 Concerned Cooperatives represent
that 90 to 95 percent of their
transactions take place in the day-ahead
market, which settles on an hourly
basis, and that adopting five-minute
settlement intervals in the real-time
market does not help Concerned
Cooperatives hedge prices.90 Concerned
Cooperatives also state that the National
Renewable Energy Laboratory study
cited in the NOPR in support of
adopting five-minute settlement
intervals also recognizes that limiting
market complexity may be a reason to
maintain hourly settlements, and that
RTOs/ISOs already have tools to
encourage resources to follow efficient
schedules, such as uninstructed
deviation penalties and ex post pricing
rules. Concerned Cooperatives
recommend that the Commission
instead identify objectives and allow
RTOs/ISOs to pursue options for
achieving those objectives.91
d. Commission Determination
i. Energy Transactions
53. We adopt the NOPR proposal to
require that each RTO/ISO settle energy
transactions in its real-time markets at
the same time interval it dispatches
energy, as discussed below.92 We find
that the settlement interval requirement
for energy transactions will meet the
Commission’s price formation goals by
more accurately reflecting the value of
the service a resource provides to the
system, which, in so doing, helps to
ensure that rates are just and reasonable
and not unduly discriminatory or
preferential.
54. As discussed below, providing the
correct incentives for market
participants to follow commitment and
dispatch instructions, make efficient
investments in facilities and equipment,
maintain reliability, and increase
transparency is fundamental to proper
formation of energy prices, helping to
ensure just and reasonable rates, terms
and conditions of service.
55. One important element of
ensuring reliable grid operations is
resources following dispatch
instructions. The requirement that each
RTO/ISO settle energy transactions at
the same interval it dispatches energy
sends accurate market signals of power
system conditions, thus encouraging
resources to follow commitment and
dispatch instructions, a point noted by
ISO–NE.93
56. The settlement interval
requirement for energy transactions also
provides an incentive to make efficient
investments in facilities and
equipment.94 In the long-term, we
expect that appropriate compensation
would help to encourage efficient
investments in facilities and equipment,
enabling reliable service. We also find
that the settlement interval requirement
will provide incentives to more flexible
resources, thus leading to more efficient
markets, as noted by several
commenters.95 More flexible resources
will help system operators address
transient system conditions. We find
that greater participation of these more
flexible resources should generally
enhance resource adequacy because it
allows the participation of diverse
resources and improves reliability, as
noted by EDP Renewables.96
57. The settlement interval
requirement for energy transactions
should help in maintaining reliability
because resources will have a greater
incentive to follow dispatch
instructions, as noted by Exelon.97 In
addition, these reforms will provide
resource owners with a greater incentive
to adequately maintain their equipment,
conduct maintenance during non-peak
periods, and invest in new and
upgraded equipment. As noted by
CAISO, linking prices with
compensation will pay resources for
providing needed flexibility to the
market operator and would motivate
these resources to improve their
operational performance.98
58. The settlement interval
requirement for energy transactions also
results in more accurate market prices,
reducing the need for out-of-market
operator actions. Under an hourly
93 ISO–NE
87 Concerned
Cooperatives Comments at 11
¨
¨
(citing Comments of Wartsila North America, Inc.,
Docket No. AD14–14–000, at 1–2 (Mar. 6, 2015)).
88 Concerned Cooperatives Comments at 11.
89 Concerned Cooperatives Comments at 11.
90 Concerned Cooperatives Comments at 11.
91 Concerned Cooperatives Comments at 12.
92 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.
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Comments at 2.
Comments, Pope Aff. at 4.
95 Public Interest Organizations Comments at 2–
3; ELCON Comments at 2–3; EDP Renewables
Comments at 2–3; ESA Comments at 3; NEI
Comments at 14.
96 EDP Renewables Comments at 2–3.
97 Exelon Comments at 4–5.
98 CAISO Comments at 7.
94 EPSA
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settlement system, resources do not
have the same incentive to follow fiveminute prices since compensation is
based on an hourly average. Therefore,
system operators are more likely to take
out-of-market actions in real-time, such
as increasing the use of regulating
reserves or committing additional
resources, to ensure that adequate
resources are available to meet system
needs. Such actions may result in uplift.
By providing incentives to follow
dispatch instructions, the settlement
interval requirement should reduce
such operator actions and, thereby,
reduce uplift.99 When this occurs,
energy prices are based on more
observable market fundamentals—such
as the marginal cost of serving load and
the operational constraints of reliably
operating the system—and not on less
observable operator action.100 As a
result of a reduction in out-of-market
uplift payments, resources will perceive
stronger financial incentives to perform,
especially during stressed system
conditions, when the performance of all
resources is paramount. Further, we
note, this increased transparency, in
turn, better informs decisions to build or
maintain resources.
59. Taken together, the benefits we
expect as a result of this settlement
reform will ensure that rates are just and
reasonable and not unduly
discriminatory or preferential.
60. We are not persuaded by the
arguments opposing the settlement
interval proposal. Underlying much of
the opposition is the assumption that
many resources cannot take advantage
of five-minute settlement intervals
because they are not flexible enough to
respond to five-minute dispatch. For
example, Direct Energy argues that
RTOs/ISOs should report the types of
resources able to effectively modify
their output to respond to five-minute
99 Reducing out-of-market uplift payments can be
beneficial to RTOs’/ISOs’ market participants
because, among other reasons, charges to market
participants for uplift are often volatile. As a result,
market participants may build risk premiums into
their resource bids in the real-time energy market
to shield them from the uncertainty associated with
unexpected uplift charges. See Staff Analysis of
Uplift in RTO and ISO Markets, Docket No. AD14–
14–000, at 18 (Aug. 2014), http://www.ferc.gov/
legal/staff-reports/2014/08-13-14-uplift.pdf. In
addition, making system conditions and
compensation more transparent through market
prices will make that price apparent to all available
resources and thus encourage them to fully
participate in the market, which is likely to reduce
generation costs incurred by load.
100 In addition to greater transparency, reducing
uplift is a goal generally. For example, ‘‘[t]he
implementation of five minute settlements would
contribute significantly to the reduction of uplift
payments, which is an ongoing goal of PJM, of the
Market Monitor and of PJM members.’’ PJM Market
Monitor Comments at 4.
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price signals.101 The concern Direct
Energy identifies is, in fact, one of the
objectives of this reform. Specifically,
resources that are not able to respond
quickly enough to address acute system
needs should not receive the same level
of compensation as those resources that
are able to flexibly respond.102 Further,
we note that all RTOs/ISOs have a
combination of resources, some of
which can respond within five minutes
and some that cannot, and that knowing
the exact percentages of resources
available to respond to prices is not
determinative of whether the reforms
adopted here will prove beneficial.
Instead, we believe it is important to
ensure settlement practices do not
distort existing five-minute pricing
signals.
61. We are not persuaded by
Concerned Cooperatives’ argument that
the settlement interval proposal should
be rejected because market participants,
such as Concerned Cooperatives,
funding the reform do not have a large
fraction of their positions in the realtime market and therefore will not
benefit significantly from it.103 We find
that aligning prices and settlement
intervals will enhance the operation of
markets by ensuring resources respond
to actual system condition regardless of
the percentage of resources that clear in
the day-ahead market.
62. We also disagree with Concerned
Cooperatives’ statement that the
Commission relied upon a single
document to support its finding without
additional analysis.104 Commenters
supporting the reform have provided
sound economic analysis and examples
demonstrating the value of the proposed
settlement reform.105 Though
Concerned Cooperatives state that many
market participants would not benefit
from the reform even though they would
be responsible for funding it,106 we
believe that many market participants
are likely to benefit from the reform
through improved economic incentives
to respond to system needs. Potomac
Economics’ analysis of fossil-fueled and
non-fossil-fueled resources 107
demonstrates that settlement reform will
incentivize generator flexibility,
improve generators’ dispatch
101 Direct
Energy Comments at 6.
rule does not require resources to be
dispatched more quickly than they are now, but it
does increase the incentive for those resources that
can and do respond quickly.
103 Concerned Cooperatives Comments at 11.
104 Concerned Cooperatives Comments at 11.
105 EPSA Comments, Pope Aff. at 2–14; Potomac
Economics Comments at 3–7; See also supra note
60.
106 Concerned Cooperatives Comments at 11.
107 Potomac Economics Comments at 5–6.
102 This
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performance, and increase investments
in more flexible resources.
63. Concerned Cooperatives express
concern that adopting five-minute
settlement intervals could result in
errors and disputes that could lead to
resettlement and uncertainty for the
market.108 All RTOs/ISOs currently
compute five-minute LMPs. Therefore,
there is no new data being generated or
calculated that would lead to additional
need for resettlement or increased
uncertainty. Concerned Cooperatives
have cited neither examples of more
errors and disputes on RTO/ISO systems
currently using five-minute settlement
intervals, nor examples of additional
resettlement and uncertainty for the
market. Also, we find that, while
administratively-determined
uninstructed deviation penalties (which
Concerned Cooperatives suggest could
be used in lieu of settlement reform) are
appropriate in certain contexts,
settlements based on the actual value of
energy corresponding with its
production or transaction in each fiveminute interval provide more accurate
incentives for resources to respond to
price signals.
64. Concerned Cooperatives also
assert that the objective of incenting
market participants to follow dispatch
instructions or invest in upgrades must
be considered in the context of existing
market rules that already may provide
incentives for investment in faster
ramping capability.109 To the extent an
RTO/ISO has a functional mechanism to
encourage the installation of fastramping resources, this Final Rule will
augment the existing RTO/ISO
mechanisms.
65. Contrary to Concerned
Cooperatives’ argument, we are not
persuaded to abandon the settlement
interval proposal because a Potomac
Economics report indicates that it
would have resulted in an additional
$28 million in increased energy costs on
the MISO system in 2014.110 First, we
recognize that that there could be higher
revenues to generators, but we believe
that this is the correct reflection of value
provided in these circumstances and
would send an improved signal for longterm investment and short-term
performance, to the overall benefit of
the market. Second, it is important to
note that the Potomac Economics report
indicates that for many settlement
intervals during 2014, MISO resources
were paid an hourly settlement rate
lower than what five-minute settlements
would justify. Thus, the Potomac
108 Concerned
Cooperatives Comments at 12.
Cooperatives Comments at 6.
110 Concerned Cooperatives Comments at 10.
109 Concerned
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Economics report should be viewed as
indicating a need to correct settlement
practices, rather than indicating a
windfall to resources. Third, it is not
clear that the proposal will result in
generally increased energy payments to
generators. For example, an ISO–NE
study for the year 2013 found that the
net increase in real-time energy credits
on its system (once the decrease in realtime reserve credits was considered)
would have been only $600,000.111
Finally, due to the increased efficiencies
resulting from improving incentives to
respond to market price signals, total
costs to electric wholesale customers
over time are likely to decrease.
66. Additionally, some commenters
argue that other types of settlement
provisions, such as make-whole
payments, should not be subject to
settlement interval reform. We would
like to clarify that the Final Rule does
not apply to make-whole payments for
units dispatched out-of-merit.
67. We disagree with the
recommendation of some commenters
that the decision to modify settlement
intervals should be subject to a
stakeholder process.112 RTOs/ISOs
implementing this Final Rule are free to
use a stakeholder process within the
implementation timelines specified
herein, but we see no need to further
delay this reform. This does not limit
stakeholders’ input as RTOs/ISOs form
their compliance filings in response to
this aspect of the Final Rule.
68. We conclude that the settlement
interval requirement for energy
transactions should ensure that hourly
settlement practices do not distort fiveminute price signals in RTOs/ISOs.
Instead, the compensation provided to
resources must reflect the value of a
resource providing given services to
ensure appropriate economic incentives
to meet system needs.
ii. Operating Reserves
69. We adopt the proposal in the
NOPR that RTOs/ISOs settle real-time
operating reserves transactions at the
same time interval that they price
operating reserves. This requirement for
operating reserves will accomplish the
Commission’s price formation goals and
thereby ensure just and reasonable rates,
and will further preserve the cooptimization of operating reserves with
energy. Under the settlement interval
requirement for operating reserves, to
the extent that an RTO/ISO prices
111 ISO–NE., Subhourly Real-Time Market
Settlements, A11 ISO Presentation 05–07–14
Revision 1, Matt Brewster, at 11 (May 8, 2014),
http://www.iso-ne.com/committees/key-projects/
subhourly-real-time-settlement.
112 APPA and NRECA Comments at 4.
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operating reserves transactions at a
different time interval than it prices
internal real-time energy transactions,
that RTO/ISO need only settle operating
reserves transactions at the same time
interval that they are priced. Thus, we
will not require an RTO/ISO to settle
operating reserves transactions on the
same time interval as it settles energy
transactions. This will preserve the
existing energy and operating reserves
co-optimization methodologies of the
various RTOs/ISOs.
70. The settlement interval
requirement increases transparency and
provides the correct incentives to
maintain reliability. It also meets the
Commission’s other price formation
goals of encouraging resources to follow
the RTO’s/ISO’s commitment and
dispatch instructions and to make
efficient investments. The reform to the
settlement interval for operating
reserves will increase reliability because
resource owners will have a greater
incentive to adequately maintain their
equipment, conduct maintenance
during non-peak periods, and invest in
new and upgraded equipment. Similar
to energy settlement intervals, requiring
settlement intervals of operating
reserves transactions to match the
intervals upon which those reserves are
priced will reduce the need for
payments made through uplift, make
resource compensation more
transparent and help ensure that there
are adequate operating reserves to
maintain reliability. Finally, cooptimized energy and reserve prices are
designed so that a resource is indifferent
between providing energy or operating
reserves. Ensuring that energy and
operating reserve settlements are done
on the same basis will preserve this
indifference and create an incentive for
a resource to provide the service the
RTO/ISO has instructed it to provide.
The reform to operating reserve
settlements will, by achieving the
Commission’s price formation goals and
preserving the co-optimization of energy
and operating reserves, ensure that rates
are just and reasonable.
71. While, as discussed above, some
commenters also support RTOs/ISOs
settling all real-time operating reserves
transactions at the same time interval
that they dispatch real-time energy,113
we are not requiring that these
settlement intervals align. CAISO, in
defending its current practices, states
that it procures operating reserves and
settles them on a fifteen-minute basis
and distinguishes this type of ancillary
service from five-minute real-time
113 PSEG Comments at 4–5; EPSA Comments,
Pope Aff. at 11–13.
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energy dispatch.114 However, CAISO,
along with all of the other RTOs/ISOs,
supports the requirement that they settle
operating reserves transactions at the
same time interval that they price these
transactions, which accommodates both
RTOs/ISOs that currently settle cooptimized reserve transactions on a fiveminute basis and those that currently
settle these transactions on a fifteenminute basis. Accordingly, we clarify
that CAISO’s understanding in this
regard is consistent with how operating
reserves and energy on its system are
‘‘priced,’’ as contemplated by the
wording of the settlement interval
regulations adopted by this Final Rule.
72. NYISO states that, although it uses
sub-hourly settlements in its real-time
market, in certain cases, the
Commission has approved NYISO
performing settlements on an hourly
basis, and NYISO argues it should not
be required to bring those settlements
into alignment with its normal dispatch
intervals.115 NYISO cites limited energy
storage resources as an example of
services that currently settle hourly and
yet follow dispatch instructions and
provide resource response in real-time.
To the extent NYISO or other RTOs/
ISOs seek to argue on compliance that
their existing market rules are consistent
with or superior to the Final Rule
reforms adopted herein, the
Commission will entertain those at that
time.116
73. Although generally supporting the
settlement interval requirement for
operating reserves, some commenters
question whether such a requirement
should apply to all reserve products or
assert that regional variations should be
considered.117 We appreciate that
regional variations may exist among the
many different reserve products in the
RTOs/ISOs and we clarify that all
operating reserve products that have a
market-based price are subject to the
settlement interval reform.
3. Interties
a. Commission Request for Comments
74. The Commission sought comment
on whether the proposed reforms are
appropriate for intertie transactions
scheduled on intervals different from
114 CAISO
Comments at 17–18.
Comments at 3–4.
116 See, e.g., Demand Response Compensation in
Organized Wholesale Energy Markets, Order No.
745, FERC Stats. & Regs. ¶ 31,322, at P 4 & n.7,
order on reh’g and clarification, Order No. 745–A,
137 FERC ¶ 61,215 (2011), reh’g denied, Order No.
745–B, 138 FERC ¶ 61,148 (2012), vacated sub nom.
Elec. Power Supply Ass’n v. FERC, 753 F.3d 216
(D.C. Cir. 2014), rev’d & remanded sub nom. FERC
v. Elec. Power Supply Ass’n, 136 S. Ct. 760 (2016).
117 See, e.g., Dominion Comments at 3; EEI
Comments at 10.
115 NYISO
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the intervals on which RTOs/ISOs
dispatch internal real-time energy.118
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i. Comments by RTOs/ISOs
75. The ISO/RTO Council asserts that
aligning dispatch and pricing should
also apply to intertie transactions,
adding that this would prevent price
discrepancies and may reduce uplift.119
76. PJM asserts that intertie
transactions should be included in the
scope of the Final Rule, noting that it
plans to settle intertie transactions on a
five-minute basis, consistent with its
proposal for its real-time energy market.
PJM suggests that, where a transaction is
curtailed or the MW quantity is reduced
during a fifteen-minute interval due to
a reliability directive, each five-minute
interval in the transaction should settle
on the integrated transaction MW
quantity that flowed during the fiveminute interval.120
77. ISO–NE argues that external
interties should settle no less often than
the intervals for which they are
scheduled. ISO–NE represents that its
proposals to implement sub-hourly
settlements would fully meet this
objective at all its external interfaces.121
NYISO argues that intertie and internal
transactions should have the same
settlement interval because this
alignment will promote competition,
identify the most economic supply
option, provide equal incentives to
respond to the same operating
conditions, and improve the efficiency
of interregional transactions.122
78. CAISO notes that it already
schedules and settles intertie
transactions and internal resources on a
fifteen-minute basis.123 However,
CAISO also provides three options for
scheduling imports and exports on an
hourly basis: (1) Economic-bid hourly
block; (2) economic-bid hourly block
with a single intra-hour schedule
change that will be dispatched to zero
within the hour if a fifteen-minute price
is less than an import’s bid price or
greater than an export’s bid price; and
(3) self-scheduled hourly.124 CAISO
requests that the Commission state that
CAISO’s current market design with
granular dispatch and settlement of its
real-time energy market is consistent
with the settlement interval proposal.125
79. CAISO asserts that a blanket
requirement that hourly intertie
schedules revert to hourly pricing, as
118 NOPR,
FERC Stats. & Regs. ¶ 32,710 at P 39.
Council Comments at 2.
120 PJM Comments at 8.
121 ISO–NE Comments at 2.
122 NYISO Comments at 5.
123 CAISO Comments at 12.
124 CAISO Comments at 9.
125 CAISO Comments at 10.
119 ISO/RTO
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was previously the case under its prior
market design, would result in the same
adverse market outcomes it resolved
through its fifteen-minute market
enhancement.126 CAISO requests that
the Commission clarify that the
availability of hourly block intertie
bidding options would not violate the
settlement interval proposal because its
current market design ensures all
internal and external transactions are
cleared and settled based on fifteenminute market intervals that optimize
all transactions in its markets.127
ii. Comments by Market Monitors
80. The PJM Market Monitor asserts
that intertie transactions in PJM cannot
be measured accurately enough to
support five-minute settlements, noting
that accurate measurement is difficult
because of differences between actual
and scheduled flows. The PJM Market
Monitor thus recommends that
settlements be based on the same
fifteen-minute interval used for external
scheduling intervals. The PJM Market
Monitor asserts that this approach
would more accurately reflect LMP
during the actual time period of the
transaction and would make the period
and settlement of the transaction
consistent.128
81. The PJM Market Monitor states
that alternative settlement approaches
include using the integrated price over
the same fifteen-minute interval used in
scheduling and using five-minute
interval settlements.129
iii. Comments in Support of Applying
Settlement Reform to Interties
82. The New Jersey Board, EEI, EPSA,
Dominion, and EDP Renewables concur
with the PJM Market Monitor that
intertie settlements should be at fifteenminute intervals, the same interval as
external scheduling.130
83. Golden Spread states that
alignment between dispatch and
settlement intervals is generally
desirable for the reasons listed in the
NOPR, and notes that it believes SPP
already aligns dispatch and settlement
intervals for intertie transactions on a
five-minute basis.131
84. ANGA, PSEG, and the Financial
Marketers Coalition assert that the logic
126 CAISO
Comments at 14.
Comments at 15.
128 PJM Market Monitor Comments at 7.
129 The PJM Market Monitor in its comments
provides examples of these alternatives. PJM Market
Monitor Comments at 5–7.
130 New Jersey Board Comments at 3–4; EEI
Comments at 9; EPSA Comments, Pope Aff. at 9;
Dominion Comments at 4; EDP Renewables
Comments at 5.
131 Golden Spread Initial Comments at 2.
127 CAISO
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underlying the proposed settlement
reform as applied to internal
transactions should apply equally to
intertie transactions, and ANGA
recommends that the Commission
consider evolving these interfaces to
five-minute dispatch and settlement,
perhaps over the next three to five
years.132
85. Although it generally agrees that
the settlement interval proposal should
apply equally to internal and intertie
transactions, Financial Marketers
Coalition states that, in CAISO, clearing
some transactions (such as load and
generation) on a five-minute price and
others (such as internal and intertie
convergence bids) on a fifteen-minute
price has yielded price divergence
instead of convergence.
iv. Comments Opposed To Applying
Settlement Reform to Interties
86. Inertia Power and DC Energy
argue that intertie economic dispatch
intervals cannot easily be aligned with
internal real-time energy dispatch but
emphasize the importance of
maintaining the highest possible
consistency across the seams to ensure
a more efficient, resilient, and reliable
electrical system.133
87. Duke states that the issue of
whether to apply the settlement interval
proposal to intertie transactions should
be discussed in the RTO/ISO
stakeholder processes and that they
should be treated comparably to reforms
to internal transactions.134
b. Commission Determination
88. Based upon the comments
received on this issue, we modify the
regulatory text proposed in the NOPR to
require each RTO/ISO to settle intertie
transactions in the same time interval
that it schedules intertie transactions.
The settlement interval requirement for
intertie transactions will facilitate the
coordination of the scheduling and
settlement of intertie transactions, and
will discourage inefficient practices
such as the chasing of inaccurate
intertie prices. For example, if there are
very high prices in the first fifteen
minutes of an hour, resources will know
that for that entire operating hour, there
will be a high integrated hourly price.
This provides an incentive for resources
to increase the volume of intertie
transactions for the remainder of the
hour, even if the price for the
subsequent fifteen-minute interval is
much lower reflecting that it may no
132 ANGA Comments at 3–4; Financial Marketers
Coalition Comments at 3–4; PSEG Comments at 5.
133 Inertia Power and DC Energy Comments at
4–5.
134 Duke Comments at 5.
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longer be efficient to schedule such
intertie transactions. Most commenters,
as described above, agree that such a
requirement will aid in the achievement
of these goals.
89. However, a difference of opinion
exists between PJM and the PJM Market
Monitor. PJM supports moving to a fiveminute settlement interval for intertie
transactions while the PJM Market
Monitor supports aligning the
settlement interval for intertie
transactions with the fifteen-minute
scheduling interval for these
transactions.
90. If an RTO/ISO settles or proposes
to settle intertie transactions using a
shorter time interval than by which it
schedules such transactions, the RTO/
ISO may propose to do so in its
compliance filing and demonstrate that
such a proposal is consistent with or
superior to the Commission’s intertie
reforms. The compliance filing
proceeding will provide a forum in
which to consider alternative practices
and resolve disputes that may arise
within regions, as well as provide for
the development of a more complete
record on these issues.
91. We decline to clarify for CAISO
that the availability of hourly block
intertie bidding options would not
violate the settlement interval
requirement for interties. Such a
determination is more appropriately
made upon reviewing CAISO’s
compliance filing and CAISO should
justify its proposed treatment for intertie
transactions there.
4. Demand Response Resources
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a. Comments
92. Several commenters discuss the
application of the settlement interval
proposal to demand response resources
even though the Commission did not
specifically solicit those comments and
did not make a separate proposal
concerning demand response resources
apart from other resources considered in
the NOPR.
93. The PJM Market Monitor, with the
New Jersey Board concurring,
recommends that five-minute pricing in
energy markets explicitly cover all
resources providing energy, including
demand side and storage resources.135
PJM Market Monitor recommends that
the Commission require any associated,
necessary metering associated with
applying the requirement to demand
resources.136
135 PJM
Market Monitor Comments at 2; New
Jersey Board Comments at 2.
136 PJM Market Monitor Comments at 2; New
Jersey Board Comments at 2.
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94. Public Interest Organizations also
urge the Commission to make clear that
its proposed reforms apply to all
resources able to participate in
wholesale energy markets.137 PSEG
similarly supports the application of the
settlement interval proposal to demand
response resources. PSEG states that
real-time settlements for demand
response resources, or any other loadside resources that are price responsive
in wholesale markets, should be based
on five-minute intervals, in the same
manner as the supply resources with
which it competes.138 PSEG
acknowledges that some demand
resources will lack necessary meters
and/or communication, and states that it
would be reasonable to allow these
resources a transition period to install
them without delaying overall
implementation.139
95. AEMA states that it recommends
that demand response resources have
the option to continue to settle on the
basis of one-hour meter readings. AEMA
asserts that demand resources use
hourly intervals because only hourly
interval metering may be available and
even new advanced metering
infrastructure is only capable of fifteen
minute interval data, whereas settling
on five-minute intervals could entail
adding an expense that is an economic
barrier to entry for some resources.140
96. AEMA also states that few
demand response resources have the
operational communications to modify
their demand at frequent intervals and
that frequent demand changes would
require more robust communications
than may be economic.141 AEMA
further states that the Net Benefits Price
Threshold that many RTOs/ISOs
established in response to FERC Order
No. 745 is applied on an hourly basis
and that the industry has universally
adopted hourly baseline methodologies
for demand response resources.142
97. AEMA explains that much of the
current energy-related demand response
participation relies on the commitment
to dispatch for one or more hours and
if the bid-offer is accepted for demand
response resources, those resources are
eligible for uplift payments if the energy
prices fall below their bid-offer during
their committed dispatch time. AEMA
requests that these bid offer guarantees
continue to be incorporated in the Final
Rule.143
137 Public
Interest Organizations at 5.
Comments at 5.
139 PSEG Comments at 5.
140 AEMA Comments at 4.
141 AEMA Comments at 4.
142 AEMA Comments at 3–5 (citing Order No.
745, FERC Stats. & Regs. ¶ 31,322).
143 AEMA Comments at 5.
138 PSEG
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42893
b. Commission Determination
98. In using the term ‘‘resource’’ in
the NOPR, the Commission intended for
the settlement interval proposal to apply
to all supply resources, including
demand response resources. We find
that, as with other resources, aligning
the price signal and dispatch signal
provides demand response resources
capable of following a given dispatch
signal the incentive to do so, resulting
in a more efficient use of demand
response resources in the real-time
energy and operating reserve markets.
As stated above, all RTOs/ISOs have a
combination of resources, some of
which can respond within five minutes
and some that cannot, and that includes
demand response resources. It is
important to provide a price signal to all
resources, regardless of type or
capability, as this will provide proper
compensation to those resources
capable of responding to five-minute
dispatch signals, and will incentivize
such capability to those resources that
do not currently have it.
99. In response to concerns about the
need to upgrade metering technology for
demand response resources, we note
that this Final Rule does not
contemplate requiring any new metering
capability, such as five-minute revenue
quality metering, and that such metering
is not necessary for implementation
given RTOs’/ISOs’ ability to create fiveminute load and generation profiles
using telemetry and hourly revenue
quality data. We also do not require any
changes to baseline methodologies.
Although a more granular baseline may
provide additional value, RTOs/ISOs
need not change their baseline
methodology to comply with this Final
Rule. Finally, we find that AEMA’s
arguments regarding the Net Benefits
Price Threshold 144 and ‘‘make whole’’
rules are beyond the scope of this Final
Rule because it does not require any
changes to the Net Benefits Price
Threshold or make-whole payments.
Even if modest changes to these
provisions were required for RTOs/ISOs
to comply with this Final Rule, the
benefits of this rule would justify such
modifications.
5. Load
a. Comments
100. A number of commenters state
the proposed rule did not specify
whether the settlement interval proposal
would apply to load,145 or, in other
144 AEMA
Comments at 3.
purposes of this Final Rule, the term
‘‘load’’ generally refers to consumption of electricity
in the wholesale markets, but not to demand
145 For
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words, whether it would change how
load is settled and measured.
101. EEI, PSEG, SCE, AEMA, EPSA
and CAISO recommend that the
Commission not apply the settlement
reform to load.146 The primary
arguments these commenters cite
against applying the settlement interval
proposal to load include: (1) The benefit
of settling load on an interval basis is
not likely to outweigh the cost, which
may include the need for new expensive
metering; 147 (2) settlement reform alone
will not encourage price responsive load
without corresponding changes to statejurisdictional retail rate design; 148 and
(3) because load is not dispatchable,
there is no dispatch interval that aligns
with load.149 Direct Energy recommends
either not applying the settlement
reform to load or delaying
implementation until the majority of
load has the ability, incentive and
information necessary to respond to
five-minute settlements.150 EEI
specifically requests that the
Commission clarify that it is not
proposing to change how load is
metered.151
102. PJM, however, states that it is
advantageous to apply the proposed rule
to load, and proposes to settle load on
the same interval as dispatch intervals
by using a combination of stateestimator and telemetry data for each
settlement interval.152 PJM states that it
thus does not foresee changes being
required for market participants’
metering.153
103. Mr. Centolella states that
advancing load settlements to reflect the
actual interval demand of each load
serving entity’s customers could remove
an important barrier to developing the
next generation of responsive demand.
Mr. Centolella also encourages the
Commission to work with states to
optimize collecting customer data, and
to evaluate how to support efficient
price formation related to the load data
used in wholesale settlements.154
response acting as a supply resource in the
wholesale markets.
146 EEI Comments at 8–9; PSEG Comments at 5–
6; SCE Comments at 2; AEMA Comments at 4–5;
EPSA Comments, Pope Aff. at 6–7; CAISO
Comments at 16–17.
147 SCE Comments at 2.
148 SCE Comments at 2.
149 CAISO Comments at 16–17.
150 Direct Energy Comments at 7. See also
Supplemental Comments of Direct Energy (filed
Mar. 4, 2016).
151 EEI Comments at 8–9.
152 PJM Comments at 5.
153 PJM Comments at 5.
154 Mr. Centolella Comments at 4–6.
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b. Commission Determination
104. We clarify that the Commission
did not propose to apply the settlement
interval proposal to load. We also clarify
that adoption of the settlement interval
requirements are not intended to change
how load is metered. The Commission’s
basis for requiring changes to the
settlement interval focused exclusively
on supply resources rather than load. As
a result, we have no record to require
any changes to the settlement interval
for load. However, we are not
prohibiting settling load on a fiveminute basis, and will evaluate any
such proposals on a case-by-case basis
in separate proceedings submitted
pursuant to section 205 of the FPA.
B. Shortage Pricing Reform
1. Need for Reform
105. In the NOPR, the Commission
stated that shortage prices send a shortterm price signal to provide an incentive
for the performance of existing
resources and help to maintain
reliability. The Commission noted that
some RTOs/ISOs currently restrict the
use of shortage pricing to certain causes
of shortages, or some RTOs/ISOs require
a shortage to exist for a minimum
amount of time before triggering
shortage pricing.155 The Commission
further noted that not invoking shortage
pricing when there is a shortage
(regardless of the duration or cause of
that shortage) distorts price signals that
are designed to elicit increased supply
and to compensate resources for the
value of the services they provide when
the system needs energy or operating
reserves. Because these price signals fail
to reflect adequately the value that a
resource provides to the system, the
Commission preliminarily found in the
NOPR that the resulting price is not just
and reasonable.156
106. The Commission also noted that
its rationale regarding shortage pricing
was similar to the rationale the
Commission relied on in Order No. 719,
in which the Commission determined
that ‘‘rules that do not allow for prices
to rise sufficiently during an operating
reserve shortage to allow supply to meet
demand are unjust, unreasonable, and
may be unduly discriminatory’’ and that
such rules ‘‘may not produce prices that
accurately reflect the value of
energy.’’ 157
107. Commenters generally support
the rationale provided by the
Commission in support of the need for
155 NOPR,
FERC Stats. & Regs. ¶ 32,710 at P 46.
FERC Stats. & Regs. ¶ 32,710 at P 47.
157 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 48
(citing Order No. 719, FERC Stats. & Regs. ¶ 31,281
at P 192).
156 NOPR,
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reform. For example, as discussed
below, MISO, NYISO and ISO–NE all
support the need for reform, and CAISO
supports the conceptual need, but
requests further clarifications. EEI and
EPSA also support the Commission’s
shortage pricing proposal. Conversely,
SPP and PJM, in joint comments,
oppose implementing shortage pricing
in all dispatch intervals, and request
revisions if the Commission adopts its
proposed reforms.
108. Based on analysis of the record,
we adopt our preliminary findings and
conclude that existing shortage pricing
triggers that do not invoke shortage
pricing when there is a shortage
(regardless of duration or cause) are
unjust and unreasonable and are unduly
discriminatory and preferential. Thus,
there is a need to reform the use of
shortage pricing in RTO/ISO markets, as
discussed further herein.
2. NOPR Proposal
109. In order to remedy the
potentially unjust and unreasonable
rates caused by restrictions on shortage
pricing, the Commission proposed to
require that RTOs/ISOs institute
mechanisms that trigger shortage pricing
for any dispatch interval during which
a shortage of energy or operating
reserves occurs.
3. Comments on the Proposed Shortage
Pricing Reform
a. Comments by RTOs/ISOs
110. MISO states that it supports
shortage pricing reform and maintains
that MISO’s current practices are
already consistent with the
Commission’s proposal. Specifically,
MISO states its operating reserve
demand curve is used in the five-minute
dispatch interval and triggers shortage
pricing in any five-minute interval in
which operating reserve requirements
cannot be fully satisfied, regardless of
duration or causation.158 MISO also
states that its recent implementation of
extended locational marginal pricing
(ELMP) considers offline fast-start
resources in its price setting algorithm
to more accurately reflect the cost of the
next MW to meet demand during
scarcity conditions.159 MISO notes that
if no economic offline fast-start
resources are eligible, it will rely upon
the operating reserve demand curve
values for shortage pricing. MISO states
that it is already compliant with the
proposed rule on shortage pricing.160
158 MISO
Comments at 10.
MISO, Extended Locational Marginal
Pricing, Docket No. ER12–668–000 (filed Dec. 22,
2011).
160 MISO Comments at 11–12.
159 See
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111. ISO–NE supports the shortage
pricing proposal and asserts that its
current market rules and real-time
pricing systems already comply with the
proposed requirement.161
112. NYISO supports the shortage
pricing proposal, and states that it uses
demand curves to price all reserve
shortages, regardless of their duration.
NYISO adds that it currently
implements shortage pricing in its dayahead and real-time markets using
various demand curves for operating
reserves, regulating reserves, and
transmission security, where the
demand curves represent the escalating
value of each product as the level of any
shortage increases.162 NYISO also states
that it does not interpret the NOPR to be
addressing the use of offline resources
in real-time pricing or to be implying
that practices, such as the NYISO’s
‘‘Hybrid Pricing’’ rules,163 are
inconsistent with the NOPR.164
113. CAISO agrees with the concept
behind the shortage pricing reform and
supports its implementation, subject to
certain clarifications. CAISO expects
that its existing tariff provisions
implementing scarcity pricing for
energy and ancillary services already
comply with the NOPR’s proposal.
CAISO explains that, in any fifteenminute interval of the fifteen-minute
market, it will co-optimize the
procurement of energy and ancillary
services based on submitted supply bids
and the forecast of demand and its
ancillary services requirements. CAISO
further explains that, in any given
fifteen-minute interval, if effective
supply bids are insufficient to clear
forecasted demand, scarcity pricing will
trigger and thereby indicate a shortage
of supply for that applicable fifteenminute interval. CAISO states that,
similarly, if ancillary services bids are
not sufficient to meet the ancillary
services procurement target, ancillary
services scarcity pricing will trigger for
that interval.165
114. CAISO notes that within a
fifteen-minute operating interval it may
need to deploy operating reserves to
address a contingency in the case of
operating reserves, or in the case of
regulation to continuously balance
supply and demand. CAISO states that
161 ISO–NE
Comments at 3.
Comments at 6.
163 NYISO’s Hybrid Pricing rules were adopted in
2001. See New York Indep. Sys. Operator, Inc., 95
FERC ¶ 61,121 (2001). The Hybrid Pricing rules
apply to Real-Time Market pricing and relax the
minimum operating limits of certain fast-start,
block-loaded resources in order to permit them to
be eligible to set price based on the incremental
need that required their commitment.
164 NYISO Comments at 7.
165 CAISO Comments at 20.
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162 NYISO
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it is important that the Final Rule clarify
that the deployment of operating
reserves or regulation does not
necessarily mean a shortage exists.
CAISO notes that in some cases the
deployment of reserves is made through
alternative deployment mechanisms and
not in the co-optimization function of
the market.166 CAISO also explains that
in any given fifteen-minute market
interval, if a shortage is observed,
shortage pricing will trigger within that
interval and CAISO will not wait for the
shortage to materialize beyond that
interval before triggering shortage
pricing. However, CAISO states that not
all price signals triggered by ‘‘transient
shortages’’ provide incentives to
resources that have the capability to
respond to brief-duration shortages.167
115. PJM and SPP filed joint
comments opposing triggering shortage
pricing in any dispatch interval in
which a shortage of energy or operating
reserves occurs. First, PJM and SPP state
that they support shortage pricing only
when ‘‘a shortage of a particular product
exists that presents reliability
concerns.’’ 168 PJM and SPP argue that
applying shortage prices to shortage
events that do not cause reliability
concerns allows price increases even
when such events are transitory, do not
pose reliability concerns, and cannot be
addressed due to limitations on resource
response. PJM and SPP maintain that
applying shortage pricing to some
transient shortages will give inaccurate
prices and could potentially degrade
system reliability, and may also result in
market pricing and operations that are
contrary to the Commission’s stated
goals.169
116. PJM and SPP further state that
they have in place rules related to this
issue consistent with the principles and
goals of shortage pricing. PJM and SPP
urge the Commission to provide
flexibility by allowing RTOs/ISOs to
implement shortage pricing in the
context of their regional rules. This, PJM
and SPP assert, will ensure that
inefficient pricing does not result.170
166 CAISO explains that during each fifteenminute interval in which the resources are
deployed, the system is not actually short of supply
bids when the operating reserves for that interval
are procured. Also, CAISO states that once the
reserves are deployed, to the extent that the market
allows for full recovery of the required reserves, the
contingency event itself does not trigger scarcity
pricing for ancillary services. According to CAISO,
this is because no actual shortage of operating
reserves exists unless there are insufficient
resources to meet operational needs for operating
reserves in the next applicable fifteen-minute
market interval. CAISO Comments at 21–22.
167 CAISO Comments at 23.
168 PJM and SPP Comments at 1.
169 PJM and SPP Comments at 1–2.
170 PJM and SPP Comments at 2–3.
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117. PJM and SPP argue that allowing
transient periods of shortage to trigger
shortage pricing could overstate the
severity of the operating condition and
result in prices that do not accurately
reflect operating conditions on the
system, or last long enough to allow
market participants responding to them
to take meaningful action. In fact, PJM
and SPP assert that responses may occur
after the relevant interval has passed,
which could be counterproductive
operationally and economically. PJM
and SPP pose two examples to illustrate
this point. As the first example, they
posit: PJM carrying the required amount
of reserves when a market seller of a
generation resource lowers the
resource’s economic maximum
capability, for a brief time (ten minutes
or less), causing PJM to have less
reserves than its requirement. Currently,
PJM can recover these reserves by reexecuting its dispatch engine and redispatching its system; but under the
shortage pricing reform, this could
invoke shortage pricing, which would
then attract more suppliers than needed
and create disincentives for resources to
back down once the event was over. In
another example, they posit: PJM has
scheduled a resource with a ten-minute
start-up time to come online to provide
energy so that another resource may be
reduced to provide reserves; but if the
resource scheduled to come online
actually takes twenty minutes instead of
ten, shortage pricing would be triggered
under the shortage pricing proposal, and
the second resource, instead of having
its output reduced to provide reserves
would now need to continue to provide
energy, thus potentially leaving PJM
short on reserves for a brief period.171
118. PJM and SPP introduce another
hypothetical scenario from the SPP
region. PJM and SPP state that SPP can
temporarily use operating reserves to
meet energy requirements during
transient periods when system
conditions do not present reliability
concerns. PJM and SPP argue that while
this may technically compromise the
operating reserve requirement, the
condition is transient and is recovered
in less than ten minutes. According to
PJM and SPP, this is not an operating
reserve shortage, but rather a transient
reallocation of capacity to manage
temporary energy needs caused by the
operational characteristics of resources.
PJM and SPP further state that the
examples described above do not
present emergency conditions or
171 PJM
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reliability concerns that would justify
shortage pricing.172
119. In order to ‘‘recognize and
respect the fact that not all instances of
shortages justify shortage pricing,’’ PJM
and SPP propose alternative language
for any Final Rule on shortage pricing:
Each RTO/ISO must establish tariff
provisions that implement shortage pricing
for pre-defined operating conditions related
to a shortage of energy or operating reserves.
The Commission will allow each RTO/ISO to
develop those provisions based on their
regional circumstances, provided that the
rules are consistent with shortage pricing
principles and are designed to facilitate the
goals of this [Final Rule]. The Commission
expects that each RTO/ISO will explain why
their provisions, or why their current rules,
comply with this rule.173
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120. PJM and SPP further assert that
a universal shortage pricing rule
requiring shortage pricing even for
transient circumstances would require
the implementation of operating reserve
demand curves that distinguish prices
relative to varying degrees of shortage.
PJM and SPP explain further that in
PJM’s case, the current operating reserve
demand curves are a step function,
which would need to be changed, and
in SPP’s case it would likely consider
the implementation of a pricing gradient
demand curve based on different
degrees of shortages and their impact on
reliability, rather than steep step
curves.174
b. Comments by Market Monitors
121. Potomac Economics explains that
all the markets that it monitors (ISO–
NE, NYISO, and MISO) are designed to
price all shortages, regardless of
duration.175 Potomac Economics states
that it strongly supports the shortage
pricing reform and argues that pricing
all shortages, regardless of duration,
provides efficient incentives for
resources to be flexible and to perform
well, which ultimately lowers costs to
consumers and improves reliability.176
Potomac Economics states that, together
with the alignment of dispatch and
settlement intervals, a requirement for
RTOs/ISOs to price ‘‘transitory
shortages’’ rewards units that can
respond quickly to help the RTO/ISO
remedy the shortage and, in doing so,
addresses the diminished reliability
caused by the shortage.177
122. Potomac Economics states that
transitory shortages typically occur
when the system is ramp-constrained,
172 PJM
and SPP Comments at 5–6.
and SPP Comments at 7.
174 PJM and SPP Comments at 8.
175 Potomac Economics Comments at 9.
176 Potomac Economics Comments at 7.
177 Potomac Economics Comments at 7.
and that these are true shortages,
because if a large contingency occurs
during this period (e.g., a generator
tripping off-line), the RTO/ISO will not
have the ability to replace the capacity
because its other generators are already
ramping as quickly as possible. Potomac
Economics states that the Commission’s
proposal will lead to resources offering
faster ramp rates, offering wider
dispatch ranges and not self-scheduling
resources, and offering shorter start
times for natural gas turbines. Potomac
Economics states that the proposal also
has important long-term implications as
it provides efficient incentives for
participants to build more flexible, fastramping generating resources, and to
make maintenance decisions on existing
resources to increase their flexibility.178
123. Potomac Economics also states
that allowing offline resources to set
real-time energy and ancillary services
prices can be efficient, but there are also
conditions under which the use of these
resources can artificially lower energy
prices and obscure shortages.179
Potomac Economics explains 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.
Further, Potomac Economics explains
that the artificial increase in real-time
supply can have a large effect when the
system is experiencing an operating
reserve or transmission shortage, which
is ultimately not priced as a shortage
because an offline unit has set the
price.180
124. Potomac Economics recommends
that the Commission require RTOs/ISOs
to demonstrate that their real-time
pricing models do not allow offline
units to set prices in a manner that
undermines its real-time shortage
pricing. Potomac Economics believes
that this can be demonstrated by the
RTO/ISO describing how and when
offline units set real-time prices and
showing that when offline units have set
price historically that they are generally
committed and dispatched as well.
Potomac Economics further asserts that
if the RTOs/ISOs cannot demonstrate
this in their compliance filing, then they
may need to make changes to their
pricing models to ensure that they
satisfy the Commission’s price
formation goals.181
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 minuteby-minute granularity, they should not
implement five-minute shortage pricing
until they have that capability.182
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
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
173 PJM
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178 Potomac
Economics Comments at 8.
Economics Comments at 9.
180 Potomac Economics Comments at 10.
181 Potomac Economics Comments at 9–11.
179 Potomac
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182 PJM
Market Monitor Comments at 9.
Market Monitor Comments at 4 (citing
SPP Tariff, Attachment AE 5.1.2.1 and 8.3.4.2).
184 SPP Market Monitor Comments at 4–6.
183 SPP
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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
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
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
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.
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.
190 EPSA Comments, Pope Aff. at 15; NEI
Comments at 14; CEA Comments at 4; NGSA
Comments at 5.
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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
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 realtime markets.193
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
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
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
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
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, fastramping 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
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
197 ESA
Comments at 4.
Comments at 4.
199 Inertia Power and DC Energy Comments at 5;
Exelon Comments at 6.
200 PSEG Comments at 13.
201 PSEG Comments at 14.
202 Golden Spread Reply Comments at 4.
203 Golden Spread Reply Comments at 7.
198 ESA
191 CEA
Comments at 4.
Comments at 5.
193 ANGA Comments at 5.
194 Powerex Comments at 6.
195 Powerex Comments at 8.
196 EDP Renewables Comments at 5–6.
192 NGSA
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accurate price signals, akin to the
shortage pricing proposal.204
e. Comments Opposed to the Proposed
Shortage Pricing Reform
d. Comments Recommending Changes
to the 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 costjustified 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
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
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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
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
140. ELCON states that the shortage
pricing proposal should be adopted only
if the Commission promotes the
development of technology-neutral fastramp products paid to provide the
specific shortage service, and for which
compensation would not inflate realtime 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
204 DTE
Comments at 5.
Spread Reply Comments at 5.
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.
210 ELCON Comments at 2.
211 ELCON Comments at 3–6.
205 Golden
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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.
215 APPA and NRECA Comments at 6–7.
216 APPA and NRECA Comments at 7.
217 APPA and NRECA Comments at 9.
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infrequently in PJM and MISO, but more
frequently in NYISO.218
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
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
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
218 APPA
and NRECA Comments at 9–10.
and NRECA Comments at 10–11.
220 Concerned Cooperatives Comments at 14.
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.
223 Concerned Cooperatives Comments at 22–24.
219 APPA
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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
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
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
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
and NRECA Comments at 12.
225 Concerned Cooperatives Comments at 15–16.
226 ODEC Comments at 6.
227 APPA and NRECA Comments at 15–16.
228 Concerned Cooperatives Comments at 15.
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
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 fiveminute shortfalls are not necessarily
symptomatic of system stress, but are
merely transient shortfalls that can be
quickly addressed through system redispatch.
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
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
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
224 APPA
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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
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
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
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
233 Direct
Energy Comments at 11–13.
and NRECA Comments at 5; Concerned
Cooperatives Comments at 18.
235 Concerned Cooperatives Comments at 18.
236 Concerned Cooperatives Comments at 26.
237 Concerned Cooperatives Comments at 26.
234 APPA
229 Concerned
Cooperatives Comments at 24–25.
Comments at 7–13.
231 Direct Energy Comments at 10–11.
232 Direct Energy Comments at 10–11.
230 TAPS
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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.
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
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 five238 Concerned
Cooperatives Comments at 18–21.
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.
239 See
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minute shortage where a resource
cannot respond and/or the event is
triggered by an artificial shortage.244
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 dayahead 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
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 realtime. 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
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
244 Concerned
Cooperatives Comments at 25.
Comments at 1–2.
246 PG&E Comments at 1–2.
247 PG&E Comments at 2.
245 PG&E
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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
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.
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
248 Dominion
Comments at 4–5.
Comments at 5.
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 shortlived.’’).
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.
249 Dominion
250 NOPR,
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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.
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 selfscheduling resources; (3) shorter start
times for natural gas turbines; and (4) an
incentive to build more flexible, fastramping 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.
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
253 See NOPR, FERC Stats. & Regs. ¶ 32,710 at P
48 (citing Order No. 719, FERC Stats. & Regs.
¶ 31,281).
254 Potomac Economics Comments at 8.
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.
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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.
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
257 EPSA
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42901
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.
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
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
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).
259 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 46
& n.70; PJM and SPP Comments at 5.
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.
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sradovich on DSK3GDR082PROD with RULES2
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.
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.
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
263 Potomac
Economics Comments at 8.
and SPP Comments at 4.
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.
266 PJM and SPP Comments at 7–8.
267 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 49.
264 PJM
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appropriate forum to make such is a
change is through an FPA section 205
filing.
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.
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
268 TAPS Comments at 9; APPA and NRECA
Comments at 7; Concerned Cooperatives Comments
at 16.
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/
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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.
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.
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
2016/New_Generation_in_the_PJM_Capacity_
Market_20160504.pdf.
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.
273 PJM Market Monitor Comments at 9.
274 Concerned Cooperatives Comments at 6.
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prices that better reflect expected
system conditions.
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 fastramping 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 dayahead 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.
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.
sradovich on DSK3GDR082PROD with RULES2
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
275 Concerned Cooperatives Comments at 18–25;
ELCON Comments at 2; PG&E Comments at 2.
276 Concerned Cooperatives Comments at 15.
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for implementation of reforms to
shortage pricing triggers.277
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
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 fiveminute 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
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
277 NOPR, FERC Stats. & Regs. ¶ 32,710 at PP 38,
54–55.
278 ISO/RTO Council Comments at 3.
279 PJM Comments at 7; MISO Comments at 13;
ISO–NE Comments at 1.
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 fiveminute settlement of real-time energy transactions,
which is currently being discussed with
stakeholders.’’ Id. at 3.
282 MISO Comments at 3.
283 MISO Comments at 6.
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42903
filing, what it believes is a reasonable
implementation schedule.284
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
187. CAISO also states that,
depending upon the specifics of the
Final Rule, extra time may be necessary
for a complete compliance filing.288
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
189. NEPOOL, Golden Spread, and
TAPS echo the statements of EEI,
284 MISO
Comments at 12.
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.
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.
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.
285 PJM
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contending that implementation should
account for specific differences between
the RTOs/ISOs instead of imposing a
rigid standard.293
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
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
d. Implementation Deadline
sradovich on DSK3GDR082PROD with RULES2
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.
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
293 NEPOOL Comments at 5; Golden Spread
Comments at 7–8; TAPS Comments at 14–15.
294 TAPS Comments at 13.
295 Golden Spread Comments at 8–10.
296 Concerned Cooperatives Comments at 12.
297 TAPS Comments at 14.
298 PSEG Comments at 8.
299 PSEG Comments at 15; Inertia Power
Comments at 9.
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compliance and implementation of the
Final Rule.300
194. Exelon maintains that the
implementation period for the fiveminute 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 fiveminute pricing.301
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
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
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
300 ODEC
Comments at 5.
Comments at 5.
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.
304 Dominion Comments at 2; IPL Comments at
2–3.
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.
301 Exelon
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implementation details with their
stakeholders.308
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
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
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
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
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 costbenefit analysis is necessary before
implementation.317 IPL asserts this
308 Concerned
Cooperatives Comments at 26–27.
and NRECA Comments at 4–5.
310 Direct Energy Comments at 6.
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.
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.
317 APPA and NRECA Comments at 4–5;
Concerned Cooperatives Comments at 12; Ameren
Comments at 4; IPL Comments at 2.
309 APPA
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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 costbenefit 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
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 longterm 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
sradovich on DSK3GDR082PROD with RULES2
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.
318 IPL
Comments at 2.
Comments, Pope Aff. at 13–14; PJM
Market Monitor Comments at 2–3.
320 Duke Comments at 6.
321 Duke Comments at 5.
322 Inertia Power Comments at 7.
323 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 55.
319 EPSA
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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
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
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.
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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
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 longrun 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
325 PJM
Comments at 3.
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.
326 APPA
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may be approximated, calculating the
efficiency benefits of implementing fiveminute settlements is effectively
impossible.329
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
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
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
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;
329 PJM
Market Monitor Comments at 2–3.
Comments at 11.
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)).
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.
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and (3) transparency with regard to outof-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
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 dayahead transmission product, and
recommends the implementation of
such a product across all RTOs/ISOs.340
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
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 dayahead market.342
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
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
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.
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)).
341 Financial Marketers Coalition Comments at 4–
6; XO Energy Comments at 3–4.
342 Entergy Nuclear Power Marketing Comments
at 2–3; NEI Comments at 15.
343 NEI Comments at 15–16.
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.
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participation of demand response in
RTO/ISO markets.347
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
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-ofmarket procurement and other operator
interventions, to prevent shortage
pricing from being triggered or
otherwise prevent scarcity from being
reflected in market prices.349
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
223. ESA requests that the
Commission consider five-minute
scheduling once it implements fiveminute intervals to better access the
greater operational flexibility of fastramping resources like energy
storage.351
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
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
347 Public
Interest Organizations Comments at
4–5.
348 SPP
Market Monitor Comments at 7.
Comments at 9.
350 Dominion Comments at 3–4.
351 ESA Comments at 4–5.
352 Powerex Comments at 12–13.
349 Powerex
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demand response in order to serve
load.353
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
227. Potomac Economics states that
the Commission’s focus on shortage
pricing should extend to transmission
shortages.355
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
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
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.
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
353 Appian
Way Comments at 2.
Power Comments at 5–6.
355 Potomac Economics Comments at 11.
356 Public Interest Organizations Comments at
3–5.
357 Mr. Lively Comments at 3–4 (filed Nov. 23,
2015).
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).
359 44 U.S.C. 3501–3520 (2012).
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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.
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
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
360 5
CFR part 1320 (2015).
U.S.C. 3507(d).
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.
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
363 See
supra PP 201–203.
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.
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
364 ‘‘Burden’’
361 44
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FERC 516D,367 as implemented in final rule in
RM15–24–000
Number of respondents
Annual number of
responses per
respondent
Total number of
responses
Average burden
hours & cost
per response
Annual burden
hours & total
annual cost
(1)
(2)
(1) × (2) = (3)
(4)
(3) × (4) = (5)
Tariff filings one-time in
Year 1, for RTOs/ISOs
that currently align realtime settlement with dispatch intervals.
Tariff filings one-time in
Year 1, for RTOs/ISOs
that do not currently align
real-time settlement with
dispatch intervals.
3 RTOs or ISOs .................
1
3
80 hrs; $5,840 .......
240 hrs; $17,520.
3 RTOs or ISOs .................
1
3
160 hrs; 11,680 .....
480 hrs; 35,040.
Total (one-time in Year
1) 368.
6 .........................................
..............................
6
................................
720 hrs.; 52,560.
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: oira_submission@
omb.eop.gov. Comments submitted to
OMB should refer to FERC–516D and
OMB Control No. To Be Determined.
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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.
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: DataClearance@ferc.gov, Phone:
(202) 502–8663, fax: (202) 273–0873.
Comments concerning the collection of
information and the associated burden
estimate(s) may also be sent to the
Office of Information and Regulatory
VI. Regulatory Flexibility Act
237. The Regulatory Flexibility Act of
1980 (RFA) 371 generally requires a
(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.
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
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.
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 onetime 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.
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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
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within four months of the effective date of the Final
Rule.
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).
371 5 U.S.C. 601–612 (2012).
372 The RFA definition of ‘‘small entity’’ refers to
the definition provided in the Small Business Act,
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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.
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. Email the
Public Reference Room at
public.referenceroom@ferc.gov.
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
ferconlinesupport@ferc.gov, or the
Electric power rates, Electric utilities,
Reporting and recordkeeping
requirements.
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
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
1. The authority citation for part 35
continues to read as follows:
■
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
■
■
■
2. Amend § 35.28 as follows:
a. Revise paragraph (g)(1)(iv)(A).
b. Add paragraph (g)(1)(vi).
§ 35.28 Non-discriminatory open access
transmission tariff
*
*
*
(g) * * *
(1) * * *
*
*
42909
(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
Commenter
AEMA ...............................................
Ameren .............................................
ANGA ...............................................
APPA and NRECA ...........................
Appian Way ......................................
CAISO ..............................................
CEA ..................................................
Concerned Cooperatives .................
sradovich on DSK3GDR082PROD with RULES2
Short name/acronym
Advanced Energy Management Alliance.
Ameren Services Company (on behalf of Ameren Illinois Company and Union Electric Company).
America’s Natural Gas Alliance.
American Public Power Association and National Rural Electric Cooperative Association.
Appian Way Energy Partners.
California Independent System Operator Corporation.
Canadian Electricity Association.
Hoosier Energy Rural Electric Cooperative, Inc., Kansas Electric Power Cooperative, Inc., and North Carolina Electric Membership Corporation.
Delaware Public Service Commission.
Direct Energy Business, LLC and Direct Energy Business Marketing, LLC.
Dominion Resources Services, Inc.
DTE Electric Company.
Delaware Commission .....................
Direct Energy ...................................
Dominion ..........................................
DTE ..................................................
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
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section 3 of the Small Business Act, 15 U.S.C. 632
(2012)).
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Short name/acronym
Commenter
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 North America LLC.
Edison Electric Institute.
Electricity Consumers Resource Council.
Energy Storage Association.
Electric Power Supply Association.
Entergy Nuclear Power Marketing, LLC.
Exelon Corporation.
Financial Marketers Coalition.
Golden Spread Electric Cooperative, Inc.
Inertia Power, LP and DC Energy, LLC.
Indianapolis Power & Light Company.
ISO/RTO Council.
ISO New England Inc.
Mark B. Lively, Utility Economic Engineers.
Midcontinent Independent System Operator, Inc.
New England Power Pool Participants Committee.
Nuclear Energy Institute.
New Jersey Board of Public Utilities.
Natural Gas Supply Association.
New York Independent System Operator, Inc.
Old Dominion Electric Cooperative.
Paul Centolella and Associates, L.L.C.
Pacific Gas & Electric Company.
PJM Interconnection, L.L.C.
Monitoring Analytics, LLC, Independent Market Monitor for PJM.
PJM Power Providers Group.
Potomac Economics, Ltd.
Powerex Corp.
PSEG Companies (Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Resources & Trade LLC).
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.
Southern California Edison Company.
Southwest Power Pool, Inc.
Southwest Power Pool, Inc. Independent Market Monitoring Unit.
Transmission Access Policy Study Group.
Westar Energy, Inc.
XO Energy, LLC.
EDP Renewables .............................
EEI ...................................................
ELCON .............................................
ESA ..................................................
EPSA ................................................
Entergy Nuclear Power Marketing ...
Exelon ..............................................
Financial Marketers Coalition ..........
Golden Spread .................................
Inertia Power and DC Energy ..........
IPL ....................................................
ISO/RTO Council .............................
ISO–NE ............................................
Mr. Lively ..........................................
MISO ................................................
NEPOOL ..........................................
NEI ...................................................
New Jersey Board ...........................
NGSA ...............................................
NYISO ..............................................
ODEC ...............................................
Mr. Centolella ...................................
PG&E ...............................................
PJM ..................................................
PJM Market Monitor .........................
PJM Power Providers ......................
Potomac Economics ........................
Powerex ...........................................
PSEG ...............................................
Public Interest Organizations ...........
SCE ..................................................
SPP ..................................................
SPP Market Monitor .........................
TAPS ................................................
Westar ..............................................
XO Energy .......................................
REPLY OR SUPPLEMENTAL COMMENTS
Short name/acronym
Commenter
Date submitted
Golden Spread ....................
Direct Energy ......................
Golden Spread Electric Cooperative, Inc ..............................................................................
Direct Energy Business, LLC and Direct Energy Business Marketing, LLC .........................
December 14, 2015.
March 4, 2016.
LATE COMMENTS
Short name/acronym
Commenter
Date submitted
New Jersey Board ..............
New Jersey Board of Public Utilities ......................................................................................
[FR Doc. 2016–15196 Filed 6–29–16; 8:45 am]
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BILLING CODE 6717–01–P
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December 3, 2015.
Agencies
[Federal Register Volume 81, Number 126 (Thursday, June 30, 2016)]
[Rules and Regulations]
[Pages 42881-42910]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-15196]
[[Page 42881]]
Vol. 81
Thursday,
No. 126
June 30, 2016
Part III
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Settlement Intervals and Shortage Pricing in Markets Operated by
Regional Transmission Organizations and Independent System Operators;
Final Rule
Federal Register / Vol. 81 , No. 126 / Thursday, June 30, 2016 /
Rules and Regulations
[[Page 42882]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM15-24-000; Order No. 825]
Settlement Intervals and Shortage Pricing in Markets Operated by
Regional Transmission Organizations and Independent System Operators
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Federal Energy Regulatory Commission (Commission) is
revising its regulations to address certain practices that fail to
compensate resources at prices that reflect the value of the service
resources provide to the system, thereby distorting price signals, and
in certain instances, creating a disincentive for resources to respond
to dispatch signals. We require that each regional transmission
organization and independent system operator align settlement and
dispatch intervals by: Settling energy transactions in its real-time
markets at the same time interval it dispatches energy; settling
operating reserves transactions in its real-time markets at the same
time interval it prices operating reserves; and settling intertie
transactions in the same time interval it schedules intertie
transactions. We also require that each regional transmission
organization and independent system operator 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. Adopting
these reforms will align prices with resource dispatch instructions and
operating needs, providing appropriate incentives for resource
performance.
DATES: This rule will become effective September 13, 2016.
FOR FURTHER INFORMATION CONTACT:
Stanley Wolf (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-6841, Stanley.Wolf@ferc.gov
Pamela Quinlan (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-6179, Pamela.Quinlan@ferc.gov
Alicia Cobb (Legal Information), Office of the General Counsel--Energy
Markets, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-8501, Alicia.Cobb@ferc.gov
SUPPLEMENTARY INFORMATION:
Order No. 825
Final Rule
Table of Contents
Paragraph No.
I. Introduction...................................... 1
II. Background....................................... 9
III. Discussion...................................... 13
A. Settlement Interval Reform.................... 13
1. Need for Reform........................... 13
2. Settlement Interval Reform for Energy 17
Transactions and Operating Reserves.........
a. Proposal.............................. 17
i. Energy Transactions............... 17
ii. Operating Reserves............... 21
b. Current Practices in the RTOs/ISOs.... 22
i. Energy Transactions............... 22
ii. Operating Reserves............... 23
c. Comments on the Proposed Settlement 27
Interval Reform.........................
i. Comments From the RTOs/ISOs....... 28
ii. Comments by Market Monitors...... 36
iii. Comments Supporting the Proposed 39
Settlement Interval Reform..........
iv. Comments Opposed to the Proposed 49
Settlement Interval Reform..........
d. Commission Determination.............. 53
i. Energy Transactions............... 53
ii. Operating Reserves............... 69
3. Interties................................. 74
a. Commission Request for Comments....... 74
i. Comments by RTOs/ISOs............. 75
ii. Comments by Market Monitors...... 80
iii. Comments in Support of Applying 82
Settlement Reform to Interties......
iv. Comments Opposed To Applying 86
Settlement Reform to Interties......
b. Commission Determination.............. 88
4. Demand Response Resources................. 92
a. Comments.............................. 92
b. Commission Determination.............. 98
5. Load...................................... 100
a. Comments.............................. 100
b. Commission Determination.............. 104
B. Shortage Pricing Reform....................... 105
1. Need for Reform........................... 105
2. NOPR Proposal............................. 109
3. Comments on the Proposed Shortage Pricing 110
Reform......................................
a. Comments by RTOs/ISOs................. 110
b. Comments by Market Monitors........... 121
c. Comments Supporting the Shortage 127
Pricing Reform..........................
d. Comments Recommending Changes to the 137
Shortage Pricing Reform.................
e. Comments Opposed to the Proposed 141
Shortage Pricing Reform.................
4. Commission Determination.................. 161
C. Compliance and Implementation................. 181
1. Commission Proposal....................... 181
[[Page 42883]]
2. Comments.................................. 182
a. Comments From RTOs/ISOs............... 183
b. Comments Urging Flexibility in 188
Implementation..........................
c. Compliance Filing Deadline............ 191
d. Implementation Deadline............... 192
e. Simultaneous Implementation........... 200
f. Costs................................. 201
3. Commission Determination.................. 204
D. Requests Beyond the Scope of This Proceeding.. 211
1. Comments.................................. 211
2. Commission Determination.................. 230
IV. Information Collection Statement................. 231
V. Environmental Analysis............................ 236
VI. Regulatory Flexibility Act....................... 237
VII. Document Availability........................... 240
VIII. Effective Date and Congressional Notification.. 243
APPENDIX: List of Commenters.........................
I. Introduction
1. In this Final Rule, we address certain practices that fail to
compensate resources at prices that reflect the value of the service
resources provide to the system, thereby distorting price signals, and
in certain instances, creating a disincentive for resources to respond
to dispatch signals. We require, pursuant to section 206 of the Federal
Power Act (FPA),\1\ that each regional transmission organization (RTO)
and independent system operator (ISO) align settlement and dispatch \2\
intervals by: (1) Settling energy transactions in its real-time markets
at the same time interval it dispatches energy;
---------------------------------------------------------------------------
\1\ 16 U.S.C. 824e (2012).
\2\ As mentioned in the Notice of Proposed Rulemaking, the
Commission sometimes uses the term ``dispatch'' as shorthand when
describing how RTOs/ISOs acquire and price energy and operating
reserves. With respect to operating reserves, the Commission uses
dispatch to describe the intervals at which they are acquired and
priced. See Settlement Intervals and Shortage Pricing in Markets
Operated by Regional Transmission Organizations and Independent
System Operators, 80 FR 58,393 (Sept. 29, 2015), FERC Stats. & Regs.
] 32,710, at P 1 (2015) (NOPR).
---------------------------------------------------------------------------
(2) settling operating reserves transactions in its real-time
markets at the same time interval it prices operating reserves; \3\ and
(3) settling intertie transactions \4\ in the same time interval it
schedules intertie transactions (settlement interval requirements). We
also require, pursuant to section 206 of the FPA, that each RTO/ISO
establish a mechanism 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 (shortage pricing
requirement).
---------------------------------------------------------------------------
\3\ Operating reserves refer to certain ancillary services
procured in the wholesale market, although they are often defined
differently in each RTO/ISO. Operating reserves typically include:
(a) Regulating Reserve, used to account for very short-term
deviations between supply and demand (e.g., 4 to 6 seconds); (b)
Spinning, or Synchronous Reserve, which is capacity held in reserve
and synchronized to the grid and able to respond within a relatively
short amount of time (e.g., within 10 minutes), to be used in case
of a contingency, such as the loss of a generator; and (c) Non-
Spinning Reserve, capacity that is not synchronized to the grid and
which can take longer to respond (e.g., within 10-30 minutes) in
case of a contingency. Federal Energy Regulatory Commission, Price
Formation in Organized Wholesale Electricity Markets: Staff Analysis
of Shortage Pricing, Docket No. AD14-14-000, at 3 n.7 (Oct. 2014),
http://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricing-rto-iso-markets.pdf (Shortage Pricing Paper).
\4\ Intertie transactions are transactions across RTO/ISO
borders, including imports, exports and wheel-through transactions.
---------------------------------------------------------------------------
2. Some current RTO/ISO settlement practices fail to reflect the
value of providing a given service, thereby distorting price signals
and failing to provide appropriate signals for resources to respond to
the actual operating needs of the market. One such practice occurs when
RTOs/ISOs dispatch resources every five minutes but perform settlements
based on an hourly integrated price, or when RTOs/ISOs schedule
intertie transactions every fifteen minutes, but perform settlements on
an hourly integrated price. This misalignment between dispatch and
settlement intervals distorts the price signals sent to resources and
fails to reflect the actual value of resources responding to operating
needs because compensation will be based on average output and average
prices across an hour, rather than output and prices during the periods
of greatest need within a particular hour.
3. We also find that a second problem occurs if there is a mismatch
between the time when a system experiences a shortage of energy and
operating reserves and the time when prices reflect the shortage
condition. This can be particularly problematic when, for example, an
RTO's/ISO's market rules require a shortage to last a minimum time
period before triggering shortage pricing. In this instance, short-term
prices fail to reflect system conditions and potential reliability
costs, as well as the value of both internal and external market
resources responding to a dispatch signal. In addition, inaccurate
price signals are provided to market participants if shortage pricing
is still in effect after the shortage has been resolved.
4. To address these problems associated with differing dispatch
intervals and settlement intervals, as well as with shortage pricing
triggers, we are setting forth the settlement interval requirements and
the shortage pricing requirement in this Final Rule.\5\ These
settlement interval and shortage pricing requirements will help ensure
that resources have price signals that provide incentives to conform
their output to dispatch instructions, and that prices reflect
operating needs at each dispatch interval.
---------------------------------------------------------------------------
\5\ We are not at this time proposing to change the price paid
by any RTO/ISO when shortage pricing is triggered.
---------------------------------------------------------------------------
5. As set forth in the NOPR, we reiterate the goals of price
formation are to: (1) Maximize market surplus for consumer and
suppliers; (2) provide correct incentives for market participants to
follow commitment and dispatch instructions, make efficient investments
in facilities and equipment, and maintain reliability; (3) provide
transparency so that market participants understand how prices reflect
the actual marginal cost of serving load and the operational
constraints of reliably operating the system; and, (4) ensure that all
suppliers have an opportunity to recover their costs.\6\
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\6\ See Notice Inviting Post-Technical Workshop Comments, Docket
No. AD14-14-000, at 1 (Jan. 16, 2015); Notice, Docket No. AD14-14-
000 (June 19, 2014).
---------------------------------------------------------------------------
6. As noted in the NOPR, the reforms adopted in this Final Rule
advance at least two of the Commission's goals
[[Page 42884]]
with respect to price formation. First, the proposed reforms will help
provide correct incentives for market participants to follow commitment
and dispatch instructions,\7\ to make efficient investments in
facilities and equipment, and to maintain reliability. Specifically,
requiring RTOs/ISOs to align the settlement and dispatch intervals will
more accurately reward resources that are providing energy and
ancillary services in periods of the greatest need and will discourage
provision of energy and ancillary services immediately following
periods of system stress. Doing so will enhance the incentive to follow
an RTO's/ISO's dispatch signal and thus help maintain system
reliability. This reform will also reward resources that can flexibly
respond to system needs, thus creating an incentive for resources to
make efficient investments in facilities and equipment. Similarly,
implementing shortage pricing for any dispatch interval during which a
shortage of energy or operating reserves occurs will provide an
incentive for resources to ensure that they are available to respond to
high prices, which should help alleviate shortages and avoid shortage
pricing during subsequent dispatch intervals. 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.
---------------------------------------------------------------------------
\7\ The Commission notes that the reforms proposed herein would
further augment existing mechanisms in each RTO/ISO market that
provide incentives to follow dispatch instructions, such as
penalties for excessive or deficient energy and the allocation of
commitment and dispatch costs to deviations from energy dispatch
targets. See, e.g., MISO, FERC Electric Tariff, 40.3.3(a) (36.0.0)
(allocating Revenue Sufficiency Guarantee costs to, inter alia,
resources providing excessive or deficient energy), 40.3.4 (33.0.0)
(charges for excessive or deficient energy deployment).
---------------------------------------------------------------------------
7. Second, the proposed reforms will also help provide transparency
and certainty so that market participants understand how compensation
and prices reflect the actual marginal cost of serving load and the
operational constraints of reliably operating the system. Requiring
settlement intervals to match dispatch intervals will make resource
compensation more transparent by, among other things, increasing the
proportion of resource payment provided through payments of energy and
operating reserves rather than uplift. Further, requiring RTOs/ISOs to
trigger shortage pricing for an interval in which a shortage of energy
or operating reserves is indicated during the pricing of resources for
that interval will ensure that prices transparently reflect the
operational constraints of reliably operating the system. This
increased transparency, in turn, better informs decisions to build or
maintain resources and enhances consumers' ability to hedge. The
benefits summarized above and discussed in detail below would
ultimately help to ensure just and reasonable rates.
8. As discussed below, we require each RTO/ISO to submit a
compliance filing with the tariff changes needed to implement this
Final Rule within 120 days of the Final Rule's effective date. 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.\8\
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\8\ The Commission has followed a similar approach with the
timelines for compliance and implementation in the past. See, e.g.,
Frequency Regulation Compensation in the Organized Wholesale Power
Markets, Order No. 755, FERC Stats. & Regs. ] 31,324, at P 201
(2011), reh'g denied, Order No. 755-A, 138 FERC ] 61,123 (2012).
---------------------------------------------------------------------------
II. Background
9. The Commission has addressed price formation in organized
markets on prior occasions. For example, in Order No. 719, the
Commission addressed shortage pricing \9\ and required RTOs/ISOs to
develop and implement shortage pricing rules that would apply during
operating reserve shortages to ``ensure that the market price for
energy reflects the value of energy during an operating reserve
shortage.'' \10\ The Commission required such rules out of concern that
inappropriate price signals during an operating reserve shortage would
provide an insufficient incentive for market participants to take
appropriate actions.
---------------------------------------------------------------------------
\9\ Wholesale Competition in Regions with Organized Electric
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at PP 192-194
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ]
31,292, order on reh'g, Order No. 719-B, 129 FERC ] 61,252 (2009).
\10\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 194.
---------------------------------------------------------------------------
10. In June 2014, the Commission initiated a proceeding, in Docket
No. AD14-14-000, to evaluate issues regarding price formation in the
energy and ancillary services markets operated by RTOs/ISOs (price
formation proceeding). In the notice initiating that proceeding, the
Commission stated that there may be opportunities for the RTOs/ISOs to
improve the energy and ancillary services price formation process. As
set forth in the notice, locational marginal prices (LMP) and market-
clearing prices used in energy and ancillary services markets ideally
``would reflect the true marginal cost of production, taking into
account all physical system constraints, and these prices would fully
compensate all resources for the variable cost of providing service.''
\11\ Pursuant to the notice, staff conducted outreach and convened
technical workshops on the following four general issues: (1) Use of
uplift payments; (2) offer price mitigation and offer price caps; (3)
scarcity and shortage pricing; and (4) operator actions that affect
prices.\12\ The Commission also released staff reports on these topics.
In one of those reports, issued in October 2014, staff analyzed
shortage pricing issues.\13\
---------------------------------------------------------------------------
\11\ Notice, Docket No. AD14-14-000, at 2 (June 19, 2014).
\12\ Id. at 1, 3-4.
\13\ See Shortage Pricing Paper.
---------------------------------------------------------------------------
11. In its January 2015 Notice Inviting Comments, the Commission
requested comments on questions that arose from the price formation
technical workshops.\14\ In response, among other price formation
issues, commenters addressed settlement intervals and shortage pricing.
---------------------------------------------------------------------------
\14\ Notice Inviting Post-Technical Workshop Comments, Docket
No. AD14-14-000 (Jan. 16, 2015).
---------------------------------------------------------------------------
12. On September 17, 2015, the Commission issued a NOPR proposing
to require that each RTO/ISO: (1) Settle energy transactions in its
real-time markets at the same time interval it dispatches and prices
energy, and settle operating reserves transactions in its real-time
markets at the same time interval it prices operating reserves; and (2)
trigger shortage pricing for any dispatch interval during which a
shortage of energy or operating reserves occurs.\15\ The Commission
sought comments on these proposals, and sought comment on: (1) Whether
settlement interval reforms are appropriate for intertie transactions
that are scheduled on intervals different from the intervals on which
RTOs/ISOs dispatch internal real-time energy; and (2) whether it is
appropriate to align the settlement interval for intertie transactions
with external scheduling intervals, e.g., fifteen minutes.\16\
Additionally, the Commission sought comment on whether to require that
RTOs/ISOs settle real-time operating reserves transactions at the same
interval as real-time energy dispatch and settlement intervals or
whether a settlement interval that differs from an RTO's/ISO's real-
time energy dispatch interval would be appropriate for some operating
reserves transactions.\17\
[[Page 42885]]
Finally, the Commission sought comment on the implementation schedule
and the costs of implementation.\18\ A list of commenters and the
abbreviated names used for them in this Final Rule appears in the
Appendix.
---------------------------------------------------------------------------
\15\ NOPR, FERC Stats. & Regs. ] 32,710 at P 14.
\16\ NOPR, FERC Stats. & Regs. ] 32,710 at P 39.
\17\ NOPR, FERC Stats. & Regs. ] 32,710 at P 40.
\18\ NOPR, FERC Stats. & Regs. ] 32,710 at PP 56, 60.
---------------------------------------------------------------------------
III. Discussion
A. Settlement Interval Reform
1. Need for Reform
13. In the NOPR,\19\ the Commission preliminarily found that the
current RTO/ISO settlement practice of using hourly integrated prices
for real-time settlement and five-minute dispatch instructions may fail
to reflect the value of providing a given service, and may contribute
to lack of a response to the actual operating needs of those markets.
In addition, the Commission stated that the use of hourly integrated
prices for real-time settlement may discourage resources from following
five-minute dispatch instructions, and may increase the need for uplift
payments. Therefore, the Commission preliminarily found that the use of
hourly integrated prices for real-time settlement may result in rates
that are unjust and unreasonable.
---------------------------------------------------------------------------
\19\ NOPR, FERC Stats. & Regs. ] 32,710 at PP 26-33.
---------------------------------------------------------------------------
14. Commenters generally agree with the Commission's preliminary
finding regarding the settlement interval proposal. For example, EPSA
states that ``[w]hen real-time settlements for generation or
dispatchable demand are calculated based on hourly prices that are the
simple average of sub-hourly prices resulting from the actual dispatch,
there is a distortion to the real-time price signal impacting both
reliability and efficiency.'' \20\ Similarly, Potomac Economics states
that the inconsistency between five-minute dispatch instructions and
hourly-average price settlement intervals ``creates incentives for
generators to not follow the dispatch signal or to simply be inflexible
by (a) restricting dispatch range (the difference between a generator's
minimum dispatch level and maximum dispatch level) or (b) offering a
slower dispatch ramp rate.'' \21\ Potomac Economics notes that while
MISO makes uplift payments to generators to alleviate these incentive
issues, such payments are ``an inferior substitute for a true alignment
where each generator, importer or exporter would settle based on the
actual value of energy corresponding with its production or
transactions in each five-minute interval.'' \22\ ELCON asserts that
hourly prices do not ``reflect system needs and costs, and may result
in over or under recovery of costs depending on how the shortage plays
out during the hour. When SPP moved to sub-hourly settlements, overall
system costs were lower.'' \23\
---------------------------------------------------------------------------
\20\ EPSA Comments, Pope Aff. at 2-3.
\21\ Potomac Economics Comments at 4.
\22\ Potomac Economics Comments at 4-5.
\23\ ELCON Comments at 2.
---------------------------------------------------------------------------
15. In some instances, commenters assert that the Commission should
not affirm its preliminary finding on the settlement interval proposal.
APPA and NRECA assert that Commission approval of any five-minute
settlement implementation process should require vetting and approval
by the RTOs'/ISOs' stakeholders.\24\ Direct Energy asserts that the
Commission should solicit further information from the RTOs/ISOs before
determining whether or not to direct settlement interval reforms.\25\
---------------------------------------------------------------------------
\24\ APPA and NRECA Comments at 4.
\25\ Direct Energy Comments at 6.
---------------------------------------------------------------------------
16. Based on analysis of the record, we adopt our preliminary
findings, and, as described in detail below, conclude that certain RTO/
ISO settlement practices are not just and reasonable and are unduly
discriminatory and preferential. Accordingly, we direct each RTO/ISO to
align its settlement and dispatch intervals by settling energy
transactions in its real-time markets at the same time interval it
dispatches energy, settling operating reserves transactions in its
real-time markets at the same time interval it prices operating
reserves, and settling intertie transactions in the same time interval
it schedules intertie transactions, as discussed further herein.
2. Settlement Interval Reform for Energy Transactions and Operating
Reserves
a. Proposal
i. Energy Transactions
17. In the NOPR, the Commission proposed to require that each RTO/
ISO settle energy transactions in its real-time markets at the same
time interval it dispatches energy. The Commission preliminarily found
the use of hourly integrated prices for real-time settlement may have
the unintended effect of distorting price signals, and, in certain
instances, contributing to market participants' failing to respond
appropriately to operating needs.\26\ Specifically, the Commission
stated that hourly integrated prices for real-time settlement may: (1)
Not accurately reflect the value a resource provides to the system; (2)
discourage resources from following dispatch instructions; and (3)
cause increased uplift payments. Therefore, the Commission
preliminarily found that the use of hourly integrated prices for real-
time settlement may result in rates that are unjust and unreasonable.
---------------------------------------------------------------------------
\26\ NOPR, FERC Stats. & Regs. ] 32,710 at PP 26-33.
---------------------------------------------------------------------------
18. To remedy any potentially unjust and unreasonable rates caused
by the use of hourly integrated prices for real-time settlement, the
Commission proposed in the NOPR to require that each RTO/ISO settle
energy transactions in its real-time markets at the same time interval
it dispatches energy.\27\
---------------------------------------------------------------------------
\27\ NOPR, FERC Stats. & Regs. ] 32,710 at P 34.
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19. The Commission explained that in the short-term, the settlement
interval proposal should improve incentives for resources to respond
quickly to dispatch instructions, which should in turn lead to
operators taking fewer out-of-market actions to ensure that supply
meets demand. The Commission noted that by improving resources'
response to dispatch instructions, the settlement interval proposal
would result in a more efficient use of generation resources to the
benefit of all consumers. In the long-term, the Commission maintained
that these reforms should provide more accurate price signals, which
should provide, together with other market price signals, the
appropriate incentives to build or maintain resources that can respond
to energy or operating reserve deficiencies.\28\
---------------------------------------------------------------------------
\28\ NOPR, FERC Stats. & Regs. ] 32,710 at P 35.
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20. In addition, the Commission noted, where settlement and
dispatch intervals are aligned, resources dispatched economically
during high-priced periods would receive those higher prices rather
than an hourly average of the dispatch interval LMPs, thereby reducing
the need to make uplift payments.
ii. Operating Reserves
21. The Commission proposed requiring that each RTO/ISO ``settle
operating reserves transactions in its real-time markets at the same
time interval it prices operating reserves.'' \29\ Although the
Commission noted that dispatch and pricing of energy and operating
reserves are closely linked through co-optimization in the real-time
market, it also noted that certain RTOs/ISOs acquire operating reserves
on a different time interval than they dispatch energy.\30\ The
Commission sought comment on whether the Commission should require
RTOs/ISOs to settle all real-time operating reserves transactions at
the same time interval as real-time energy dispatch and
[[Page 42886]]
settlement intervals, or whether a settlement interval that differs
from an RTO's/ISO's real-time energy dispatch interval would be
appropriate for some operating reserves transactions.\31\
---------------------------------------------------------------------------
\29\ NOPR, FERC Stats. & Regs. ] 32,710 at P 34.
\30\ NOPR, FERC Stats. & Regs. ] 32,710 at P 40.
\31\ NOPR, FERC Stats. & Regs. ] 32,710 at P 40.
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b. Current Practices in the RTOs/ISOs
i. Energy Transactions
22. The following table describes how each RTO/ISO currently
dispatches and settles real-time energy transactions:
Table 1--RTO/ISO Dispatch and Settlement Intervals for Energy
------------------------------------------------------------------------
Real-time
dispatch
\32\ Real-time settlement \33\
(minutes)
------------------------------------------------------------------------
CAISO 5 5 minute.
ISO-NE 5 hourly average.
MISO 5 hourly average.
NYISO 5 5 minute.
PJM 5 hourly average.
SPP 5 5 minute.
------------------------------------------------------------------------
ii. Operating Reserves
23. The RTOs/ISOs vary in how they settle and treat operating
reserves. For example, CAISO represents that it settles its operating
reserve transactions on fifteen-minute intervals and dispatches energy
on five-minute intervals.\34\ MISO states that it currently calculates
settlements for real-time operating reserves transactions at the same
interval that they are dispatched, i.e., five minutes, but that actual
settlements are on an hourly basis due to the specific calculations
MISO makes.
---------------------------------------------------------------------------
\32\ See CAISO, eTariff, 34.5 (17.0.0); ISO-NE., Transmission,
Markets and Services Tariff, Market Rule 1, III.2.3 (15.0.0); MISO,
FERC Electric Tariff, 40.2 (34.0.0); NYISO Markets and Services
Tariff, 4.4.2.1 (17.0.0); PJM OATT, Attachment K, Appendix, 2.3
(2.0.0); SPP, OATT, Sixth Revised Volume No. 1, Attachment AE, 6.2.2
(1.0.0).
\33\ See CAISO, eTariff, 11.5 (2.0.0), Appendix A, Settlement
Interval (2.0.0); ISO-NE., Transmission, Markets and Services
Tariff, Market Rule 1, III.2.2(b) (15.0.0); MISO, FERC Electric
Tariff, 40.3 (32.0.0), 40.3.1 (32.0.0), 40.3.3 (36.0.0); NYISO,
NYISO Tariffs, NYISO Markets and Services Tariff, 4.4.2.1, 4.4.2.8
(17.0.0); PJM, Intra-PJM Tariffs, OATT, Attachment K, Appendix,
2.5(e), (4.0.0), 3.2.1(e), (f) (28.0.0); SPP, OATT, Sixth Revised
Volume No. 1, Attachment AE, 8.6, 8.6.1 (2.1.0). The above tariff
citations refer to internal transactions. CAISO settles its intertie
interchange transactions on fifteen-minute intervals. See CAISO,
eTariff, HASP Block Intertie Schedule (0.0.0).
\34\ CAISO Comments at 8.
---------------------------------------------------------------------------
24. The PJM Market Monitor explains that the synchronized and
regulation reserves markets in PJM clear hourly but already incorporate
five-minute LMP data for calculating opportunity costs. The PJM Market
Monitor states that the offer price in PJM's synchronized reserve
market includes both the direct short-run marginal cost of providing
synchronized reserves, which does not vary every five minutes, and the
opportunity cost of providing synchronized reserves, which does vary
with five-minute LMPs. The PJM Market Monitor explains that PJM
currently updates the opportunity cost every five minutes using five-
minute LMP data for the Tier 2 synchronized reserve market and
recalculates the market clearing price every five minutes, with
settlement based on the average of the five-minute clearing price.\35\
---------------------------------------------------------------------------
\35\ PJM Market Monitor Comments at 8.
---------------------------------------------------------------------------
25. The PJM Market Monitor explains that, in PJM's regulation
market, the offer price includes both the direct short-run marginal
cost of providing regulation, which does not vary every five minutes,
and the opportunity cost of providing regulation, which varies with
five-minute LMPs. The PJM Market Monitor adds that PJM currently
updates the opportunity cost every five minutes using five-minute LMP
data for the regulation market and recalculates the clearing price
every five minutes, with settlement based on the average of five-minute
clearing prices. The PJM Market Monitor also notes that PJM purchases
other forms of operating reserves on a cost basis, including Tier 1
synchronized reserves, non-synchronized reserves, and day-ahead
scheduling reserves.\36\
---------------------------------------------------------------------------
\36\ PJM Market Monitor Comments at 8.
---------------------------------------------------------------------------
26. NYISO explains that it uses five-minute intervals to settle its
real-time markets for energy, regulation service, and operating
reserves.\37\ ISO-NE currently has hourly integrated settlement for its
real-time energy transactions and its real-time operating reserves.
However, ISO-NE states it intends to implement five-minute settlement
of real-time operating reserves in connection with implementing five-
minute settlement of real-time energy transactions, which is a current
discussion among ISO-NE stakeholders.\38\ SPP prices and settles
operating reserve products in its real-time market on a dispatch
interval, or five minute, basis.\39\
---------------------------------------------------------------------------
\37\ NYISO Comments at 2-3.
\38\ ISO-NE Comments at 2-3.
\39\ SPP Market Protocols, Sections 4.5.4 and 4.5.9.
---------------------------------------------------------------------------
c. Comments on the Proposed Settlement Interval Reform
27. Twenty-seven of the thirty commenters providing input on this
issue generally support the NOPR's proposed settlement interval
reform.\40\ As described below, many assert that the proposed reform
will align the price signals with system conditions and provide
accurate incentives for generation units to follow dispatch
instructions.\41\ Others point to additional benefits.
---------------------------------------------------------------------------
\40\ 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; ODEC
Comments at 3; 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.
\41\ Inertia Power and DC Energy Comments at 2; Potomac
Economics Comments at 1; Westar Comments at 1; PSEG Comments at 3.
---------------------------------------------------------------------------
i. Comments From the RTOs/ISOs
28. The ISO/RTO Council supports the Commission's goals of aligning
prices with resource dispatch instructions and operating needs and
specifically supports the settlement interval proposal for energy
transactions. The ISO/RTO Council states that the proposed settlement
interval reform will make resource compensation more transparent by
increasing the proportion of payments to resources through the price
paid for energy as opposed to uplift.\42\
---------------------------------------------------------------------------
\42\ ISO/RTO Council Comments at 2.
---------------------------------------------------------------------------
29. In separate comments, NYISO, ISO-NE., MISO, and PJM support the
settlement interval proposal for both energy and operating reserve
transactions. Likewise, in separate comments, CAISO supports the
settlement interval proposal for energy transactions, but does not
support requiring RTOs/ISOs to settle all real-time operating reserves
transactions at the same interval as real-time energy dispatch and
settlement intervals.
30. CAISO states that the settlement interval proposal would
improve market efficiency, and that accurate price signals provide
market participants with incentives to develop needed capabilities and
to offer those capabilities into the market.\43\ CAISO states that
where settlement and dispatch intervals are aligned, resources
dispatched economically during high-priced periods should receive high
prices, thus reducing the need to pay uplift caused by non-alignment of
settlement and dispatch intervals.\44\
---------------------------------------------------------------------------
\43\ CAISO Comments at 7.
\44\ CAISO Comments at 7.
---------------------------------------------------------------------------
31. However, CAISO does not support requiring RTOs/ISOs to settle
all real-time operating reserves transactions at the same interval as
real-time energy dispatch and settlement intervals.
[[Page 42887]]
Instead, CAISO asserts that it is appropriate to maintain its current
fifteen-minute procurement and settlement interval for operating
reserves transactions, which differs from the five-minute real-time
energy dispatch interval. CAISO explains that its current settlement
methodology aligns ancillary services commitment with internal
generation commitment and intertie transactions scheduling so that the
market accurately reflects the overall amount of supply resources
available to provide energy and ancillary services.\45\
---------------------------------------------------------------------------
\45\ CAISO Comments at 17-18.
---------------------------------------------------------------------------
32. NYISO supports the settlement interval proposal and asserts
that its use of five-minute intervals to settle its real-time markets
for energy, regulation service, and operating reserves, has provided
significant incentives for resources to follow dispatch instructions
and opportunities for supply resources to obtain full payment for their
performance based on actual system conditions.\46\
---------------------------------------------------------------------------
\46\ NYISO Comments at 2-3.
---------------------------------------------------------------------------
33. ISO-NE contends that settling on sub-hourly or five-minute
intervals would help to improve price signals and resource
compensation.\47\ ISO-NE states that five-minute settlements will help
improve price formation by ensuring that compensation for real-time
performance sends more accurate market signals of power system
conditions when energy is provided.\48\ ISO-NE supports the settlement
interval proposal for operating reserve transactions. It asserts that
settling all real-time operating reserves transactions at the same
interval as real-time energy dispatch and settlement intervals would
assist in aligning dispatch following incentives in markets that
simultaneously co-optimize energy and reserve dispatch in real-time.
ISO-NE states it intends to implement five-minute settlement of real-
time operating reserves in connection with implementing five-minute
settlement of real-time energy transactions, which is a current
discussion among ISO-NE stakeholders.\49\
---------------------------------------------------------------------------
\47\ ISO-NE Comments at 2.
\48\ ISO-NE Comments at 2.
\49\ ISO-NE Comments at 2-3.
---------------------------------------------------------------------------
34. MISO asserts that the inconsistency between dispatch and
settlements may produce financial outcomes that do not align with the
guiding principles of co-optimized (energy and ancillary services)
security constrained economic dispatch.\50\ If the Commission requires
five-minute settlements of operating reserves, MISO states that it
would modify its operating reserves settlements from its current hourly
method of settling operating reserves to align with real-time energy
transactions.\51\
---------------------------------------------------------------------------
\50\ MISO Comments at 2.
\51\ MISO Comments at 7-8.
---------------------------------------------------------------------------
35. PJM states that ancillary services, including operating
reserves, should settle on the same interval as energy because they are
co-optimized. PJM argues that not doing so could yield discrepancies
between the prices used to settle each product and could therefore undo
enhancements made since implementation of Order No. 719, reduce market
efficiencies, disrupt operations, and hinder proper price
formation.\52\ PJM states that it intends to change its market rules to
settle energy and ancillary services transactions in its real-time
energy market at the same interval on which it dispatches
resources.\53\
---------------------------------------------------------------------------
\52\ PJM Comments at 9.
\53\ PJM Comments at 2.
---------------------------------------------------------------------------
ii. Comments by Market Monitors
36. The PJM Market Monitor agrees that it would be appropriate to
implement five-minute pricing for the reasons stated in the NOPR, and
that implementing five-minute settlements will contribute significantly
to reducing uplift payments in PJM, an ongoing goal in the PJM
region.\54\ The PJM Market Monitor states that, while it is appropriate
to include the impact of five-minute LMP changes on the cost of
operating reserves in the form of synchronized reserves and regulation,
the PJM design for these markets currently incorporates those impacts.
The PJM Market Monitor asserts that no additional changes to PJM market
and non-market mechanisms for acquiring operating reserves are
currently necessary to incorporate changes in five-minute LMPs.\55\
---------------------------------------------------------------------------
\54\ PJM Market Monitor Comments at 2, 4.
\55\ PJM Market Monitor Comments at 8-9.
---------------------------------------------------------------------------
37. Potomac Economics, which serves as the market monitor for ISO-
NE., MISO, and NYISO, argues that hourly settlements encourage
resources not to follow dispatch instructions or to decrease their
flexibility by restricting dispatch ranges and offering slower ramp
rates, and states that MISO pays uplift to alleviate these issues.
Potomac Economics cites its 2014 MISO State of the Market Report to
show how five-minute settlements would change total payments to
resources compared to current hourly settlements. This analysis showed
that fossil-fueled resources in 2014 received settlements that were $35
million less than they would have received if the settlement were based
on five-minute prices and output, and that only one-fifth of this lost
value was paid via uplift. In contrast, Potomac Economics represents
that non-fossil resources were paid on net in hourly revenues slightly
above what they would have received with five-minute settlements.
Potomac Economics asserts that five-minute settlement provides greater
compensation to fossil resources, more accurately representing the
flexibility fossil resources provide to the system. In contrast,
Potomac Economics argues that hourly settlement overvalues wind
resources because such resources cannot ramp up in response to higher
prices, are negatively correlated with load and contribute to higher
congestion at higher output levels.\56\ Potomac Economics states that
the settlement interval proposal will provide incentives for better
resource performance, will improve price signals, and will improve
markets' short-run commitment and dispatch of existing resources.\57\
---------------------------------------------------------------------------
\56\ Potomac Economics Comments at 6.
\57\ Potomac Economics Comments at 1.
---------------------------------------------------------------------------
38. The SPP Market Monitor agrees with the Commission's preliminary
finding that aligning settlement and dispatch intervals would make
resource compensation more transparent by increasing the proportion of
resource payments made through energy and operating reserve payments
instead of uplift.\58\ The SPP Market Monitor states that aligning
dispatch and settlement intervals in neighboring markets would enhance
price signals at seams and enhance market efficiency.\59\
---------------------------------------------------------------------------
\58\ SPP Market Monitor Comments at 2.
\59\ SPP Market Monitor Comments at 2-3.
---------------------------------------------------------------------------
iii. Comments Supporting the Proposed Settlement Interval Reform
39. Many commenters expressly support the NOPR's settlement
interval proposal, citing many of the benefits that were outlined in
the NOPR.\60\ They generally argue that the settlement interval
proposal will provide incentives for generators to follow dispatch more
precisely, thus leading to
[[Page 42888]]
better resource performance, and improved reliability.\61\ They also
assert that the settlement interval proposal will properly compensate
resources for the service they provide and will more fully recognize
the value of flexible or fast-ramping resources.\62\ In addition, they
generally state that the settlement interval proposal will lead to
fewer out-of-market payments, will increase transparency, and will
support more efficient market outcomes.\63\
---------------------------------------------------------------------------
\60\ 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; AEMA Comments at 2; XO Energy Comments at 1;
PJM Market Monitor at 2; ODEC at 3.
\61\ Inertia Power and DC Energy Comments at 2; Westar Comments
at 1, 3; EEI Comments at 6-7; Exelon Comments at 4-5.
\62\ Public Interest Organizations Comments at 2-3; ELCON
Comments at 2-3; EDP Renewables Comments at 2-3; ESA Comments at 3;
NEI Comments at 14.
\63\ See supra note 60; ELCON Comments at 3; Exelon Comments at
4-5.
---------------------------------------------------------------------------
40. More specifically, Exelon asserts that the settlement interval
proposal will support ongoing market improvements, such as ISO-NE's
performance incentive mechanism, effective in June 2018, that will pay
resources bonuses or impose penalties based on performance during
operating reserve shortages that last five minutes or longer. Exelon
argues that ISO-NE's market must settle at five-minute intervals to
implement this mechanism completely.\64\
---------------------------------------------------------------------------
\64\ Exelon Comments at 5.
---------------------------------------------------------------------------
41. According to EDP Renewables, greater participation of fast
ramping renewable resources will also enhance resource adequacy,
produce cost savings for consumers, and improve grid resilience.\65\
---------------------------------------------------------------------------
\65\ EDP Renewables Comments at 3.
---------------------------------------------------------------------------
42. Some commenters also argue that the settlement interval
proposal will reduce market inefficiencies and lead to greater
investment. PSEG asserts that the proposed reforms correct market flaws
that have caused inefficiencies in both price signals and resource
dispatch decisions.\66\ ELCON states that the proposed settlement
reform addresses an embedded inconsistency in market operation that
promotes gaming and other forms of ill behavior or inefficiencies.\67\
EDP Renewables argues that the proposed reforms will also yield
savings, remove opportunities for market manipulation, and encourage
investment in new services and new technologies, all of which will
result in a more robust and resilient grid and help both consumers and
suppliers through more efficient market operation.\68\
---------------------------------------------------------------------------
\66\ PSEG Comments at 3.
\67\ Public Interest Organizations Comments at 2-3; ELCON
Comments at 2-3.
\68\ EDP Renewables Comments at 2.
---------------------------------------------------------------------------
43. EPSA argues that implementing sub-hourly settlement intervals
is needed to obtain the full benefits of other price formation reforms
to improve the accuracy with which real-time prices communicate the
time-dependent and location-dependent value of incremental energy and
ancillary services.\69\
---------------------------------------------------------------------------
\69\ EPSA Comments at 6-7, Pope Aff. at 4-5.
---------------------------------------------------------------------------
44. TAPS does not oppose the settlement interval proposal, as long
as it does not impose an undue burden on load serving entities.\70\
---------------------------------------------------------------------------
\70\ TAPS Comments at 4.
---------------------------------------------------------------------------
45. EPSA supports the settlement interval proposal for operating
reserves. It argues that real-time operating reserves should be co-
optimized in the dispatch and settled with energy for every hourly sub-
interval (generally five minutes) to ensure that resources are
compensated for following RTO/ISO instructions and are indifferent to
providing either energy or operating reserves during periods of high
energy or operating reserves prices.\71\ EPSA emphasizes the importance
of sending sub-hourly price signals to ensure that operating reserves
are available in sub-hourly intervals due to their contribution to
maintaining reliability, further stating that sub-hourly settlements
for operating reserves send information to the market relating to the
potential profitability of incremental investments to enhance the sub-
hourly availability of such reserves.\72\ EPSA argues that to ensure
accurate prices for both energy and operating reserves, RTOs/ISOs
should be required to co-optimize these products in real-time because
suppliers should be indifferent to providing incremental energy and
operating reserves in each sub-hourly interval to allow the RTO/ISO to
perform a reliable least-cost dispatch.\73\
---------------------------------------------------------------------------
\71\ EPSA Comments, Pope Aff. at 11.
\72\ EPSA Comments, Pope Aff. at 11.
\73\ EPSA Comments, Pope Aff. at 12-13.
---------------------------------------------------------------------------
46. Dominion supports the settlement interval proposal for
operating reserves. However, Dominion argues that only specific reserve
products should settle at the same interval that they are priced and
that other types of settlement provisions, such as make-whole payments,
should not.\74\ Dominion explains that, in PJM, for example,
``balancing Operating Reserves'' includes the costs to dispatch
resources out-of-merit for reliability or to cover deficiencies in the
day-ahead market solution.\75\ According to Dominion, these resources
do not provide a specific reserve product; rather, these resources are
made whole when they are dispatched to address a mismatch between day-
ahead commitment and real-time requirements. Dominion therefore
requests that the Commission not require the settlement intervals for
these types of operating reserve to change.\76\
---------------------------------------------------------------------------
\74\ Dominion Comments at 3.
\75\ Dominion Comments at 3.
\76\ Dominion Comments at 3.
---------------------------------------------------------------------------
47. PSEG supports applying the proposed settlement intervals to
both real-time energy transactions and real-time operating reserves.
PSEG explains that given the linkage between energy transactions and
reserve services, settling those products on different intervals would
introduce dislocations, and incent resource actions that could disrupt
these co-optimization objectives, essentially undermining the
Commission's objectives in the NOPR.\77\
---------------------------------------------------------------------------
\77\ PSEG Comments at 4-5.
---------------------------------------------------------------------------
48. The New Jersey Board concurs with the PJM Market Monitor that
no changes should be made in PJM's synchronized reserve and regulation
markets given that the opportunity cost component in these ancillary
services markets, which is the only cost component subject to five-
minute changes in LMP, already accounts for the five-minute interval
changes.\78\ Duke acknowledges potential benefits from aligning
operating reserve transactions with their respective settlement
intervals but argues that stakeholders should consider whether
operating reserves transactions should be aligned with settlement
intervals for energy given the costs of doing so.\79\ Although it takes
no position on the operating reserves proposal, EEI states that
additional clarity from the Commission on the definition of operating
reserve transactions would be helpful, given the varied definitions of
reserve products among regions. EEI states that such regional variation
warrants further consideration.\80\
---------------------------------------------------------------------------
\78\ New Jersey Board Comments at 4.
\79\ Duke Comments at 5.
\80\ EEI Comments at 9-10 & n.16.
---------------------------------------------------------------------------
iv. Comments Opposed to the Proposed Settlement Interval Reform
49. Several commenters oppose the settlement interval proposal.
Direct Energy states that the Commission should solicit information
from RTOs/ISOs to determine whether existing generation resources are
able to respond effectively to five-minute price signals before
determining whether any settlement interval reform is warranted.\81\
Direct Energy doubts the ability of longer lead-time resources to
respond to five-minute price signals
[[Page 42889]]
during periods of extreme price volatility, and surmises that look-
ahead unit commitment and dispatch software results could exacerbate
swings in generation and load balance. Direct Energy states that a
high-priced dispatch interval could encourage dispatch of peaking
generation, which would take several minutes with longer ramp times and
cause other resources to ramp up more quickly. Direct Energy argues
that this could lead to an oversupply and to depressed prices, thus
making the longer-ramping resources responding to the original signal
uneconomic by running below their costs and incurring uplift--the
opposite of the goal of the settlement interval proposal.\82\
---------------------------------------------------------------------------
\81\ Direct Energy Comments at 6.
\82\ Direct Energy Comments at 3-5.
---------------------------------------------------------------------------
50. Duke, APPA and NRECA, and Concerned Cooperatives argue that the
Commission should refrain from requiring a one-size-fits-all
approach.\83\ Duke, APPA and NRECA, and Concerned Cooperatives contend
that RTO/ISO stakeholder processes should vet this issue and consider
issues such as the costs, benefits, types of changes needed to
implement this reform, price formation issues more generally, and
unintended consequences.\84\ Duke states that this approach would
notify the Commission with regard to possible solutions, cost of
implementation, and the timeframe in which the RTO/ISO could reasonably
address each issue.\85\ Additionally, Concerned Cooperatives disagree
with the Commission's conclusion that reforming the settlement
intervals will result in more efficient use of generating resources.
---------------------------------------------------------------------------
\83\ Duke Comments at 2-3; APPA and NRECA Comments at 4-5;
Concerned Cooperatives Comments at 4-5.
\84\ Duke Comments at 4; APPA and NRECA Comments at 3; Concerned
Cooperatives Comments at 1.
\85\ Duke Comments at 4-5.
---------------------------------------------------------------------------
51. Concerned Cooperatives argue that the benefits of moving to
five-minute settlements will not offset the cost. They state that the
Potomac Economics report cited in the NOPR shows that switching to
matching intervals would force MISO market participants to expend
millions of dollars on upgrades and operation and maintenance (O&M)
costs, without realizing lower rates. Instead, those participants would
face an annual increase of approximately $28 million, after netting the
estimated $6.6 million system benefit from the increased payments to
generators of about $35 million dollars.\86\
---------------------------------------------------------------------------
\86\ Concerned Cooperatives Comments at 10 (citing Potomac
Economics, 2014 State of the Market Report for the MISO Electricity
Markets, at 43-44, Figure 19 (2015)).
---------------------------------------------------------------------------
52. Concerned Cooperatives further argue that the Commission relies
solely upon a letter filed in Docket No. AD14-14-000 \87\ to support
its finding with no analysis as to whether the observed increase in
capacity factors for internal combustion engines in SPP was the result
of SPP's adoption of five-minute settlement intervals or other
factors.\88\ Concerned Cooperatives argue that, even if there was some
marginal benefit to the settlement interval proposal, many market
participants would not benefit from the reform even though they would
be responsible for funding it.\89\ Concerned Cooperatives represent
that 90 to 95 percent of their transactions take place in the day-ahead
market, which settles on an hourly basis, and that adopting five-minute
settlement intervals in the real-time market does not help Concerned
Cooperatives hedge prices.\90\ Concerned Cooperatives also state that
the National Renewable Energy Laboratory study cited in the NOPR in
support of adopting five-minute settlement intervals also recognizes
that limiting market complexity may be a reason to maintain hourly
settlements, and that RTOs/ISOs already have tools to encourage
resources to follow efficient schedules, such as uninstructed deviation
penalties and ex post pricing rules. Concerned Cooperatives recommend
that the Commission instead identify objectives and allow RTOs/ISOs to
pursue options for achieving those objectives.\91\
---------------------------------------------------------------------------
\87\ Concerned Cooperatives Comments at 11 (citing Comments of
W[auml]rtsil[auml] North America, Inc., Docket No. AD14-14-000, at
1-2 (Mar. 6, 2015)).
\88\ Concerned Cooperatives Comments at 11.
\89\ Concerned Cooperatives Comments at 11.
\90\ Concerned Cooperatives Comments at 11.
\91\ Concerned Cooperatives Comments at 12.
---------------------------------------------------------------------------
d. Commission Determination
i. Energy Transactions
53. We adopt the NOPR proposal to require that each RTO/ISO settle
energy transactions in its real-time markets at the same time interval
it dispatches energy, as discussed below.\92\ We find that the
settlement interval requirement for energy transactions will meet the
Commission's price formation goals by more accurately reflecting the
value of the service a resource provides to the system, which, in so
doing, helps to ensure that rates are just and reasonable and not
unduly discriminatory or preferential.
---------------------------------------------------------------------------
\92\ NOPR, FERC Stats. & Regs. ] 32,710 at P 34.
---------------------------------------------------------------------------
54. As discussed below, providing the correct incentives for market
participants to follow commitment and dispatch instructions, make
efficient investments in facilities and equipment, maintain
reliability, and increase transparency is fundamental to proper
formation of energy prices, helping to ensure just and reasonable
rates, terms and conditions of service.
55. One important element of ensuring reliable grid operations is
resources following dispatch instructions. The requirement that each
RTO/ISO settle energy transactions at the same interval it dispatches
energy sends accurate market signals of power system conditions, thus
encouraging resources to follow commitment and dispatch instructions, a
point noted by ISO-NE.\93\
---------------------------------------------------------------------------
\93\ ISO-NE Comments at 2.
---------------------------------------------------------------------------
56. The settlement interval requirement for energy transactions
also provides an incentive to make efficient investments in facilities
and equipment.\94\ In the long-term, we expect that appropriate
compensation would help to encourage efficient investments in
facilities and equipment, enabling reliable service. We also find that
the settlement interval requirement will provide incentives to more
flexible resources, thus leading to more efficient markets, as noted by
several commenters.\95\ More flexible resources will help system
operators address transient system conditions. We find that greater
participation of these more flexible resources should generally enhance
resource adequacy because it allows the participation of diverse
resources and improves reliability, as noted by EDP Renewables.\96\
---------------------------------------------------------------------------
\94\ EPSA Comments, Pope Aff. at 4.
\95\ Public Interest Organizations Comments at 2-3; ELCON
Comments at 2-3; EDP Renewables Comments at 2-3; ESA Comments at 3;
NEI Comments at 14.
\96\ EDP Renewables Comments at 2-3.
---------------------------------------------------------------------------
57. The settlement interval requirement for energy transactions
should help in maintaining reliability because resources will have a
greater incentive to follow dispatch instructions, as noted by
Exelon.\97\ In addition, these reforms will provide resource owners
with a greater incentive to adequately maintain their equipment,
conduct maintenance during non-peak periods, and invest in new and
upgraded equipment. As noted by CAISO, linking prices with compensation
will pay resources for providing needed flexibility to the market
operator and would motivate these resources to improve their
operational performance.\98\
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\97\ Exelon Comments at 4-5.
\98\ CAISO Comments at 7.
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58. The settlement interval requirement for energy transactions
also results in more accurate market prices, reducing the need for out-
of-market operator actions. Under an hourly
[[Page 42890]]
settlement system, resources do not have the same incentive to follow
five-minute prices since compensation is based on an hourly average.
Therefore, system operators are more likely to take out-of-market
actions in real-time, such as increasing the use of regulating reserves
or committing additional resources, to ensure that adequate resources
are available to meet system needs. Such actions may result in uplift.
By providing incentives to follow dispatch instructions, the settlement
interval requirement should reduce such operator actions and, thereby,
reduce uplift.\99\ When this occurs, energy prices are based on more
observable market fundamentals--such as the marginal cost of serving
load and the operational constraints of reliably operating the system--
and not on less observable operator action.\100\ As a result of a
reduction in out-of-market uplift payments, resources will perceive
stronger financial incentives to perform, especially during stressed
system conditions, when the performance of all resources is paramount.
Further, we note, this increased transparency, in turn, better informs
decisions to build or maintain resources.
---------------------------------------------------------------------------
\99\ Reducing out-of-market uplift payments can be beneficial to
RTOs'/ISOs' market participants because, among other reasons,
charges to market participants for uplift are often volatile. As a
result, market participants may build risk premiums into their
resource bids in the real-time energy market to shield them from the
uncertainty associated with unexpected uplift charges. See Staff
Analysis of Uplift in RTO and ISO Markets, Docket No. AD14-14-000,
at 18 (Aug. 2014), http://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf. In addition, making system conditions and
compensation more transparent through market prices will make that
price apparent to all available resources and thus encourage them to
fully participate in the market, which is likely to reduce
generation costs incurred by load.
\100\ In addition to greater transparency, reducing uplift is a
goal generally. For example, ``[t]he implementation of five minute
settlements would contribute significantly to the reduction of
uplift payments, which is an ongoing goal of PJM, of the Market
Monitor and of PJM members.'' PJM Market Monitor Comments at 4.
---------------------------------------------------------------------------
59. Taken together, the benefits we expect as a result of this
settlement reform will ensure that rates are just and reasonable and
not unduly discriminatory or preferential.
60. We are not persuaded by the arguments opposing the settlement
interval proposal. Underlying much of the opposition is the assumption
that many resources cannot take advantage of five-minute settlement
intervals because they are not flexible enough to respond to five-
minute dispatch. For example, Direct Energy argues that RTOs/ISOs
should report the types of resources able to effectively modify their
output to respond to five-minute price signals.\101\ The concern Direct
Energy identifies is, in fact, one of the objectives of this reform.
Specifically, resources that are not able to respond quickly enough to
address acute system needs should not receive the same level of
compensation as those resources that are able to flexibly respond.\102\
Further, we note that all RTOs/ISOs have a combination of resources,
some of which can respond within five minutes and some that cannot, and
that knowing the exact percentages of resources available to respond to
prices is not determinative of whether the reforms adopted here will
prove beneficial. Instead, we believe it is important to ensure
settlement practices do not distort existing five-minute pricing
signals.
---------------------------------------------------------------------------
\101\ Direct Energy Comments at 6.
\102\ This rule does not require resources to be dispatched more
quickly than they are now, but it does increase the incentive for
those resources that can and do respond quickly.
---------------------------------------------------------------------------
61. We are not persuaded by Concerned Cooperatives' argument that
the settlement interval proposal should be rejected because market
participants, such as Concerned Cooperatives, funding the reform do not
have a large fraction of their positions in the real-time market and
therefore will not benefit significantly from it.\103\ We find that
aligning prices and settlement intervals will enhance the operation of
markets by ensuring resources respond to actual system condition
regardless of the percentage of resources that clear in the day-ahead
market.
---------------------------------------------------------------------------
\103\ Concerned Cooperatives Comments at 11.
---------------------------------------------------------------------------
62. We also disagree with Concerned Cooperatives' statement that
the Commission relied upon a single document to support its finding
without additional analysis.\104\ Commenters supporting the reform have
provided sound economic analysis and examples demonstrating the value
of the proposed settlement reform.\105\ Though Concerned Cooperatives
state that many market participants would not benefit from the reform
even though they would be responsible for funding it,\106\ we believe
that many market participants are likely to benefit from the reform
through improved economic incentives to respond to system needs.
Potomac Economics' analysis of fossil-fueled and non-fossil-fueled
resources \107\ demonstrates that settlement reform will incentivize
generator flexibility, improve generators' dispatch performance, and
increase investments in more flexible resources.
---------------------------------------------------------------------------
\104\ Concerned Cooperatives Comments at 11.
\105\ EPSA Comments, Pope Aff. at 2-14; Potomac Economics
Comments at 3-7; See also supra note 60.
\106\ Concerned Cooperatives Comments at 11.
\107\ Potomac Economics Comments at 5-6.
---------------------------------------------------------------------------
63. Concerned Cooperatives express concern that adopting five-
minute settlement intervals could result in errors and disputes that
could lead to resettlement and uncertainty for the market.\108\ All
RTOs/ISOs currently compute five-minute LMPs. Therefore, there is no
new data being generated or calculated that would lead to additional
need for resettlement or increased uncertainty. Concerned Cooperatives
have cited neither examples of more errors and disputes on RTO/ISO
systems currently using five-minute settlement intervals, nor examples
of additional resettlement and uncertainty for the market. Also, we
find that, while administratively-determined uninstructed deviation
penalties (which Concerned Cooperatives suggest could be used in lieu
of settlement reform) are appropriate in certain contexts, settlements
based on the actual value of energy corresponding with its production
or transaction in each five-minute interval provide more accurate
incentives for resources to respond to price signals.
---------------------------------------------------------------------------
\108\ Concerned Cooperatives Comments at 12.
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64. Concerned Cooperatives also assert that the objective of
incenting market participants to follow dispatch instructions or invest
in upgrades must be considered in the context of existing market rules
that already may provide incentives for investment in faster ramping
capability.\109\ To the extent an RTO/ISO has a functional mechanism to
encourage the installation of fast-ramping resources, this Final Rule
will augment the existing RTO/ISO mechanisms.
---------------------------------------------------------------------------
\109\ Concerned Cooperatives Comments at 6.
---------------------------------------------------------------------------
65. Contrary to Concerned Cooperatives' argument, we are not
persuaded to abandon the settlement interval proposal because a Potomac
Economics report indicates that it would have resulted in an additional
$28 million in increased energy costs on the MISO system in 2014.\110\
First, we recognize that that there could be higher revenues to
generators, but we believe that this is the correct reflection of value
provided in these circumstances and would send an improved signal for
long-term investment and short-term performance, to the overall benefit
of the market. Second, it is important to note that the Potomac
Economics report indicates that for many settlement intervals during
2014, MISO resources were paid an hourly settlement rate lower than
what five-minute settlements would justify. Thus, the Potomac
[[Page 42891]]
Economics report should be viewed as indicating a need to correct
settlement practices, rather than indicating a windfall to resources.
Third, it is not clear that the proposal will result in generally
increased energy payments to generators. For example, an ISO-NE study
for the year 2013 found that the net increase in real-time energy
credits on its system (once the decrease in real-time reserve credits
was considered) would have been only $600,000.\111\ Finally, due to the
increased efficiencies resulting from improving incentives to respond
to market price signals, total costs to electric wholesale customers
over time are likely to decrease.
---------------------------------------------------------------------------
\110\ Concerned Cooperatives Comments at 10.
\111\ ISO-NE., Subhourly Real-Time Market Settlements, A11 ISO
Presentation 05-07-14 Revision 1, Matt Brewster, at 11 (May 8,
2014), http://www.iso-ne.com/committees/key-projects/subhourly-real-time-settlement.
---------------------------------------------------------------------------
66. Additionally, some commenters argue that other types of
settlement provisions, such as make-whole payments, should not be
subject to settlement interval reform. We would like to clarify that
the Final Rule does not apply to make-whole payments for units
dispatched out-of-merit.
67. We disagree with the recommendation of some commenters that the
decision to modify settlement intervals should be subject to a
stakeholder process.\112\ RTOs/ISOs implementing this Final Rule are
free to use a stakeholder process within the implementation timelines
specified herein, but we see no need to further delay this reform. This
does not limit stakeholders' input as RTOs/ISOs form their compliance
filings in response to this aspect of the Final Rule.
---------------------------------------------------------------------------
\112\ APPA and NRECA Comments at 4.
---------------------------------------------------------------------------
68. We conclude that the settlement interval requirement for energy
transactions should ensure that hourly settlement practices do not
distort five-minute price signals in RTOs/ISOs. Instead, the
compensation provided to resources must reflect the value of a resource
providing given services to ensure appropriate economic incentives to
meet system needs.
ii. Operating Reserves
69. We adopt the proposal in the NOPR that RTOs/ISOs settle real-
time operating reserves transactions at the same time interval that
they price operating reserves. This requirement for operating reserves
will accomplish the Commission's price formation goals and thereby
ensure just and reasonable rates, and will further preserve the co-
optimization of operating reserves with energy. Under the settlement
interval requirement for operating reserves, to the extent that an RTO/
ISO prices operating reserves transactions at a different time interval
than it prices internal real-time energy transactions, that RTO/ISO
need only settle operating reserves transactions at the same time
interval that they are priced. Thus, we will not require an RTO/ISO to
settle operating reserves transactions on the same time interval as it
settles energy transactions. This will preserve the existing energy and
operating reserves co-optimization methodologies of the various RTOs/
ISOs.
70. The settlement interval requirement increases transparency and
provides the correct incentives to maintain reliability. It also meets
the Commission's other price formation goals of encouraging resources
to follow the RTO's/ISO's commitment and dispatch instructions and to
make efficient investments. The reform to the settlement interval for
operating reserves will increase reliability because resource owners
will have a greater incentive to adequately maintain their equipment,
conduct maintenance during non-peak periods, and invest in new and
upgraded equipment. Similar to energy settlement intervals, requiring
settlement intervals of operating reserves transactions to match the
intervals upon which those reserves are priced will reduce the need for
payments made through uplift, make resource compensation more
transparent and help ensure that there are adequate operating reserves
to maintain reliability. Finally, co-optimized energy and reserve
prices are designed so that a resource is indifferent between providing
energy or operating reserves. Ensuring that energy and operating
reserve settlements are done on the same basis will preserve this
indifference and create an incentive for a resource to provide the
service the RTO/ISO has instructed it to provide. The reform to
operating reserve settlements will, by achieving the Commission's price
formation goals and preserving the co-optimization of energy and
operating reserves, ensure that rates are just and reasonable.
71. While, as discussed above, some commenters also support RTOs/
ISOs settling all real-time operating reserves transactions at the same
time interval that they dispatch real-time energy,\113\ we are not
requiring that these settlement intervals align. CAISO, in defending
its current practices, states that it procures operating reserves and
settles them on a fifteen-minute basis and distinguishes this type of
ancillary service from five-minute real-time energy dispatch.\114\
However, CAISO, along with all of the other RTOs/ISOs, supports the
requirement that they settle operating reserves transactions at the
same time interval that they price these transactions, which
accommodates both RTOs/ISOs that currently settle co-optimized reserve
transactions on a five-minute basis and those that currently settle
these transactions on a fifteen-minute basis. Accordingly, we clarify
that CAISO's understanding in this regard is consistent with how
operating reserves and energy on its system are ``priced,'' as
contemplated by the wording of the settlement interval regulations
adopted by this Final Rule.
---------------------------------------------------------------------------
\113\ PSEG Comments at 4-5; EPSA Comments, Pope Aff. at 11-13.
\114\ CAISO Comments at 17-18.
---------------------------------------------------------------------------
72. NYISO states that, although it uses sub-hourly settlements in
its real-time market, in certain cases, the Commission has approved
NYISO performing settlements on an hourly basis, and NYISO argues it
should not be required to bring those settlements into alignment with
its normal dispatch intervals.\115\ NYISO cites limited energy storage
resources as an example of services that currently settle hourly and
yet follow dispatch instructions and provide resource response in real-
time. To the extent NYISO or other RTOs/ISOs seek to argue on
compliance that their existing market rules are consistent with or
superior to the Final Rule reforms adopted herein, the Commission will
entertain those at that time.\116\
---------------------------------------------------------------------------
\115\ NYISO Comments at 3-4.
\116\ See, e.g., Demand Response Compensation in Organized
Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ]
31,322, at P 4 & n.7, order on reh'g and clarification, Order No.
745-A, 137 FERC ] 61,215 (2011), reh'g denied, Order No. 745-B, 138
FERC ] 61,148 (2012), vacated sub nom. Elec. Power Supply Ass'n v.
FERC, 753 F.3d 216 (D.C. Cir. 2014), rev'd & remanded sub nom. FERC
v. Elec. Power Supply Ass'n, 136 S. Ct. 760 (2016).
---------------------------------------------------------------------------
73. Although generally supporting the settlement interval
requirement for operating reserves, some commenters question whether
such a requirement should apply to all reserve products or assert that
regional variations should be considered.\117\ We appreciate that
regional variations may exist among the many different reserve products
in the RTOs/ISOs and we clarify that all operating reserve products
that have a market-based price are subject to the settlement interval
reform.
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\117\ See, e.g., Dominion Comments at 3; EEI Comments at 10.
---------------------------------------------------------------------------
3. Interties
a. Commission Request for Comments
74. The Commission sought comment on whether the proposed reforms
are appropriate for intertie transactions scheduled on intervals
different from
[[Page 42892]]
the intervals on which RTOs/ISOs dispatch internal real-time
energy.\118\
---------------------------------------------------------------------------
\118\ NOPR, FERC Stats. & Regs. ] 32,710 at P 39.
---------------------------------------------------------------------------
i. Comments by RTOs/ISOs
75. The ISO/RTO Council asserts that aligning dispatch and pricing
should also apply to intertie transactions, adding that this would
prevent price discrepancies and may reduce uplift.\119\
---------------------------------------------------------------------------
\119\ ISO/RTO Council Comments at 2.
---------------------------------------------------------------------------
76. PJM asserts that intertie transactions should be included in
the scope of the Final Rule, noting that it plans to settle intertie
transactions on a five-minute basis, consistent with its proposal for
its real-time energy market. PJM suggests that, where a transaction is
curtailed or the MW quantity is reduced during a fifteen-minute
interval due to a reliability directive, each five-minute interval in
the transaction should settle on the integrated transaction MW quantity
that flowed during the five-minute interval.\120\
---------------------------------------------------------------------------
\120\ PJM Comments at 8.
---------------------------------------------------------------------------
77. ISO-NE argues that external interties should settle no less
often than the intervals for which they are scheduled. ISO-NE
represents that its proposals to implement sub-hourly settlements would
fully meet this objective at all its external interfaces.\121\ NYISO
argues that intertie and internal transactions should have the same
settlement interval because this alignment will promote competition,
identify the most economic supply option, provide equal incentives to
respond to the same operating conditions, and improve the efficiency of
interregional transactions.\122\
---------------------------------------------------------------------------
\121\ ISO-NE Comments at 2.
\122\ NYISO Comments at 5.
---------------------------------------------------------------------------
78. CAISO notes that it already schedules and settles intertie
transactions and internal resources on a fifteen-minute basis.\123\
However, CAISO also provides three options for scheduling imports and
exports on an hourly basis: (1) Economic-bid hourly block; (2)
economic-bid hourly block with a single intra-hour schedule change that
will be dispatched to zero within the hour if a fifteen-minute price is
less than an import's bid price or greater than an export's bid price;
and (3) self-scheduled hourly.\124\ CAISO requests that the Commission
state that CAISO's current market design with granular dispatch and
settlement of its real-time energy market is consistent with the
settlement interval proposal.\125\
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\123\ CAISO Comments at 12.
\124\ CAISO Comments at 9.
\125\ CAISO Comments at 10.
---------------------------------------------------------------------------
79. CAISO asserts that a blanket requirement that hourly intertie
schedules revert to hourly pricing, as was previously the case under
its prior market design, would result in the same adverse market
outcomes it resolved through its fifteen-minute market
enhancement.\126\ CAISO requests that the Commission clarify that the
availability of hourly block intertie bidding options would not violate
the settlement interval proposal because its current market design
ensures all internal and external transactions are cleared and settled
based on fifteen-minute market intervals that optimize all transactions
in its markets.\127\
---------------------------------------------------------------------------
\126\ CAISO Comments at 14.
\127\ CAISO Comments at 15.
---------------------------------------------------------------------------
ii. Comments by Market Monitors
80. The PJM Market Monitor asserts that intertie transactions in
PJM cannot be measured accurately enough to support five-minute
settlements, noting that accurate measurement is difficult because of
differences between actual and scheduled flows. The PJM Market Monitor
thus recommends that settlements be based on the same fifteen-minute
interval used for external scheduling intervals. The PJM Market Monitor
asserts that this approach would more accurately reflect LMP during the
actual time period of the transaction and would make the period and
settlement of the transaction consistent.\128\
---------------------------------------------------------------------------
\128\ PJM Market Monitor Comments at 7.
---------------------------------------------------------------------------
81. The PJM Market Monitor states that alternative settlement
approaches include using the integrated price over the same fifteen-
minute interval used in scheduling and using five-minute interval
settlements.\129\
---------------------------------------------------------------------------
\129\ The PJM Market Monitor in its comments provides examples
of these alternatives. PJM Market Monitor Comments at 5-7.
---------------------------------------------------------------------------
iii. Comments in Support of Applying Settlement Reform to Interties
82. The New Jersey Board, EEI, EPSA, Dominion, and EDP Renewables
concur with the PJM Market Monitor that intertie settlements should be
at fifteen-minute intervals, the same interval as external
scheduling.\130\
---------------------------------------------------------------------------
\130\ New Jersey Board Comments at 3-4; EEI Comments at 9; EPSA
Comments, Pope Aff. at 9; Dominion Comments at 4; EDP Renewables
Comments at 5.
---------------------------------------------------------------------------
83. Golden Spread states that alignment between dispatch and
settlement intervals is generally desirable for the reasons listed in
the NOPR, and notes that it believes SPP already aligns dispatch and
settlement intervals for intertie transactions on a five-minute
basis.\131\
---------------------------------------------------------------------------
\131\ Golden Spread Initial Comments at 2.
---------------------------------------------------------------------------
84. ANGA, PSEG, and the Financial Marketers Coalition assert that
the logic underlying the proposed settlement reform as applied to
internal transactions should apply equally to intertie transactions,
and ANGA recommends that the Commission consider evolving these
interfaces to five-minute dispatch and settlement, perhaps over the
next three to five years.\132\
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\132\ ANGA Comments at 3-4; Financial Marketers Coalition
Comments at 3-4; PSEG Comments at 5.
---------------------------------------------------------------------------
85. Although it generally agrees that the settlement interval
proposal should apply equally to internal and intertie transactions,
Financial Marketers Coalition states that, in CAISO, clearing some
transactions (such as load and generation) on a five-minute price and
others (such as internal and intertie convergence bids) on a fifteen-
minute price has yielded price divergence instead of convergence.
iv. Comments Opposed To Applying Settlement Reform to Interties
86. Inertia Power and DC Energy argue that intertie economic
dispatch intervals cannot easily be aligned with internal real-time
energy dispatch but emphasize the importance of maintaining the highest
possible consistency across the seams to ensure a more efficient,
resilient, and reliable electrical system.\133\
---------------------------------------------------------------------------
\133\ Inertia Power and DC Energy Comments at 4-5.
---------------------------------------------------------------------------
87. Duke states that the issue of whether to apply the settlement
interval proposal to intertie transactions should be discussed in the
RTO/ISO stakeholder processes and that they should be treated
comparably to reforms to internal transactions.\134\
---------------------------------------------------------------------------
\134\ Duke Comments at 5.
---------------------------------------------------------------------------
b. Commission Determination
88. Based upon the comments received on this issue, we modify the
regulatory text proposed in the NOPR to require each RTO/ISO to settle
intertie transactions in the same time interval that it schedules
intertie transactions. The settlement interval requirement for intertie
transactions will facilitate the coordination of the scheduling and
settlement of intertie transactions, and will discourage inefficient
practices such as the chasing of inaccurate intertie prices. For
example, if there are very high prices in the first fifteen minutes of
an hour, resources will know that for that entire operating hour, there
will be a high integrated hourly price. This provides an incentive for
resources to increase the volume of intertie transactions for the
remainder of the hour, even if the price for the subsequent fifteen-
minute interval is much lower reflecting that it may no
[[Page 42893]]
longer be efficient to schedule such intertie transactions. Most
commenters, as described above, agree that such a requirement will aid
in the achievement of these goals.
89. However, a difference of opinion exists between PJM and the PJM
Market Monitor. PJM supports moving to a five-minute settlement
interval for intertie transactions while the PJM Market Monitor
supports aligning the settlement interval for intertie transactions
with the fifteen-minute scheduling interval for these transactions.
90. If an RTO/ISO settles or proposes to settle intertie
transactions using a shorter time interval than by which it schedules
such transactions, the RTO/ISO may propose to do so in its compliance
filing and demonstrate that such a proposal is consistent with or
superior to the Commission's intertie reforms. The compliance filing
proceeding will provide a forum in which to consider alternative
practices and resolve disputes that may arise within regions, as well
as provide for the development of a more complete record on these
issues.
91. We decline to clarify for CAISO that the availability of hourly
block intertie bidding options would not violate the settlement
interval requirement for interties. Such a determination is more
appropriately made upon reviewing CAISO's compliance filing and CAISO
should justify its proposed treatment for intertie transactions there.
4. Demand Response Resources
a. Comments
92. Several commenters discuss the application of the settlement
interval proposal to demand response resources even though the
Commission did not specifically solicit those comments and did not make
a separate proposal concerning demand response resources apart from
other resources considered in the NOPR.
93. The PJM Market Monitor, with the New Jersey Board concurring,
recommends that five-minute pricing in energy markets explicitly cover
all resources providing energy, including demand side and storage
resources.\135\ PJM Market Monitor recommends that the Commission
require any associated, necessary metering associated with applying the
requirement to demand resources.\136\
---------------------------------------------------------------------------
\135\ PJM Market Monitor Comments at 2; New Jersey Board
Comments at 2.
\136\ PJM Market Monitor Comments at 2; New Jersey Board
Comments at 2.
---------------------------------------------------------------------------
94. Public Interest Organizations also urge the Commission to make
clear that its proposed reforms apply to all resources able to
participate in wholesale energy markets.\137\ PSEG similarly supports
the application of the settlement interval proposal to demand response
resources. PSEG states that real-time settlements for demand response
resources, or any other load-side resources that are price responsive
in wholesale markets, should be based on five-minute intervals, in the
same manner as the supply resources with which it competes.\138\ PSEG
acknowledges that some demand resources will lack necessary meters and/
or communication, and states that it would be reasonable to allow these
resources a transition period to install them without delaying overall
implementation.\139\
---------------------------------------------------------------------------
\137\ Public Interest Organizations at 5.
\138\ PSEG Comments at 5.
\139\ PSEG Comments at 5.
---------------------------------------------------------------------------
95. AEMA states that it recommends that demand response resources
have the option to continue to settle on the basis of one-hour meter
readings. AEMA asserts that demand resources use hourly intervals
because only hourly interval metering may be available and even new
advanced metering infrastructure is only capable of fifteen minute
interval data, whereas settling on five-minute intervals could entail
adding an expense that is an economic barrier to entry for some
resources.\140\
---------------------------------------------------------------------------
\140\ AEMA Comments at 4.
---------------------------------------------------------------------------
96. AEMA also states that few demand response resources have the
operational communications to modify their demand at frequent intervals
and that frequent demand changes would require more robust
communications than may be economic.\141\ AEMA further states that the
Net Benefits Price Threshold that many RTOs/ISOs established in
response to FERC Order No. 745 is applied on an hourly basis and that
the industry has universally adopted hourly baseline methodologies for
demand response resources.\142\
---------------------------------------------------------------------------
\141\ AEMA Comments at 4.
\142\ AEMA Comments at 3-5 (citing Order No. 745, FERC Stats. &
Regs. ] 31,322).
---------------------------------------------------------------------------
97. AEMA explains that much of the current energy-related demand
response participation relies on the commitment to dispatch for one or
more hours and if the bid-offer is accepted for demand response
resources, those resources are eligible for uplift payments if the
energy prices fall below their bid-offer during their committed
dispatch time. AEMA requests that these bid offer guarantees continue
to be incorporated in the Final Rule.\143\
---------------------------------------------------------------------------
\143\ AEMA Comments at 5.
---------------------------------------------------------------------------
b. Commission Determination
98. In using the term ``resource'' in the NOPR, the Commission
intended for the settlement interval proposal to apply to all supply
resources, including demand response resources. We find that, as with
other resources, aligning the price signal and dispatch signal provides
demand response resources capable of following a given dispatch signal
the incentive to do so, resulting in a more efficient use of demand
response resources in the real-time energy and operating reserve
markets. As stated above, all RTOs/ISOs have a combination of
resources, some of which can respond within five minutes and some that
cannot, and that includes demand response resources. It is important to
provide a price signal to all resources, regardless of type or
capability, as this will provide proper compensation to those resources
capable of responding to five-minute dispatch signals, and will
incentivize such capability to those resources that do not currently
have it.
99. In response to concerns about the need to upgrade metering
technology for demand response resources, we note that this Final Rule
does not contemplate requiring any new metering capability, such as
five-minute revenue quality metering, and that such metering is not
necessary for implementation given RTOs'/ISOs' ability to create five-
minute load and generation profiles using telemetry and hourly revenue
quality data. We also do not require any changes to baseline
methodologies. Although a more granular baseline may provide additional
value, RTOs/ISOs need not change their baseline methodology to comply
with this Final Rule. Finally, we find that AEMA's arguments regarding
the Net Benefits Price Threshold \144\ and ``make whole'' rules are
beyond the scope of this Final Rule because it does not require any
changes to the Net Benefits Price Threshold or make-whole payments.
Even if modest changes to these provisions were required for RTOs/ISOs
to comply with this Final Rule, the benefits of this rule would justify
such modifications.
---------------------------------------------------------------------------
\144\ AEMA Comments at 3.
---------------------------------------------------------------------------
5. Load
a. Comments
100. A number of commenters state the proposed rule did not specify
whether the settlement interval proposal would apply to load,\145\ or,
in other
[[Page 42894]]
words, whether it would change how load is settled and measured.
---------------------------------------------------------------------------
\145\ For purposes of this Final Rule, the term ``load''
generally refers to consumption of electricity in the wholesale
markets, but not to demand response acting as a supply resource in
the wholesale markets.
---------------------------------------------------------------------------
101. EEI, PSEG, SCE, AEMA, EPSA and CAISO recommend that the
Commission not apply the settlement reform to load.\146\ The primary
arguments these commenters cite against applying the settlement
interval proposal to load include: (1) The benefit of settling load on
an interval basis is not likely to outweigh the cost, which may include
the need for new expensive metering; \147\ (2) settlement reform alone
will not encourage price responsive load without corresponding changes
to state-jurisdictional retail rate design; \148\ and (3) because load
is not dispatchable, there is no dispatch interval that aligns with
load.\149\ Direct Energy recommends either not applying the settlement
reform to load or delaying implementation until the majority of load
has the ability, incentive and information necessary to respond to
five-minute settlements.\150\ EEI specifically requests that the
Commission clarify that it is not proposing to change how load is
metered.\151\
---------------------------------------------------------------------------
\146\ EEI Comments at 8-9; PSEG Comments at 5-6; SCE Comments at
2; AEMA Comments at 4-5; EPSA Comments, Pope Aff. at 6-7; CAISO
Comments at 16-17.
\147\ SCE Comments at 2.
\148\ SCE Comments at 2.
\149\ CAISO Comments at 16-17.
\150\ Direct Energy Comments at 7. See also Supplemental
Comments of Direct Energy (filed Mar. 4, 2016).
\151\ EEI Comments at 8-9.
---------------------------------------------------------------------------
102. PJM, however, states that it is advantageous to apply the
proposed rule to load, and proposes to settle load on the same interval
as dispatch intervals by using a combination of state-estimator and
telemetry data for each settlement interval.\152\ PJM states that it
thus does not foresee changes being required for market participants'
metering.\153\
---------------------------------------------------------------------------
\152\ PJM Comments at 5.
\153\ PJM Comments at 5.
---------------------------------------------------------------------------
103. Mr. Centolella states that advancing load settlements to
reflect the actual interval demand of each load serving entity's
customers could remove an important barrier to developing the next
generation of responsive demand. Mr. Centolella also encourages the
Commission to work with states to optimize collecting customer data,
and to evaluate how to support efficient price formation related to the
load data used in wholesale settlements.\154\
---------------------------------------------------------------------------
\154\ Mr. Centolella Comments at 4-6.
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b. Commission Determination
104. We clarify that the Commission did not propose to apply the
settlement interval proposal to load. We also clarify that adoption of
the settlement interval requirements are not intended to change how
load is metered. The Commission's basis for requiring changes to the
settlement interval focused exclusively on supply resources rather than
load. As a result, we have no record to require any changes to the
settlement interval for load. However, we are not prohibiting settling
load on a five-minute basis, and will evaluate any such proposals on a
case-by-case basis in separate proceedings submitted pursuant to
section 205 of the FPA.
B. Shortage Pricing Reform
1. Need for Reform
105. In the NOPR, the Commission stated that shortage prices send a
short-term price signal to provide an incentive for the performance of
existing resources and help to maintain reliability. The Commission
noted that some RTOs/ISOs currently restrict the use of shortage
pricing to certain causes of shortages, or some RTOs/ISOs require a
shortage to exist for a minimum amount of time before triggering
shortage pricing.\155\ The Commission further noted that not invoking
shortage pricing when there is a shortage (regardless of the duration
or cause of that shortage) distorts price signals that are designed to
elicit increased supply and to compensate resources for the value of
the services they provide when the system needs energy or operating
reserves. Because these price signals fail to reflect adequately the
value that a resource provides to the system, the Commission
preliminarily found in the NOPR that the resulting price is not just
and reasonable.\156\
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\155\ NOPR, FERC Stats. & Regs. ] 32,710 at P 46.
\156\ NOPR, FERC Stats. & Regs. ] 32,710 at P 47.
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106. The Commission also noted that its rationale regarding
shortage pricing was similar to the rationale the Commission relied on
in Order No. 719, in which the Commission determined that ``rules that
do not allow for prices to rise sufficiently during an operating
reserve shortage to allow supply to meet demand are unjust,
unreasonable, and may be unduly discriminatory'' and that such rules
``may not produce prices that accurately reflect the value of energy.''
\157\
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\157\ NOPR, FERC Stats. & Regs. ] 32,710 at P 48 (citing Order
No. 719, FERC Stats. & Regs. ] 31,281 at P 192).
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107. Commenters generally support the rationale provided by the
Commission in support of the need for reform. For example, as discussed
below, MISO, NYISO and ISO-NE all support the need for reform, and
CAISO supports the conceptual need, but requests further
clarifications. EEI and EPSA also support the Commission's shortage
pricing proposal. Conversely, SPP and PJM, in joint comments, oppose
implementing shortage pricing in all dispatch intervals, and request
revisions if the Commission adopts its proposed reforms.
108. Based on analysis of the record, we adopt our preliminary
findings and conclude that existing shortage pricing triggers that do
not invoke shortage pricing when there is a shortage (regardless of
duration or cause) are unjust and unreasonable and are unduly
discriminatory and preferential. Thus, there is a need to reform the
use of shortage pricing in RTO/ISO markets, as discussed further
herein.
2. NOPR Proposal
109. In order to remedy the potentially unjust and unreasonable
rates caused by restrictions on shortage pricing, the Commission
proposed to require that RTOs/ISOs institute mechanisms that trigger
shortage pricing for any dispatch interval during which a shortage of
energy or operating reserves occurs.
3. Comments on the Proposed Shortage Pricing Reform
a. Comments by RTOs/ISOs
110. MISO states that it supports shortage pricing reform and
maintains that MISO's current practices are already consistent with the
Commission's proposal. Specifically, MISO states its operating reserve
demand curve is used in the five-minute dispatch interval and triggers
shortage pricing in any five-minute interval in which operating reserve
requirements cannot be fully satisfied, regardless of duration or
causation.\158\ MISO also states that its recent implementation of
extended locational marginal pricing (ELMP) considers offline fast-
start resources in its price setting algorithm to more accurately
reflect the cost of the next MW to meet demand during scarcity
conditions.\159\ MISO notes that if no economic offline fast-start
resources are eligible, it will rely upon the operating reserve demand
curve values for shortage pricing. MISO states that it is already
compliant with the proposed rule on shortage pricing.\160\
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\158\ MISO Comments at 10.
\159\ See MISO, Extended Locational Marginal Pricing, Docket No.
ER12-668-000 (filed Dec. 22, 2011).
\160\ MISO Comments at 11-12.
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[[Page 42895]]
111. ISO-NE supports the shortage pricing proposal and asserts that
its current market rules and real-time pricing systems already comply
with the proposed requirement.\161\
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\161\ ISO-NE Comments at 3.
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112. NYISO supports the shortage pricing proposal, and states that
it uses demand curves to price all reserve shortages, regardless of
their duration. NYISO adds that it currently implements shortage
pricing in its day-ahead and real-time markets using various demand
curves for operating reserves, regulating reserves, and transmission
security, where the demand curves represent the escalating value of
each product as the level of any shortage increases.\162\ NYISO also
states that it does not interpret the NOPR to be addressing the use of
offline resources in real-time pricing or to be implying that
practices, such as the NYISO's ``Hybrid Pricing'' rules,\163\ are
inconsistent with the NOPR.\164\
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\162\ NYISO Comments at 6.
\163\ NYISO's Hybrid Pricing rules were adopted in 2001. See New
York Indep. Sys. Operator, Inc., 95 FERC ] 61,121 (2001). The Hybrid
Pricing rules apply to Real-Time Market pricing and relax the
minimum operating limits of certain fast-start, block-loaded
resources in order to permit them to be eligible to set price based
on the incremental need that required their commitment.
\164\ NYISO Comments at 7.
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113. CAISO agrees with the concept behind the shortage pricing
reform and supports its implementation, subject to certain
clarifications. CAISO expects that its existing tariff provisions
implementing scarcity pricing for energy and ancillary services already
comply with the NOPR's proposal. CAISO explains that, in any fifteen-
minute interval of the fifteen-minute market, it will co-optimize the
procurement of energy and ancillary services based on submitted supply
bids and the forecast of demand and its ancillary services
requirements. CAISO further explains that, in any given fifteen-minute
interval, if effective supply bids are insufficient to clear forecasted
demand, scarcity pricing will trigger and thereby indicate a shortage
of supply for that applicable fifteen-minute interval. CAISO states
that, similarly, if ancillary services bids are not sufficient to meet
the ancillary services procurement target, ancillary services scarcity
pricing will trigger for that interval.\165\
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\165\ CAISO Comments at 20.
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114. CAISO notes that within a fifteen-minute operating interval it
may need to deploy operating reserves to address a contingency in the
case of operating reserves, or in the case of regulation to
continuously balance supply and demand. CAISO states that it is
important that the Final Rule clarify that the deployment of operating
reserves or regulation does not necessarily mean a shortage exists.
CAISO notes that in some cases the deployment of reserves is made
through alternative deployment mechanisms and not in the co-
optimization function of the market.\166\ CAISO also explains that in
any given fifteen-minute market interval, if a shortage is observed,
shortage pricing will trigger within that interval and CAISO will not
wait for the shortage to materialize beyond that interval before
triggering shortage pricing. However, CAISO states that not all price
signals triggered by ``transient shortages'' provide incentives to
resources that have the capability to respond to brief-duration
shortages.\167\
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\166\ CAISO explains that during each fifteen-minute interval in
which the resources are deployed, the system is not actually short
of supply bids when the operating reserves for that interval are
procured. Also, CAISO states that once the reserves are deployed, to
the extent that the market allows for full recovery of the required
reserves, the contingency event itself does not trigger scarcity
pricing for ancillary services. According to CAISO, this is because
no actual shortage of operating reserves exists unless there are
insufficient resources to meet operational needs for operating
reserves in the next applicable fifteen-minute market interval.
CAISO Comments at 21-22.
\167\ CAISO Comments at 23.
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115. PJM and SPP filed joint comments opposing triggering shortage
pricing in any dispatch interval in which a shortage of energy or
operating reserves occurs. First, PJM and SPP state that they support
shortage pricing only when ``a shortage of a particular product exists
that presents reliability concerns.'' \168\ PJM and SPP argue that
applying shortage prices to shortage events that do not cause
reliability concerns allows price increases even when such events are
transitory, do not pose reliability concerns, and cannot be addressed
due to limitations on resource response. PJM and SPP maintain that
applying shortage pricing to some transient shortages will give
inaccurate prices and could potentially degrade system reliability, and
may also result in market pricing and operations that are contrary to
the Commission's stated goals.\169\
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\168\ PJM and SPP Comments at 1.
\169\ PJM and SPP Comments at 1-2.
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116. PJM and SPP further state that they have in place rules
related to this issue consistent with the principles and goals of
shortage pricing. PJM and SPP urge the Commission to provide
flexibility by allowing RTOs/ISOs to implement shortage pricing in the
context of their regional rules. This, PJM and SPP assert, will ensure
that inefficient pricing does not result.\170\
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\170\ PJM and SPP Comments at 2-3.
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117. PJM and SPP argue that allowing transient periods of shortage
to trigger shortage pricing could overstate the severity of the
operating condition and result in prices that do not accurately reflect
operating conditions on the system, or last long enough to allow market
participants responding to them to take meaningful action. In fact, PJM
and SPP assert that responses may occur after the relevant interval has
passed, which could be counterproductive operationally and
economically. PJM and SPP pose two examples to illustrate this point.
As the first example, they posit: PJM carrying the required amount of
reserves when a market seller of a generation resource lowers the
resource's economic maximum capability, for a brief time (ten minutes
or less), causing PJM to have less reserves than its requirement.
Currently, PJM can recover these reserves by re-executing its dispatch
engine and re-dispatching its system; but under the shortage pricing
reform, this could invoke shortage pricing, which would then attract
more suppliers than needed and create disincentives for resources to
back down once the event was over. In another example, they posit: PJM
has scheduled a resource with a ten-minute start-up time to come online
to provide energy so that another resource may be reduced to provide
reserves; but if the resource scheduled to come online actually takes
twenty minutes instead of ten, shortage pricing would be triggered
under the shortage pricing proposal, and the second resource, instead
of having its output reduced to provide reserves would now need to
continue to provide energy, thus potentially leaving PJM short on
reserves for a brief period.\171\
---------------------------------------------------------------------------
\171\ PJM and SPP Comments at 4.
---------------------------------------------------------------------------
118. PJM and SPP introduce another hypothetical scenario from the
SPP region. PJM and SPP state that SPP can temporarily use operating
reserves to meet energy requirements during transient periods when
system conditions do not present reliability concerns. PJM and SPP
argue that while this may technically compromise the operating reserve
requirement, the condition is transient and is recovered in less than
ten minutes. According to PJM and SPP, this is not an operating reserve
shortage, but rather a transient reallocation of capacity to manage
temporary energy needs caused by the operational characteristics of
resources. PJM and SPP further state that the examples described above
do not present emergency conditions or
[[Page 42896]]
reliability concerns that would justify shortage pricing.\172\
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\172\ PJM and SPP Comments at 5-6.
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119. In order to ``recognize and respect the fact that not all
instances of shortages justify shortage pricing,'' PJM and SPP propose
alternative language for any Final Rule on shortage pricing:
Each RTO/ISO must establish tariff provisions that implement
shortage pricing for pre-defined operating conditions related to a
shortage of energy or operating reserves. The Commission will allow
each RTO/ISO to develop those provisions based on their regional
circumstances, provided that the rules are consistent with shortage
pricing principles and are designed to facilitate the goals of this
[Final Rule]. The Commission expects that each RTO/ISO will explain
why their provisions, or why their current rules, comply with this
rule.\173\
---------------------------------------------------------------------------
\173\ PJM and SPP Comments at 7.
120. PJM and SPP further assert that a universal shortage pricing
rule requiring shortage pricing even for transient circumstances would
require the implementation of operating reserve demand curves that
distinguish prices relative to varying degrees of shortage. PJM and SPP
explain further that in PJM's case, the current operating reserve
demand curves are a step function, which would need to be changed, and
in SPP's case it would likely consider the implementation of a pricing
gradient demand curve based on different degrees of shortages and their
impact on reliability, rather than steep step curves.\174\
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\174\ PJM and SPP Comments at 8.
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b. Comments by Market Monitors
121. Potomac Economics explains that all the markets that it
monitors (ISO-NE, NYISO, and MISO) are designed to price all shortages,
regardless of duration.\175\ Potomac Economics states that it strongly
supports the shortage pricing reform and argues that pricing all
shortages, regardless of duration, provides efficient incentives for
resources to be flexible and to perform well, which ultimately lowers
costs to consumers and improves reliability.\176\ Potomac Economics
states that, together with the alignment of dispatch and settlement
intervals, a requirement for RTOs/ISOs to price ``transitory
shortages'' rewards units that can respond quickly to help the RTO/ISO
remedy the shortage and, in doing so, addresses the diminished
reliability caused by the shortage.\177\
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\175\ Potomac Economics Comments at 9.
\176\ Potomac Economics Comments at 7.
\177\ Potomac Economics Comments at 7.
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122. Potomac Economics states that transitory shortages typically
occur when the system is ramp-constrained, and that these are true
shortages, because if a large contingency occurs during this period
(e.g., a generator tripping off-line), the RTO/ISO will not have the
ability to replace the capacity because its other generators are
already ramping as quickly as possible. Potomac Economics states that
the Commission's proposal will lead to resources offering faster ramp
rates, offering wider dispatch ranges and not self-scheduling
resources, and offering shorter start times for natural gas turbines.
Potomac Economics states that the proposal also has important long-term
implications as it provides efficient incentives for participants to
build more flexible, fast-ramping generating resources, and to make
maintenance decisions on existing resources to increase their
flexibility.\178\
---------------------------------------------------------------------------
\178\ Potomac Economics Comments at 8.
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123. Potomac Economics also states that allowing offline resources
to set real-time energy and ancillary services prices can be efficient,
but there are also conditions under which the use of these resources
can artificially lower energy prices and obscure shortages.\179\
Potomac Economics explains 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. Further, Potomac Economics explains that the
artificial increase in real-time supply can have a large effect when
the system is experiencing an operating reserve or transmission
shortage, which is ultimately not priced as a shortage because an
offline unit has set the price.\180\
---------------------------------------------------------------------------
\179\ Potomac Economics Comments at 9.
\180\ Potomac Economics Comments at 10.
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124. Potomac Economics recommends that the Commission require RTOs/
ISOs to demonstrate that their real-time pricing models do not allow
offline units to set prices in a manner that undermines its real-time
shortage pricing. Potomac Economics believes that this can be
demonstrated by the RTO/ISO describing how and when offline units set
real-time prices and showing that when offline units have set price
historically that they are generally committed and dispatched as well.
Potomac Economics further asserts that if the RTOs/ISOs cannot
demonstrate this in their compliance filing, then they may need to make
changes to their pricing models to ensure that they satisfy the
Commission's price formation goals.\181\
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\181\ Potomac Economics Comments at 9-11.
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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.
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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\
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\183\ SPP Market Monitor Comments at 4 (citing SPP Tariff,
Attachment AE 5.1.2.1 and 8.3.4.2).
\184\ SPP Market Monitor Comments at 4-6.
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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
[[Page 42897]]
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\
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\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.
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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.
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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.
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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.
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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.
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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.
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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
[[Page 42898]]
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\
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\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\
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\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\
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\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.
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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\
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\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.
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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\
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\219\ APPA and NRECA Comments at 10-11.
\220\ Concerned Cooperatives Comments at 14.
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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\
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\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.
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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
[[Page 42899]]
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\
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\223\ Concerned Cooperatives Comments at 22-24.
\224\ APPA and NRECA Comments at 12.
\225\ Concerned Cooperatives Comments at 15-16.
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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\
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\226\ ODEC Comments at 6.
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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\
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\227\ APPA and NRECA Comments at 15-16.
\228\ Concerned Cooperatives Comments at 15.
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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\
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\229\ Concerned Cooperatives Comments at 24-25.
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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\
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\230\ TAPS Comments at 7-13.
\231\ Direct Energy Comments at 10-11.
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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\
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\232\ Direct Energy Comments at 10-11.
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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\
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\233\ Direct Energy Comments at 11-13.
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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\
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\234\ APPA and NRECA Comments at 5; Concerned Cooperatives
Comments at 18.
\235\ Concerned Cooperatives Comments at 18.
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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\
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\236\ Concerned Cooperatives Comments at 26.
\237\ Concerned Cooperatives Comments at 26.
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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
[[Page 42900]]
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.
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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\
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\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.
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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\
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\244\ Concerned Cooperatives Comments at 25.
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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\
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\245\ PG&E Comments at 1-2.
\246\ PG&E Comments at 1-2.
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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\
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\247\ PG&E Comments at 2.
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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.
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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.
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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
[[Page 42901]]
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.
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\253\ See NOPR, FERC Stats. & Regs. ] 32,710 at P 48 (citing
Order No. 719, FERC Stats. & Regs. ] 31,281).
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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.
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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.
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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\
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\259\ NOPR, FERC Stats. & Regs. ] 32,710 at P 46 & n.70; PJM and
SPP Comments at 5.
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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
[[Page 42902]]
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.
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\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.
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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.
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\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.
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\266\ PJM and SPP Comments at 7-8.
\267\ NOPR, FERC Stats. & Regs. ] 32,710 at P 49.
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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.
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\268\ TAPS Comments at 9; APPA and NRECA Comments at 7;
Concerned Cooperatives Comments at 16.
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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\
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\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.
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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
[[Page 42903]]
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,
[[Page 42904]]
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
[[Page 42905]]
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
[[Page 42906]]
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
[[Page 42907]]
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\
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\357\ Mr. Lively Comments at 3-4 (filed Nov. 23, 2015).
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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).
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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.
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\359\ 44 U.S.C. 3501-3520 (2012).
\360\ 5 CFR part 1320 (2015).
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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.
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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\
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\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.
[[Page 42908]]
--------------------------------------------------------------------------------------------------------------------------------------------------------
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.
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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:
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
Comments concerning the collection of information and the associated
burden estimate(s) may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission]. Due to security concerns, comments
should be sent electronically to the following email address:
oira_submission@omb.eop.gov. 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\
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\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).
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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.
[[Page 42909]]
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.
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\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)).
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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
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
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.
[[Page 42910]]
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