Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, 53403-53411 [2017-24803]
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Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations
maximum continuous thrust, and
deceleration to ground idle.
(2) The throttle movement from
ground idle to rated takeoff or maximum
continuous thrust and from rated takeoff
thrust to ground idle should be not more
than one (1) second, except that, if
different regimes of control operations
are incorporated necessitating
scheduling of the thrust-control lever
motion in going from one extreme
position to the other, a longer period of
time is acceptable, but not more than
two (2) seconds. The throttle movement
from rated maximum continuous thrust
to ground idle should not be more than
five (5) seconds.
(3) The time durations for each cycle
associated with either takeoff or
maximum continuous thrust segments
must include all maximums allowed in
the TCDS and expected service
operation, and must include the
following cycles:
(i) Three (3) cycles of 5 minutes each
and one (1) cycle of 10 minutes at the
takeoff thrust.
(ii) Three (3) cycles of 30 minutes
each at the maximum continuous thrust.
Issued in Burlington, Massachusetts, on
November 8, 2017.
Robert J. Ganley,
Manager, Engine and Propeller Standards
Branch, Aircraft Certification Service.
[FR Doc. 2017–24812 Filed 11–15–17; 8:45 am]
BILLING CODE 4910–13–P
53403
determinations in Order No. 831, which
amended its regulations to address
incremental energy offer caps in markets
operated by regional transmission
organizations and independent system
operators.
DATES:
This rule is effective January 16,
2018.
FOR FURTHER INFORMATION CONTACT:
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM16–5–001; Order No. 831–
A]
Offer Caps in Markets Operated by
Regional Transmission Organizations
and Independent System Operators
Federal Energy Regulatory
Commission, Department of Energy.
ACTION: Order on rehearing and
clarification.
AGENCY:
The Federal Energy
Regulatory Commission is granting in
part and denying in part requests for
rehearing and clarification of its
SUMMARY:
Emma Nicholson (Technical
Information), Office of Energy Policy
and Innovation, Federal Energy
Regulatory Commission, 888 First
Street NE., Washington, DC 20426,
(202) 502–8846, emma.nicholson@
ferc.gov
Pamela Quinlan (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
6179, pamela.quinlan@ferc.gov
Anne Marie Hirschberger (Legal
Information), Office of the General
Counsel, Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
8387, annemarie.hirschberger@
ferc.gov
SUPPLEMENTARY INFORMATION:
TABLE OF CONTENTS
Paragraph Nos.
I. Introduction ...............................................................................................................................................................................
II. Discussion ................................................................................................................................................................................
A. Offer Cap Structure ..........................................................................................................................................................
1. Hard Cap Level ..........................................................................................................................................................
2. Implementation of the Hard Cap ..............................................................................................................................
B. Verification Requirement .................................................................................................................................................
1. Expected Costs ...........................................................................................................................................................
2. Verification of Imports ..............................................................................................................................................
C. Costs Included in Cost-Based Incremental Energy Offers ..............................................................................................
1. Requests for Rehearing/Clarification ........................................................................................................................
2. Determination .............................................................................................................................................................
III. Information Collection Statement ..........................................................................................................................................
IV. Regulatory Flexibility Act Certification ................................................................................................................................
V. Document Availability ............................................................................................................................................................
VI. Effective Date ..........................................................................................................................................................................
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I. Introduction
1. On November 17, 2016, the Federal
Energy Regulatory Commission
(Commission) issued Order No. 831.1
Order No. 831 addresses the
incremental energy offer component of
a resource’s supply offer, which is a
financial component consisting of costs
that vary with a resource’s output or
level of demand reduction. Incremental
energy offers are one of the components
used to calculate locational marginal
1 Offer Caps in Markets Operated by Regional
Transmission Organizations and Independent
System Operators, 81 FR 87,770 (Dec. 5, 2016),
FERC Stats. & Regs. ¶ 31,387 (2016) (Order No.
831).
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prices (LMPs). California Independent
System Operator Corporation (CAISO),
ISO New England Inc. (ISO–NE),
Midcontinent Independent System
Operator, Inc. (MISO), New York
Independent System Operator, Inc.
(NYISO), and Southwest Power Pool,
Inc. (SPP) currently have a $1,000/MWh
cap on incremental energy offers (offer
cap), and PJM Interconnection, L.L.C.
(PJM) currently has an offer cap of
$2,000/MWh on cost-based offers.2
2. In Order No. 831, the Commission
amended its regulations to require that
each regional transmission organization
2 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
PP 11–13.
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and independent system operator (RTO/
ISO): (1) Cap each resource’s
incremental energy offer at the higher of
$1,000/MWh or that resource’s verified
cost-based incremental energy offer; and
(2) cap verified cost-based incremental
energy offers at $2,000/MWh when
calculating LMPs (hard cap).3 Resources
with verified cost-based incremental
energy offers above $2,000/MWh will be
eligible to receive uplift.4 In response to
comments on the Notice of Proposed
3 Id.
4 Id.
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Rulemaking,5 the Commission clarified
that each RTO/ISO or Market
Monitoring Unit must verify that any
incremental energy offer above $1,000/
MWh reasonably reflects the associated
resource’s actual or expected costs, as
opposed to only the resource’s actual
costs, prior to using that offer to
calculate LMP.6
3. With respect to treatment of costbased incremental energy offers above
$2,000/MWh, the Commission stated
that it expects RTOs/ISOs to use such
offers to determine merit-order dispatch,
and it cited PJM as an example of an
RTO/ISO that uses cost-based
incremental energy offers above $2,000/
MWh to determine merit-order dispatch,
but limits cost-based incremental energy
offers to $2,000/MWh for purposes of
calculating LMP.7 The Commission
found that imports should be permitted
to offer above $1,000/MWh, but will not
be subject to verification.8 Finally,
while Order No. 831 did not require
RTOs/ISOs to include an adder above
cost in cost-based incremental energy
offers above $1,000/MWh, the
Commission stated that if an RTO/ISO
chooses to retain existing rules that
allow for an adder above cost or
proposes any new adders above cost,
such adders may not exceed $100/
MWh.9 However, in Order No. 831, the
Commission did not require RTOs/ISOs
to change the costs they currently
include in cost-based incremental
energy offers, and it did not address
whether verifiable opportunity costs are
subject to the $100/MWh limit on
adders.
4. On December 19, 2016, the
Commission received four requests for
rehearing and/or clarification of Order
No. 831 which raise issues related to the
structure of the offer cap, the
verification requirement, and the costs
included in cost-based incremental
energy offers. TAPS filed a request for
rehearing and clarification. NYISO filed
a request for clarification and,
alternatively, request for rehearing.
AMP/APPA filed a request for
rehearing. Exelon filed a motion for
clarification and request for rehearing.10
5 Offer Caps in Markets Operated by Regional
Transmission Organizations and Independent
System Operators, 81 FR 5951 (Feb. 4, 2016), FERC
Stats. & Regs. ¶ 32,714, at PP 3 (2016) (NOPR).
6 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
P 139.
7 Id. P 90.
8 Id. P 192.
9 Id. P 207.
10 The Independent Market Monitor for PJM (PJM
Market Monitor) filed an answer to Exelon’s motion
for clarification and request for rehearing. MISO
filed comments in support of NYISO’s request for
clarification and, alternatively, request for
rehearing. Rule 713(d)(1) of the Commission’s Rules
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For the reasons discussed below, we
grant in part and deny in part the
requests for rehearing and clarification.
II. Discussion
A. Offer Cap Structure
5. The requests for rehearing and
clarification regarding the offer cap
structure focus on the level of the hard
cap and the implementation of the hard
cap.
1. Hard Cap Level
a. Request for Rehearing
6. TAPS seeks rehearing and argues
both that the $2,000/MWh hard cap
level established by the Commission is
not supported by substantial evidence,
and that the $1,724/MWh offer cited in
Order No. 831 was not a legitimate costbased incremental energy offer.11
Rather, TAPS states, the $1,724/MWh
offer was the estimated cost of a
resource calculated according to PJM’s
Cost Development Guidelines, but the
actual cost of that resource was less than
$1,500/MWh. TAPS argues that, given
the large discrepancy between estimated
and actual costs, it was inappropriate
for the Commission to rely on an
estimated $1,724/MWh offer as the basis
for the $2,000/MWh hard cap level.
TAPS asserts that, even if it was
appropriate for the Commission to rely
upon estimated costs, the Commission
should not have used the $1,724/MWh
level, since it was estimated using a
methodology that is not compliant with
Order No. 831. TAPS contends that the
Commission should instead set the hard
cap level at $1,500/MWh or,
alternatively, at $1,800/MWh if the
Commission determines that there was
a legitimate cost-based incremental
energy offer of $1,724/MWh.12 TAPS
also argues that the Commission failed
to meaningfully address the analytical
evidence TAPS presented in its
comments supporting a $1,500/MWh
hard cap.13
b. Determination
7. We deny TAPS’ request for
rehearing of the $2,000/MWh level of
the hard cap. In Order No. 831, the
of Practice and Procedure prohibits answers to
requests for rehearing. 18 CFR 385.713(d)(2) (2017).
We therefore reject the answer of the PJM Market
Monitor. We will treat MISO’s comments as an
answer and as a result reject them.
11 TAPS Request for Clarification/Rehearing at 2
(citing Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315
(D.C. Cir. 2004); Canadian Ass’n of Petroleum
Producers v. FERC, 254 F.3d 289 (D.C. Cir. 2001)
(Canadian Ass’n of Petroleum Producers)).
12 Id. at 5–11.
13 Id. at 10 (citing Canadian Ass’n of Petroleum
Producers, 254 F.3d at 299 (an agency’s ‘‘failure to
respond meaningfully’’ to objections raised by a
party renders its decision arbitrary and capricious)).
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Commission determined that a hard cap
was necessary to limit any adverse
impact on LMPs due to imperfect
information about a resource’s short-run
marginal costs that might arise during
the verification process.14 The
Commission also recognized that a hard
cap that is too low might suppress LMPs
below the marginal cost of production.15
In determining the $2,000/MWh level of
the hard cap, the Commission therefore
struck a balance between competing
goals: (1) Limiting any adverse impacts
on LMPs due to imperfect information
during the verification process and (2)
reducing the likelihood of suppressing
LMPs below the marginal cost of
production.
8. The overall offer cap structure set
forth in Order No. 831 and the overall
market structure of RTOs/ISOs in which
the offers arise affected the balance
struck by the Commission in setting the
level of the hard cap. The hard cap does
not stand alone, meaning that it is not
the only way of ensuring that an offer
does not reflect the exercise of market
power and that the price resulting from
an incremental energy offer is just and
reasonable. In balancing the competing
goals, the Commission effectively
recognized that the hard cap serves as
a backstop to the mitigation established
through both the cost-based requirement
and the verification process—the other
elements of the offer cap structure. The
cost-based offer requirement serves a
‘‘mitigation function’’ 16 by requiring
incremental energy offers above $1,000/
MWh be cost-based. The verification
requirement also addresses market
power concerns.17 The hard cap
‘‘limit[s] the adverse impact that any
imperfect information about resources’
short-run marginal costs during the
verification process could have on
LMPs.’’ 18 The Commission factored in
these two other elements of the offer-cap
structure in balancing the competing
goals to set the level of the hard cap.
9. In setting that level, the
Commission also considered the overall
market structure of RTOs/ISOs—a
structure designed to ensure that
markets are competitive and not subject
to the exercise of market power, through
for instance, existing market power
mitigation processes.19 The hard cap
14 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
P 87.
15 Id. P 91.
16 Id. P 83.
17 Id. P 139.
18 Id. P 87.
19 Cf. id. PP 85–90. Additionally, all six RTOs/
ISOs have market power mitigation rules designed
to prevent market participants from exercising
market power. See, e.g., California Independent
System Operator Corporation, eTariff, 39; ISO New
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also serves as backstop to those existing
market mitigation processes.20
10. Based on the record, the
Commission set the level of the hard cap
to $2,000/MWh. The Commission
determined that $2,000/MWh was the
level that short-run marginal costs
would rarely exceed.21 The cost-based
incremental energy offer of $1,724/MWh
referenced in Order No. 831, and which
TAPS questions, regardless of the
methodology by which it was derived,
was only one point of reference for the
Commission within the context of the
broader record. Specifically, the
Commission also examined the
evidence in the record regarding high
natural gas prices that occurred during
the Polar Vortex when some resources
experienced short-run marginal costs
above $1,000/MWh.22
11. The alternative $1,500/MWh and
$1,800/MWh hard cap levels that TAPS
proposed would result in a balance
different than the one chosen by the
Commission. Lower hard cap levels
such as these would increase the
likelihood of suppressing prices below
the marginal cost of production and
would thereby run contrary to the
Commission’s price formation efforts to
ensure that LMPs reflect the short-run
marginal cost of the marginal resource.
We therefore reject TAPS’ request for
rehearing and the alternative hard cap
levels proposed. As stated above, we
continue to find that the $2,000/MWh
hard cap reasonably balances reducing
the likelihood of suppressing LMPs
while limiting any adverse impact on
LMPs from imperfect information about
resources’ short-run marginal costs
during the verification process.
12. Further, we reject TAPS’ argument
that the Commission failed to
meaningfully address its $1,500/MWh
England Inc., Markets and Services Tariff, Market
Rule 1, Appendix A; Midcontinent Independent
System Operator, Inc., FERC Electric Tariff, Module
D; New York Independent System Operator, Inc.,
Market Administration and Control Area Services
Tariff, Attachment H; PJM Interconnection, L.L.C.,
Intra-PJM Tariffs, OATT, Tariff Operating
Agreement, Attachment M; and Southwest Power
Pool, Inc., OATT, Sixth Revised Volume No. 1,
Attachment AF.
20 Cf. id. P 89.
21 See id. n.200 (citing Envtl. Action, Inc. v. FERC,
939 F.2d 1057, 1064 (D.C. Cir. 1991) (‘‘it is within
the scope of the agency’s expertise to make such a
prediction about the market it regulates, and a
reasonable prediction deserves our deference
notwithstanding that there might also be another
reasonable view.’’). See also Michigan Consol. Gas
Co. v. FERC, 883 F.2d 117, 124 (1989) (‘‘It is also
quite clear FERC may make predictions—‘‘[m]aking
. . . predictions is clearly within the Commission’s
expertise’’ and will be upheld if ‘‘rationally based
on record evidence.’’) (citing East Tennessee
Natural Gas Co. v. FERC, 863 F.2d 932, 938–39
(1988) (citing Associated Gas Distributors v. FERC,
824 F.2d 981, 1008 (1987)))).
22 Id. P 92.
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alternative proposal. The Commission
addressed this alternative in adopting
the $2,000/MWh hard cap.23 In any
event, in a rulemaking, the Commission
need not respond to every comment or
analyze every alternative. Rather, the
Commission must respond to
‘‘comments which, if true. . .would
require a change in an agency’s
proposed rule.’’ 24 The Commission’s
determination regarding the $2,000/
MWh hard cap is not invalidated merely
because there may be a reasonable
alternative.25
2. Implementation of the Hard Cap
a. Requests for Rehearing/Clarification
13. NYISO seeks clarification that
Order No. 831 does not require that
incremental energy offers above $2,000/
MWh be used to determine merit-order
dispatch in all RTOs/ISOs, and, in the
alternative, seeks rehearing on this
issue.26 NYISO states that, to the extent
the Commission intended to establish a
requirement, the Commission did not
seek comment on the requirement in the
NOPR, did not demonstrate that the
requirement must be imposed on all
RTOs/ISOs in order to ensure just and
reasonable rates, and did not consider
the burdens the requirement would
impose on NYISO.27
14. NYISO asserts that such a
requirement would introduce foreign
market design elements into NYISO that
were developed by PJM to be
compatible with its own pricing
method, market rules, and software.28
Specifically, NYISO explains that PJM’s
design accommodates discrepancies
between schedules and price, using a
secondary ex post process to determine
23 Id.
24 American Min. Congress v. EPA, 907 F.2d 1179,
1187–88 (D.C. Cir. 1990) (American Min. Congress)
(citing Thompson v. Clark, 741 F.2d 401, 408 (D.C.
Cir. 1984) (Thompson); ACLU v. FCC, 823 F.2d
1554, 1581 (D.C. Cir.1987) (ACLU)).
25 See United Distribution Cos. v. FERC, 88 F.3d
1105, 1169–70 (D.C. Cir. 1996) (United Distribution
Cos.) (‘‘FERC correctly counters that the fact that
AEPCO may have proposed a reasonable alternative
. . . is not compelling. The existence of a second
reasonable course of action does not invalidate an
agency’s determination.’’).
26 See Order No. 831, FERC Stats. & Regs. ¶
31,387 at P 90 (‘‘With respect to the treatment of
cost-based incremental energy offers above $2,000/
MWh, we expect RTOs/ISOs to use such offers to
determine merit-order dispatch. We note that the
Commission allowed this approach when accepting
PJM’s current offer cap structure. . . .’’ ’’).
27 NYISO Request for Clarification/Rehearing at 5,
11–13.
28 NYISO also maintains that RTOs/ISOs do not
need to have identical software or market rules, and
that the practical ability to implement software
changes justifies accommodating regional
circumstances. Id. at 6 (citing N.Y. Indep. Sys.
Operator, Inc., 142 FERC ¶ 61,202, at PP 24–26
(2013); N.Y. Indep. Sys. Operator, Inc., 133 FERC
¶ 61,246, at P 25 (2010)).
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LMPs that is separate from the process
for determining resource schedules.
However, NYISO states that it uses a
common ex ante process to determine
both locational based marginal prices
(LBMPs) and resource schedules.
NYISO asserts that, because its process
utilizes the same offers for scheduling
and pricing, it would be challenging to
allow resources to be committed and
scheduled based on validated
incremental energy offers above $2,000/
MWh, but then cap the offers for
purposes of calculating LBMPs and
ancillary services prices. According to
NYISO, this would require resourceintensive and potentially costly software
changes, make validation of prices and
schedules more complex, and require
NYISO to redirect resources from other
efforts that are more certain to benefit
consumers and markets. Additionally,
NYISO contends that implementing an
offer cap that only limits the offer prices
used to determine LBMPs can lead to a
divergence between resource schedules
and prices that can harm market
participants.29
15. In addition, NYISO requests
clarification that RTOs/ISOs are
permitted to apply the same offer cap to
both incremental energy and minimum
generation offers,30 and in the
alternative seeks rehearing on this issue.
Currently, NYISO’s tariff applies a
$1,000/MWh offer cap to all day-ahead
and real-time energy offers, including
minimum generation offers. NYISO
argues that applying different offer caps
to incremental energy offers and
minimum generation offers could
incentivize suppliers to artificially
shape their offers to conform to the
different offer caps rather than offer in
a manner that accurately reflects a
resource’s costs, which would result in
less optimal commitment, dispatch, and
pricing. Furthermore, NYISO states that
if minimum generation offer caps are
lower than incremental energy offer
caps, generators may not offer to supply
energy if they do not expect to be able
to recoup their costs.31 NYISO also
states that the Commission previously
granted waiver of the $1,000/MWh offer
cap on both incremental energy offers
and minimum generation offers in
29 Id.
at 7–11.
NYISO, the first block in a resource’s
incremental energy offer is called a ‘‘minimum
generation bid’’ and includes the costs a resource
incurs to operate at its economic minimum
operating level. NYISO, Manual 11—Day-Ahead
Scheduling Manual, Sec. 4.3.3. (October 2016)
https://www.nyiso.com/public/webdocs/markets_
operations/documents/Manuals_and_Guides/
Manuals/Operations/dayahd_schd_mnl.pdf.
31 NYISO Request for Clarification/Rehearing at
13–15.
30 In
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response to spikes in natural gas costs
caused by the Polar Vortex.32
b. Determination
16. Regarding NYISO’s concerns on
economic merit-order dispatch, we
clarify that Order No. 831 did not
require cost-based incremental energy
offers above $2,000/MWh to be used to
determine economic merit-order
dispatch. We recognize that some
RTO’s/ISO’s existing commitment,
dispatch, and pricing algorithms are
structured differently, and the
Commission in Order No. 831 did not
require RTOs/ISOs to change their
current practices or software to use costbased incremental energy offers above
$2,000/MWh for determining economic
merit-order dispatch. However, in the
event that RTOs/ISOs must select from
several offers above $2,000/MWh, we
encourage RTOs/ISOs to make those
selections on a least-cost basis when
possible, in order to minimize the cost
to serve load.
17. We also clarify that application of
the offer cap and verification
requirement adopted in Order No. 831
to minimum generation offers, as NYISO
requests, is appropriate. Applying
different offer caps to minimum
generation and incremental energy
offers could give resources the incentive
to shape their offers in a manner that
does not reflect their costs.33
Furthermore, this application is
consistent with prior Commission
orders regarding NYISO’s offer cap
discussed above.34
B. Verification Requirement
18. The requests for rehearing
regarding the verification requirement
focus on the use of expected costs in the
verification requirement and whether to
subject imports to the verification
requirement.
1. Expected Costs
19. The requests for rehearing
regarding expected costs include the
definition of expected costs and
whether they should be included in the
regulatory text as well as market power
concerns related to the use of expected
costs in the verification process.
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a. Definition and Regulatory Text
i. Requests for Rehearing
20. AMP/APPA seek rehearing of
Order No. 831, arguing that the
Commission was arbitrary and
capricious because it failed to provide a
32 Id. at 13 (citing N.Y. Indep. Sys. Operator, Inc.,
146 FERC ¶ 61,061, at PP 2–4, 20 (2014)).
33 See id. at 14.
34 See supra P 15.
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reasonable justification for allowing
sellers’ expected costs to set LMP, and
that the Commission also unjustifiably
expanded the definition of cost-based
offers to include ‘‘expected’’ costs.
According to AMP/APPA, in order for
LMPs to send accurate signals regarding
the actual cost of producing energy,
LMPs should be based on actual costs.
AMP/APPA argue that, since some
commenters stated that pre-verification
of actual costs would not be possible,
the Commission should have concluded
that offers above $1,000/MWh should
not set LMP, and instead, required such
costs to be recovered via uplift.35
21. Exelon requests rehearing of the
fact that the regulatory text does not
include the ‘‘actual or expected’’ phrase
when it describes the costs to be
verified. Exelon argues that the current
regulatory text fails to adequately
capture the Commission’s intent
described in the preamble, specifically
that costs may be either actual or
expected. Exelon asserts that, in order to
avoid confusion and also satisfy due
process and regulatory notice
requirements, the Commission should
amend the regulatory text to specify that
the verified costs can be ‘‘actual or
expected.’’ 36
ii. Determination
22. We disagree with AMP/APPA’s
argument that the use of expected costs
in the verification process to set LMPs
was arbitrary and capricious, and thus
deny its request for rehearing. The
record demonstrates that certain natural
gas resources do not know their actual
short-run marginal costs at the time they
submit their incremental energy offers,
and thus it is just and reasonable, and
consistent with current practice, for
such resources to offer based on their
expected costs.37 Given this record, the
Commission appropriately responded to
the many comments filed by clarifying
in Order No. 831 that market
participants could offer based on
expected costs. In circumstances when
actual costs are not known, a resource
offer based on expected short-run
marginal cost constitutes a competitive
offer. Further, contrary to AMP/APPA’s
assertion, in Order No. 831 the
Commission did not expand the
definition of the specific types of short35 AMP/APPA Request for Rehearing at 9–13
(citing Motor Vehicle Mfrs. Ass’n v. State Farm Mut.
Auto. Ins. Co., 463 U.S. 29, 43 (1983) (Motor Vehicle
Mfrs. Ass’n); United Distrib. Cos., 88 F.3d at 1169).
36 Exelon Request for Clarification/Rehearing at
6–8 (citing U.S. v. Chrysler Corp., 158 F.3d 1350
(D.C. Cir. 1998); Upton v. SEC, 75 F.3d 92 (2d Cir.
1996); General Electric Co. v. EPA, 53 F.3d 1324
(D.C. Cir. 1995)).
37 See Order No. 831, FERC Stats. & Regs. ¶
31,387 at PP 104–108.
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run marginal costs that a resource could
include in its cost-based incremental
energy offer above $1,000/MWh, but
rather, the Commission stated that it
expected that the RTO/ISO would build
on its existing mitigation processes for
calculating or updating cost-based
incremental energy offers. Further, in
Order No. 831, the Commission required
an RTO/ISO to explain in its
compliance filing what factors it will
consider in the verification process for
cost-based incremental energy offers
above $1,000/MWh and whether such
factors are currently considered in
existing market power mitigation
provisions. Thus, the Commission was
not arbitrary and capricious because its
decision to permit verified expected
costs above $1,000/MWh to set LMP is
consistent with current RTO/ISO
practices that allow cost-based
incremental energy offers to be based on
expected, rather than actual costs, as
demonstrated in the record.38
23. We grant Exelon’s request to
amend the regulatory text by adding the
words ‘‘actual or expected’’ as suggested
by Exelon. We agree that these revisions
will provide more certainty to market
participants and more clearly state the
Commission’s intention that both actual
and expected costs over $1,000/MWh
may be submitted for verification.
b. Market Power Concerns
i. Requests for Rehearing
24. AMP/APPA seek rehearing
contending that Order No. 831 is
arbitrary and capricious because it fails
to address market power concerns that
may arise if resources exaggerate
expected costs included in cost-based
incremental energy offers above $1,000/
MWh.39 According to AMP/APPA, there
are strong incentives for an owner of a
fleet of resources, for example, to inflate
expected costs of one resource during a
constrained period in order to increase
earnings for all of its resources. AMP/
APPA further argue that there is an
opportunity to inflate costs because
natural gas prices are higher during
constrained periods, and this is also
when the price of natural gas is less
transparent because the price paid by a
market seller for gas on the bilateral
market is farthest away from index
prices.40
25. AMP/APPA further assert that
Order No. 831 failed to address whether
38 See
id. PP 106–107.
Request for Rehearing at 13–16
(citing Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43).
40 Id. at 13–15 (citing Joint Comments of PJM and
SPP, Docket No. RM16–5–000, at 10–11 (filed Apr.
4, 2016); Comments of ISO–NE Market Monitor,
Docket No. RM16–5–000, at 7 (filed Apr. 4, 2016)).
39 AMP/APPA
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allowing offers above $1,000/MWh to
set LMP could lead to market power
concerns in the natural gas market.41 In
support of this position, AMP/APPA
reference the PJM Market Monitor’s
comments in the Order No. 831
proceeding stating that removing the
offer cap entirely could exacerbate
market power in the natural gas markets
and also impact electricity markets.42
AMP/APPA further note that the
Internal Market Monitor for ISO–NE
(ISO–NE Market Monitor) stated that, in
ISO–NE., raising the offer cap could
expose the energy markets to
uncompetitive conditions in the natural
gas markets.43 AMP/APPA therefore
propose that offers above $1,000/MWh
should be based upon actual costs in
order to be used to set LMP, since the
use of expected costs can exacerbate
market power concerns, but offers above
$1,000/MWh based on expected costs
should be recovered via uplift.44
26. AMP/APPA seek rehearing of
Order No. 831, arguing that the
Commission’s use of expected costs in
setting LMP was arbitrary and
capricious, and that the Commission did
not explain its departure from relevant
precedent.45 Specifically, AMP/APPA
argue that allowing expected costs to be
used to verify cost-based incremental
energy offers above $1,000/MWh
contravenes the Federal Power Act
(FPA) and is inconsistent with
precedent requiring certain safeguards
when granting market-based rates.
AMP/APPA maintain that the
Commission’s authority under the FPA
to grant market-based rate authority has
been upheld in court because the
Commission periodically conducts ex
ante examinations of a public utility’s
market power as well as enforceable ex
post reporting.46 According to AMP/
APPA, however, Order No. 831 never
requires RTOs/ISOs or Market Monitors
to ensure that the market-clearing LMPs
resulting from a seller’s offer exceeding
$1,000/MWh are actually cost-based.
AMP/APPA assert that permitting
verification based on expected costs
does not meet the ex post reporting
requirement that would allow the
Commission to determine whether these
expected costs and resulting market41 Id.
at 15–16.
at 15 (citing PJM Market Monitor,
Comments, Docket No. RM16–5–000, at 4 (filed
Apr. 4, 2016)).
43 Id. (citing ISO–NE Market Monitor, Comments,
Docket No. RM16–5–000, at 3 (filed Apr. 4, 2016)).
44 Id. at 17.
45 Id. at 8 (citing PSEG Energy Res. & Trade LLC
v. FERC, 665 F.3d 203, 208 (D.C. Cir. 2011); Motor
Vehicle Mfrs. Ass’n, 463 U.S. at 43; FCC v. Fox
Television Stations, 556 U.S. 502, 515 (2009)).
46 Id. at 5 (citing California ex rel. Lockyer v.
FERC, 383 F.3d 1006, 1013–14 (9th Cir. 2004)).
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42 Id.
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clearing prices are just and reasonable.
AMP/APPA therefore conclude that
Order No. 831 is unlawful because the
Commission cannot rely on market
forces to regulate rates in lieu of
imposing reporting requirements on
generators.47
ii. Determination
27. We deny AMP/APPA’s request for
rehearing and alternative proposal
regarding market power concerns and
the use of expected costs. We disagree
with AMP/APPA that incremental
energy offers above $1,000/MWh based
on expected costs present market power
concerns; the verification requirement
in Order No. 831 was specifically
designed to address market power
concerns and ensure that all
incremental energy offers above $1,000/
MWh are indeed cost-based. Pursuant to
the verification requirement, resources
may only submit incremental energy
offers above $1,000/MWh if they are
cost-based, and the RTO/ISO or Market
Monitoring Unit must verify that any
such offer reasonably reflects that
resource’s actual or expected short-run
marginal costs. Incremental energy
offers above $1,000/MWh may not be
used to calculate LMPs if such offers
cannot be verified by the RTO/ISO or
Market Monitoring Unit prior to the
market clearing process. In Order No.
831, the Commission specifically found
that ‘‘the verification requirement
reasonably addresses market power
concerns associated with incremental
energy offers above $1,000/MWh
because such offers will be required to
be cost-based, which should deter
attempts by resources to exercise market
power.’’ 48 The verification requirement
in Order No. 831 is therefore designed
to prevent the concerns AMP/APPA
raise about resources including
‘‘inflated’’ or ‘‘exaggerated’’ expected
costs in cost-based incremental energy
offers above $1,000/MWh.
28. We reject as unsupported AMP/
APPA’s claim that the Final Rule did
not address concerns about market
power in the natural gas market. The
excerpts from the PJM Market Monitor’s
and ISO–NE Market Monitor’s
comments that AMP/APPA included in
its request for rehearing expressed
general concern about removing a hard
cap in energy markets given potential
concerns about market power in natural
gas markets. However, Order No. 831
did not remove a hard cap in energy
markets—it adopted a $2,000/MWh
47 Id. at 6–8 (citing Blumenthal v. FERC, 552 F.3d
875, 882–83 (D.C. Cir. 2009); FPC v. Texaco, 417
U.S. 380, 399 (1974)).
48 See Order No. 831, FERC Stats. & Regs.
¶ 31,387 at P 144.
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53407
hard cap. As discussed above, we
balanced several considerations in
adopting a $2,000/MWh but the fact that
a hard cap continues to remain in place
addresses the comments AMP/APPA
cites, to the extent there is market power
in the natural gas markets. Additionally,
the excerpt from the ISO–NE Market
Monitor’s comments cited by AMP/
APPA discusses the relationship
between natural gas markets and energy
markets and expresses general concerns
about limited transparency into the
competitive conditions in natural gas
spot markets. Again, the $2,000/MWh
hard cap addresses this concern as it
recognizes that the verification process
required by Order No. 831 may be less
effective during extreme conditions in
the natural gas market.49
29. We deny AMP/APPA’s request for
rehearing regarding market-based rates
because Order No. 831 does not depart
from Commission precedent, and the
Commission’s action was not arbitrary
and capricious. Contrary to AMP/
APPA’s claims, a market participant
with market-based rate authority that
submits a cost-based incremental offer
above $1,000/MWh for a resource would
continue to be subject to the existing
reporting and other requirements that
are imposed on entities with marketbased rate authority,50 consistent with
the precedent cited by AMP/APPA.
Further, contrary to AMP/APPA’s
assertions, the verification process
specifically requires that the RTO/ISO
or Market Monitoring Unit ensure that
incremental energy offers are in fact
cost-based, meaning that the offer must
reasonably reflect that resource’s actual
or expected short-run marginal costs.51
49 See
id. P 87.
example, entities with market-based rate
authority must file Electric Quarterly Reports with
the Commission, consistent with Order Nos. 2001
and 768. Revised Public Utility Filing Requirements,
Order No. 2001, FERC Stats. & Regs. ¶ 31,127, reh’g
denied, Order No. 2001–A, 100 FERC ¶ 61,074,
reh’g denied, Order No. 2001–B, 100 FERC ¶ 61,342,
order directing filing, Order No. 2001–C, 101 FERC
¶ 61,314 (2002), order directing filing, Order No.
2001–D, 102 FERC ¶ 61,334, order refining filing
requirements, Order No. 2001–E, 105 FERC ¶ 61,352
(2003), order on clarification, Order No. 2001–F,
106 FERC ¶ 61,060 (2004), order revising filing
requirements, Order No. 2001–G, 120 FERC
¶ 61,270, order on reh’g and clarification, Order No.
2001–H, 121 FERC ¶ 61,289 (2007), order revising
filing requirements, Order No. 2001–I, FERC Stats.
& Regs. ¶ 31,282 (2008); Elec. Mkt. Transparency
Provisions of Section 220 of the Fed. Power Act,
Order No. 768, FERC Stats. & Regs. ¶ 31,336 (2012),
order on reh’g, Order No. 768–A, 143 FERC ¶ 61,054
(2013). They must also timely report to the
Commission any change in status that would reflect
a departure from the characteristics the Commission
relied upon in granting their market-based rate
authority. 18 CFR 35.42 (2017).
51 See Order No. 831, FERC Stats. & Regs.
¶ 31,387 at P 140 (‘‘[A]n RTO/ISO or a Market
50 For
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As discussed above, the record
demonstrates that it is appropriate to
use expected costs in the verification of
cost-based incremental energy offers
because when actual costs are not
known, a resource offer based on
expected short-run marginal cost
constitutes a competitive offer.52 In
Order No. 831, the Commission stated
that ‘‘[a] cost-based incremental energy
offer is based on the associated
resource’s short-run marginal cost,
which constitutes a competitive offer
free from the exercise of market
power.’’ 53 Therefore, the use of
expected costs in the verification
process does in fact allow the
Commission to determine whether the
resulting market clearing prices would
be just and reasonable.
2. Verification of Imports
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a. Request for Rehearing
30. TAPS seeks rehearing of Order No.
831’s exemption of all imports from the
verification requirement for incremental
energy offers above $1,000/MWh and
asserts that it is unjust and unreasonable
and arbitrary, and that it puts internal
and external resources on unequal
footing.54 According to TAPS, the
Commission’s finding that some imports
are not resource-specific and therefore
cannot have their costs verified does not
support exempting all imports from the
verification requirement. Therefore,
TAPS proposes that only resourcespecific imports whose costs are verified
by the receiving RTO/ISO should be
able to set LMP, while other imports
with offers above $1,000/MWh that are
not verified should receive uplift
payments if their costs are verified afterthe-fact. TAPS further argues that failing
to verify the costs of imports presents a
greater opportunity and incentive for
generators to exercise market power.
TAPS presents a hypothetical example
of a market participant that owns
generators both inside and outside of an
RTO/ISO and asserts that such a market
participant could use its external
generators to make import offers above
$1,000/MWh that its internal generators
would not be permitted to make. TAPS
states that, if the market participant’s
external resource sets the LMP in the
RTO/ISO (i.e., as an import), all of that
market participant’s internal resources
would receive infra-marginal rents.
Monitoring Unit must verify that cost-based
incremental energy offers above $1,000/MWh
reasonably reflect a resource’s actual or expected
costs.’’).
52 See supra P 22.
53 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
P 83.
54 TAPS Request for Clarification/Rehearing at
12–15.
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According to TAPS, such behavior
would be difficult to monitor because
Order No. 831 does not require cost
information from external resources.
TAPS therefore argues that, on
rehearing, the Commission should
prevent import offers above $1,000/
MWh from setting LMP in the importing
RTO/ISO unless the import offer costs
are verified in advance, and that the
Commission should only permit uplift
payments to imports that have been
cost-verified after-the-fact.55
b. Determination
31. We deny TAPS’ request for
rehearing regarding the treatment of
imports. In Order No. 831, the
Commission found that exempting
incremental energy offers from imports
above $1,000/MWh from the verification
requirement was justified because
imports are not similarly situated to
internal resources.56 Because they are
not similarly situated, it was not
arbitrary or capricious to treat import
offers from external resources
differently than offers from internal
resources. Specifically, the Commission
found that internal resources and
imports are not similarly situated
because, based on the record,57 it may
be impossible to identify the costs
underlying an import offer because they
are not resource-specific. Further, Order
No. 831 remains consistent with current
market power mitigation measures in
RTOs/ISOs that generally apply to
internal resources but not to imports.
32. With respect to TAPS’ proposed
alternative which would prevent import
offers above $1,000/MWh from setting
LMP if the costs cannot be verified, we
reject it because, as supported in the
record,58 we continue to find that such
a prohibition could discourage imports
at times when they are most needed to
provide additional supply and increased
competition.59 Further, as the
Commission explained in Order No.
831, such a prohibition could also result
in uneconomic flows between RTOs/
ISOs.60
33. In Order No. 831, the Commission
also considered market power concerns
similar to those raised by TAPS in its
rehearing request, but did not find that
they warranted requiring costverification for import offers above
$1,000/MWh. The Commission
explained that because ‘‘market
participants can import energy from
55 Id.
at 12–16.
No. 831, FERC Stats. & Regs. ¶ 31,387 at
56 Order
P 195.
57 See, e.g., id. PP 180, 183, 185.
58 See, e.g., id. PP 179, 181, 188–189.
59 Id. P 193.
60 Id. P 194.
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adjacent markets and sell that energy in
the RTO/ISO energy market . . . it is
difficult for external resources in an
adjacent market to withhold.’’ 61 The
hypothetical example TAPS presents in
its request for rehearing does not
persuade us otherwise. First, and as the
Commission explained in Order No.
831, it is unlikely that a resourcespecific import transaction can
successfully withhold energy from the
destination market because any
resource-specific import transaction is
also competing against an import
transaction that simply buys from the
export market at the prevailing export
market price. Second, the import offer
in that example would only benefit a
market participant that owns a fleet of
internal and external generation (which
is online and being compensated at the
LMP in TAPS’ hypothetical example) if
the import offer actually cleared the
importing RTO/ISO’s energy market.
However, such an import offer would
only clear this market at a price above
$1,000/MWh if it were below the
verified cost-based incremental energy
offers of other internal resources and
below other import offers. Thus, such an
import would be beneficial to the
importing RTO/ISO market as it would
lower the clearing price compared to a
situation without it. Therefore, TAPS’
example demonstrates that imports can
lower an importing RTO/ISO’s LMP,
which supports the Commission’s
rationale for allowing import offers
above $1,000/MWh to set LMP.62 For
these additional reasons, we find that
the regulations regarding the treatment
of imports in Order No. 831 are just and
reasonable and not arbitrary and
capricious and reject TAPS’ proposal to
prevent import offers above $1,000/
MWh from setting LMP in the importing
RTO/ISO unless the import offer’s costs
have been verified. For similar reasons,
we deny TAPS’ proposal regarding
uplift payments to imports. Finally, we
note that in Order No. 831, the
Commission stated it would consider
RTO/ISO proposals under FPA section
205 to verify or otherwise review the
costs of imports or exports and/or
develop additional mitigation
provisions for import and export
transactions with offers above $1,000/
MWh.63
61 Id.
P 196.
No. 831 does not apply to emergency
purchases, such as emergency import purchases.
See id. P 198.
63 Id. P 197.
62 Order
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C. Costs Included in Cost-Based
Incremental Energy Offers
1. Requests for Rehearing/Clarification
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34. Exelon requests clarification, and
alternatively rehearing, that the
Commission did not intend to exclude
any particular categories of variable
costs, particularly those not tied to the
price of the commodity associated with
the resource’s fuel supply. Exelon
asserts that a resource’s cost-based
incremental energy offer is comprised
not only of those costs linked to the
price of fuel, but also of other variable
costs, including but not limited to
balancing costs and transportation costs.
Exelon states that if the Commission
does not grant its requested
clarification, then it seeks rehearing on
the basis that exclusion of other variable
costs from cost-based incremental
energy offers would lead to an unjust
and unreasonable result.64
35. TAPS requests clarification, and
alternatively rehearing, regarding
whether opportunity costs may be
recovered in addition to the $100/MWh
adder.65 TAPS asserts that in Order No.
831, the Commission did not respond to
the arguments it raised in response to
the NOPR, did not explicitly state
whether the $100/MWh adder includes
opportunity costs, and did not state
whether RTOs/ISOs can allow
opportunity costs when developing
their verification methodologies. TAPS
asks the Commission to clarify that if an
RTO/ISO allows adders, the maximum
total amount of such adders, including
both opportunity costs and any other
difficult-to-quantify costs, cannot
exceed $100/MWh. TAPS asserts that, if
the Commission intended to permit
RTOs/ISOs to propose verification
methodologies that allow for the
recovery of opportunity costs in
addition to the $100/MWh adder, the
Commission should grant rehearing
because opportunity costs should not be
allowed under the ‘‘extreme’’ price
levels at issue in this proceeding.66
36. NYISO requests that the
Commission clarify that, when
calculating uplift payments for the
64 Exelon Request for Clarification/Rehearing at
4–6, 7–8 (citing Motor Vehicle Mfrs. Ass’n, 463 U.S.
at 43; NorAm Gas Transmission Co. v. FERC, 148
F.3d 1158, 1165 (D.C. Cir. 1998); PPL Wallingford
Energy LLC v. FERC, 419 F.3d 1194, 1198 (D.C. Cir.
2005)).
65 TAPS Request for Clarification/Rehearing at 2
(citing Canadian Ass’n of Petroleum Producers, 254
F.3d 289).
66 Id. at 16–18 (citing PJM Interconnection, L.L.C.,
126 FERC ¶ 61,145, at P 28 n.34 (2009) (‘‘The
opportunity cost associated with providing ‘must
run’ output is the value associated with the lost
opportunity to produce energy during a higher
valued time period within the year.’’)).
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recovery of verified costs, only actual,
documented out-of-pocket costs should
be paid after-the-fact and that no riskrelated adders or opportunity costs be
allowed when cost information is not
submitted in a sufficiently timely
manner to permit review and
verification. NYISO states that it is
concerned that the submission of
legitimate, verifiable costs that exceed
the $1,000/MWh offer cap close in time
to the day-ahead or real-time market
close could deny NYISO sufficient time
to perform cost verification. NYISO
states that this could cause the
resource’s offer to be mitigated to a level
that does not include the unverified,
additional costs and could cause the
resource to be committed when it would
not have otherwise been or receive a
larger schedule than it otherwise would
have. NYISO asserts that its requested
clarification would ensure all resources
have an incentive to submit timely
information to the RTO/ISO.67
2. Determination
37. We deny Exelon’s request for
clarification, and alternatively
rehearing, regarding whether the
verification requirement intended to
exclude particular categories of actual or
expected costs, particularly variable
costs that are non-fuel related costs. In
Order No. 831, the Commission neither
required RTOs/ISOs to change the
methodologies they currently use to
develop cost-based offers in order to
satisfy the verification requirement nor
prescribed the specific types of shortrun marginal costs that could be
included in cost-based incremental
energy offers above $1,000/MWh. We do
not prejudge what types of costs RTOs/
ISOs may propose as part of their
compliance filings.
38. We deny TAPS’ request for
clarification, and alternatively
rehearing, regarding whether the $100/
MWh limit on adders applies to
opportunity costs. Opportunity costs are
legitimate short-run marginal costs and
not adders above cost. Cost-based
incremental energy offers based on
opportunity costs may currently set
LMP in many RTOs/ISOs. Given that, in
Order No. 831, the Commission did not
require RTOs/ISOs to change the
specific costs that they permit resources
to include in cost-based incremental
energy offers, resources in RTOs/ISOs
that permit the use of opportunity costs
in this manner may continue to do so
after implementing Order No. 831.
Because opportunity costs should be
considered part of a cost-based
67 NYISO Request for Clarification/Rehearing at
15–16.
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53409
incremental energy offer, whether or not
the offer exceeds $1,000/MWh,
verifiable opportunity costs should not
be subject to the $100/MWh limit on
adders above cost. We do not prejudge
the validity of including verifiable
opportunity costs in cost-based
incremental offers above $1,000/MWh
or the verification methods of such costs
that RTOs/ISOs may propose as part of
their compliance filings. We also reject
TAPS’ argument that the Commission
failed to meaningfully address its
arguments stating that opportunity costs
should not be permitted at the
‘‘extreme’’ prices contemplated in this
rulemaking.68 As stated above, in a
rulemaking, the Commission need not
respond to every comment or analyze
every alternative.69 As explained here,
opportunity costs are legitimate shortrun marginal costs that should be
considered part of a cost-based
incremental energy offer, regardless of
whether that offer exceeds $1,000/MWh.
Some current RTO/ISO practices permit
cost-based incremental energy offers
based on opportunity costs to set LMP,
and the Commission in Order No. 831
did not require RTOs/ISOs to change
which costs they may include in costbased incremental energy offers.
Therefore, TAPS’ comments would not
have resulted in a change in the rule.
39. We grant NYISO’s request for
clarification regarding the calculation of
uplift payments. Resources are only
eligible to receive uplift payments to
make them whole to, at most, their
submitted cost-based incremental
energy offers if the associated offer and
cost information is submitted in a
sufficiently timely manner and verified
by the RTO/ISO, meaning offers and
supporting information must be
provided consistent with RTO/ISO offer
submission guidelines and approved by
the RTO/ISO or Market Monitoring
Unit. Consistent with Order No. 831, the
after-the-fact uplift payment that a
resource would be eligible to receive if
its cost-based incremental energy offer
above $1,000/MWh is not verified prior
to market clearing shall include only
actual verifiable costs. We agree with
NYISO that opportunity costs, like other
costs, must be submitted in a timely
manner. However, we clarify that if a
resource avails itself of an RTO’s/ISO’s
current rules to allow a resource to
include opportunity costs in its costbased incremental energy offer, then
that RTO/ISO must give that resource an
68 TAPS Request for Clarification/Rehearing at
17–18.
69 See supra P 12 (citing American Min. Congress,
907 F.2d at 1187–88; (citing Thompson, 741 F.2d
at 408; ACLU, 823 F.2d at 1581)).
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opportunity to recover those
opportunity costs through an uplift
payment, subject to verification. We
further clarify that a resource may not
receive uplift payments for incremental
energy costs in excess of the costs
included in its verified incremental
energy offer. That is, a resource may not
submit a cost-based incremental energy
offer based on expected costs prior to
the market clearing process and
subsequently receive uplift payments to
make it whole to an offer above the
$/MWh level(s) of its offer(s).70 In this
instance, allowing a resource to receive
uplift in excess of its verified cost-based
incremental energy offer could give that
resource the incentive to submit offers
that do not reflect its actual short-run
marginal costs and could thus result in
inefficient resource selection.
40. Further, such after-the-fact uplift
payments may not include any adders
above cost, including risk related
adders, because actual costs are known
after-the-fact.71 This finding is
consistent with Commission precedent
regarding PJM’s requests for waivers of
certain tariff provisions related to its
offer cap.72
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III. Information Collection Statement
41. The Paperwork Reduction Act
(PRA) 73 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,74 in
turn, require approval of certain
information collection requirements
imposed by agency rules.
42. The Commission is amending its
regulations to clarify what the
Commission already required in Order
No. 831—that either actual or expected
costs included in incremental energy
offers above $1,000/MWh may be
submitted for verification. The
Commission estimates that there will be
no net change to burden.
70 For example, a resource may not submit a
$2,300/MWh offer based on expected short-run
marginal cost that is verified and clears the market
and receive uplift associated with incremental
energy costs above $2,300/MWh, even if that
resource’s actual short-run marginal cost, based on
an after-the-fact review, is $2,500/MWh.
71 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
P 146.
72 In the 2015 PJM offer cap order, the
Commission found that ‘‘the 10 percent adder
[above costs] is unjust and unreasonable as applied
to ex post review of documented costs, because the
cost [sic] are no longer uncertain.’’ See PJM
Interconnection L.L.C., 153 FERC ¶ 61,289, at P 31
(2015). See also PJM Interconnection, L.L.C., 149
FERC ¶ 61,059, at P 13 (2014).
73 44 U.S.C. 3501–3520.
74 5 CFR 1320 (2017).
VerDate Sep<11>2014
14:33 Nov 15, 2017
Jkt 244001
43. Interested persons may obtain
information on the reporting
requirements by contacting: 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 requirements
of this rule may also be sent to the
Office of Information and Regulatory
Affairs, Office of Management and
Budget, Washington, DC 20503
[Attention: Desk Officer for the Federal
Energy Regulatory Commission]. For
security reasons, comments should be
sent by email to OMB at oira_
submission@omb.eop.gov. Comments
submitted to OMB should refer to
FERC–516C and OMB Control Number
1902–0287.
IV. Regulatory Flexibility Act
Certification
47. 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.
VI. Effective Date
48. These regulations are effective
January 16, 2018.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities,
Non-discriminatory open access
transmission tariffs.
By the Commission.
Issued: November 9, 2017.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Regulatory Text
44. The Regulatory Flexibility Act of
1980 (RFA) 75 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. The Commission has
determined that there will not be a
significant impact on a substantial
number of small entities, therefore these
requirements under the RFA do not
apply.
In consideration of the foregoing, the
Commission amends part 35, chapter I,
title 18, Code of Federal Regulations, as
follows:
V. Document Availability
*
45. 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 (https://
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.
46. 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.
75 5
PO 00000
U.S.C. 601–12.
Frm 00014
Fmt 4700
Sfmt 4700
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. Revise § 35.28(g)(9) to read as
follows:
■
§ 35.28 Non-discriminatory open access
transmission tariff.
*
*
*
*
(g) * * *
(9) A resource’s incremental energy
offer must be capped at the higher of
$1,000/MWh or that resource’s costbased incremental energy offer. For the
purpose of calculating Locational
Marginal Prices, Regional Transmission
Organizations and Independent System
Operators must cap cost-based
incremental energy offers at $2,000/
MWh. The actual or expected costs
underlying a resource’s cost-based
incremental energy offer above $1,000/
MWh must be verified before that offer
can be used for purposes of calculating
Locational Marginal Prices. If a resource
submits an incremental energy offer
above $1,000/MWh and the actual or
expected costs underlying that offer
cannot be verified before the market
clearing process begins, that offer may
not be used to calculate Locational
Marginal Prices and the resource would
be eligible for a make-whole payment if
that resource is dispatched and the
E:\FR\FM\16NOR1.SGM
16NOR1
Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations
resource’s actual costs are verified afterthe-fact. A resource would also be
eligible for a make-whole payment if it
is dispatched and its verified cost-based
incremental energy offer exceeds
$2,000/MWh. All resources, regardless
of type, are eligible to submit cost-based
incremental energy offers in excess of
$1,000/MWh.
[FR Doc. 2017–24803 Filed 11–15–17; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF THE INTERIOR
Office of Surface Mining Reclamation
and Enforcement
30 CFR Part 917
[KY–254–FOR; OSM–2011–0005;
S1D1SSS08011000SX064A000189S180110;
S2D2SSS08011000SX066A00018XS501520]
Kentucky Regulatory Program
Office of Surface Mining
Reclamation and Enforcement (OSMRE),
Interior.
ACTION: Final rule; approval of
amendment.
AGENCY:
We are approving an
amendment to the Kentucky regulatory
program (hereinafter, the ‘‘Kentucky
program’’) under the Surface Mining
Control and Reclamation Act of 1977
(SMCRA or the Act). Kentucky
submitted a proposed amendment to
OSMRE that includes revisions to the
Kentucky Revised Statutes (KRS) as
authorized by House Bill 385 (HB 385),
regarding bonding of surface coal
mining and reclamation operations.
DATES: The effective date is December
18, 2017.
FOR FURTHER INFORMATION CONTACT:
Robert Evans, Telephone: (859) 260–
3900. Email: bevans@osmre.gov.
SUPPLEMENTARY INFORMATION:
SUMMARY:
I. Background on the Kentucky Program
II. Description of the Amendment
III. OSMRE’s Findings
IV. Summary and Disposition of Comments
V. OSMRE’s Decision
VI. Procedural Determinations
nshattuck on DSK9F9SC42PROD with RULES
I. Background on the Kentucky
Program
Section 503(a) of the Act permits a
State to assume primacy for the
regulation of surface coal mining and
reclamation operations on non-Federal
and non-Indian lands within its borders
by demonstrating that its program
includes, among other things, State laws
and regulations that govern surface coal
mining and reclamation operations in
accordance with the Act and consistent
VerDate Sep<11>2014
14:33 Nov 15, 2017
Jkt 244001
with the Federal regulations. See 30
U.S.C. 1253(a)(1) and (7). On the basis
of these criteria, the Secretary of the
Interior conditionally approved the
Kentucky program on May 18, 1982.
You can find background information
on the Kentucky program, including the
Secretary’s findings, the disposition of
comments, and conditions of approval
of the Kentucky program in the May 18,
1982, Federal Register (47 FR 21404,
21434). You can also find later actions
concerning Kentucky’s program and
program amendments at 30 CFR 917.11,
917.12, 917.13, 917.15, 917.16, and
917.17.
II. Description of the Proposed
Amendment
On May 10, 2011, Kentucky submitted
an amendment to OSMRE for approval
that proposed bonding revisions to the
KRS as authorized by HB 385, which
passed during the State’s regular 2011
legislative session. HB 385 was passed
in response to OSMRE’s findings in its
January 5, 2011, National Priority
Oversight Evaluation of the Adequacy of
Kentucky Reclamation Performance
Bond Amounts (National Oversight
Study) report. In that report, OSMRE
oversight and programmatic reviews
identified that current reclamation
performance bonds in Kentucky are not
sufficient to complete the reclamation
required in approved permits. On
February 3, 2011, the Kentucky
Department for Natural Resources
(KYDNR) and OSMRE signed an Action
Plan detailing the steps necessary for
correcting identified bond calculation
deficiencies. The Action Plan required
KYDNR to complete revised bonding
protocols by April 1, 2011, along with
a timetable for implementation for new
and existing permits. HB 385 amends
Kentucky Revised Statutes 350.060 to
provide that:
Within thirty (30) days of a cabinet
determination of a need to change a bond
protocol currently in use, the cabinet shall
immediately promulgate administrative
regulations setting forth bonding
requirements including, but not limited to,
requirements for the amount, duration,
release, and forfeiture of bonds. Bond
protocols shall not be exempt from KRS
13A.100 and shall be established by
promulgating administrative regulations
under KRS Chapter 13A. Failure to include
the formula for establishing the amount of
the bond in any administrative regulation on
bonding requirements shall be deemed a
failure to comply with the prescriptions of
this section and the administrative regulation
shall automatically be declared deficient in
accordance with KRS Chapter 13A.
We announced receipt of the
amendment and asked for comments in
a Federal Register notice published on
PO 00000
Frm 00015
Fmt 4700
Sfmt 4700
53411
August 15, 2011 (76 FR 50436). In the
same document, we opened the public
comment period and provided an
opportunity for a public hearing or
meeting. We did not hold a public
hearing or meeting because no one
requested one. The public comment
period ended on September 14, 2011.
We received comments from two
organizations.
III. OSMRE’s Findings
The following are the findings we
made concerning Kentucky’s proposed
amendment under SMCRA at Section
509, 30 U.S.C. 1259 and the Federal
regulations at 30 CFR 800.14 and
800.15.
KRS 350.060 (11) Processing Permit
Applications
The new language in KRS 350.060
(11) is intended to ensure that bond
protocol regulations include the formula
for establishing the amount of the bond.
Failure to do so would result in any
administrative regulations or bonding
requirements to be declared deficient
automatically, in accordance with KRS
Chapter 13A.
While these proposed State revisions
have no direct Federal counterparts
there is no provision in SMCRA or its
implementing regulations that prohibits
a State from requiring its bond protocols
to be implemented solely as regulations.
On their face, the proposed revisions are
not inconsistent with Section 509 of
SMCRA and 30 CFR 800.14, and we are
therefore approving them, as noted
below.
While HB 385 could be construed to
require the KYDNR to implement all
bond adjustments as regulations before
the adjustments can be made, to do so
would be inconsistent with the literal
construction of the language of the bill.
Therefore, we do not construe HB 385
to apply to individual bonding
adjustments, or other individual
bonding decisions.
Rather, we are approving the
proposed amendment, in accordance
with its plain language, which will not
impede implementation of the
requirement in Section 509 of SMCRA
that ‘‘[t]he amount of the bond shall be
sufficient to assure the completion of
the reclamation plan if the work had to
be performed by the regulatory authority
in the event of forfeiture.’’ Nor will the
proposed amendment impede the
obligation of the regulatory authority to
adjust the amount of bond in
accordance with 30 CFR 800.15. Should
we find, however, during oversight, that
the amendment is being interpreted in
a manner that would render it
inconsistent with either Section 509 of
E:\FR\FM\16NOR1.SGM
16NOR1
]]>Agencies
[Federal Register Volume 82, Number 220 (Thursday, November 16, 2017)]
[Rules and Regulations]
[Pages 53403-53411]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-24803]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM16-5-001; Order No. 831-A]
Offer Caps in Markets Operated by Regional Transmission
Organizations and Independent System Operators
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Order on rehearing and clarification.
-----------------------------------------------------------------------
SUMMARY: The Federal Energy Regulatory Commission is granting in part
and denying in part requests for rehearing and clarification of its
determinations in Order No. 831, which amended its regulations to
address incremental energy offer caps in markets operated by regional
transmission organizations and independent system operators.
DATES: This rule is effective January 16, 2018.
FOR FURTHER INFORMATION CONTACT:
Emma Nicholson (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-8846, emma.nicholson@ferc.gov
Pamela Quinlan (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-6179, pamela.quinlan@ferc.gov
Anne Marie Hirschberger (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502-8387, annemarie.hirschberger@ferc.gov
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph Nos.
I. Introduction...................................... 1
II. Discussion....................................... 5
A. Offer Cap Structure........................... 5
1. Hard Cap Level............................ 6
2. Implementation of the Hard Cap............ 13
B. Verification Requirement...................... 18
1. Expected Costs............................ 19
2. Verification of Imports................... 30
C. Costs Included in Cost-Based Incremental 34
Energy Offers...................................
1. Requests for Rehearing/Clarification...... 34
2. Determination............................. 37
III. Information Collection Statement................ 41
IV. Regulatory Flexibility Act Certification......... 44
V. Document Availability............................. 45
VI. Effective Date................................... 48
I. Introduction
1. On November 17, 2016, the Federal Energy Regulatory Commission
(Commission) issued Order No. 831.\1\ Order No. 831 addresses the
incremental energy offer component of a resource's supply offer, which
is a financial component consisting of costs that vary with a
resource's output or level of demand reduction. Incremental energy
offers are one of the components used to calculate locational marginal
prices (LMPs). California Independent System Operator Corporation
(CAISO), ISO New England Inc. (ISO-NE), Midcontinent Independent System
Operator, Inc. (MISO), New York Independent System Operator, Inc.
(NYISO), and Southwest Power Pool, Inc. (SPP) currently have a $1,000/
MWh cap on incremental energy offers (offer cap), and PJM
Interconnection, L.L.C. (PJM) currently has an offer cap of $2,000/MWh
on cost-based offers.\2\
---------------------------------------------------------------------------
\1\ Offer Caps in Markets Operated by Regional Transmission
Organizations and Independent System Operators, 81 FR 87,770 (Dec.
5, 2016), FERC Stats. & Regs. ] 31,387 (2016) (Order No. 831).
\2\ Order No. 831, FERC Stats. & Regs. ] 31,387 at PP 11-13.
---------------------------------------------------------------------------
2. In Order No. 831, the Commission amended its regulations to
require that each regional transmission organization and independent
system operator (RTO/ISO): (1) Cap each resource's incremental energy
offer at the higher of $1,000/MWh or that resource's verified cost-
based incremental energy offer; and (2) cap verified cost-based
incremental energy offers at $2,000/MWh when calculating LMPs (hard
cap).\3\ Resources with verified cost-based incremental energy offers
above $2,000/MWh will be eligible to receive uplift.\4\ In response to
comments on the Notice of Proposed
[[Page 53404]]
Rulemaking,\5\ the Commission clarified that each RTO/ISO or Market
Monitoring Unit must verify that any incremental energy offer above
$1,000/MWh reasonably reflects the associated resource's actual or
expected costs, as opposed to only the resource's actual costs, prior
to using that offer to calculate LMP.\6\
---------------------------------------------------------------------------
\3\ Id. P 1.
\4\ Id. P 78.
\5\ Offer Caps in Markets Operated by Regional Transmission
Organizations and Independent System Operators, 81 FR 5951 (Feb. 4,
2016), FERC Stats. & Regs. ] 32,714, at PP 3 (2016) (NOPR).
\6\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 139.
---------------------------------------------------------------------------
3. With respect to treatment of cost-based incremental energy
offers above $2,000/MWh, the Commission stated that it expects RTOs/
ISOs to use such offers to determine merit-order dispatch, and it cited
PJM as an example of an RTO/ISO that uses cost-based incremental energy
offers above $2,000/MWh to determine merit-order dispatch, but limits
cost-based incremental energy offers to $2,000/MWh for purposes of
calculating LMP.\7\ The Commission found that imports should be
permitted to offer above $1,000/MWh, but will not be subject to
verification.\8\ Finally, while Order No. 831 did not require RTOs/ISOs
to include an adder above cost in cost-based incremental energy offers
above $1,000/MWh, the Commission stated that if an RTO/ISO chooses to
retain existing rules that allow for an adder above cost or proposes
any new adders above cost, such adders may not exceed $100/MWh.\9\
However, in Order No. 831, the Commission did not require RTOs/ISOs to
change the costs they currently include in cost-based incremental
energy offers, and it did not address whether verifiable opportunity
costs are subject to the $100/MWh limit on adders.
---------------------------------------------------------------------------
\7\ Id. P 90.
\8\ Id. P 192.
\9\ Id. P 207.
---------------------------------------------------------------------------
4. On December 19, 2016, the Commission received four requests for
rehearing and/or clarification of Order No. 831 which raise issues
related to the structure of the offer cap, the verification
requirement, and the costs included in cost-based incremental energy
offers. TAPS filed a request for rehearing and clarification. NYISO
filed a request for clarification and, alternatively, request for
rehearing. AMP/APPA filed a request for rehearing. Exelon filed a
motion for clarification and request for rehearing.\10\ For the reasons
discussed below, we grant in part and deny in part the requests for
rehearing and clarification.
---------------------------------------------------------------------------
\10\ The Independent Market Monitor for PJM (PJM Market Monitor)
filed an answer to Exelon's motion for clarification and request for
rehearing. MISO filed comments in support of NYISO's request for
clarification and, alternatively, request for rehearing. Rule
713(d)(1) of the Commission's Rules of Practice and Procedure
prohibits answers to requests for rehearing. 18 CFR 385.713(d)(2)
(2017). We therefore reject the answer of the PJM Market Monitor. We
will treat MISO's comments as an answer and as a result reject them.
---------------------------------------------------------------------------
II. Discussion
A. Offer Cap Structure
5. The requests for rehearing and clarification regarding the offer
cap structure focus on the level of the hard cap and the implementation
of the hard cap.
1. Hard Cap Level
a. Request for Rehearing
6. TAPS seeks rehearing and argues both that the $2,000/MWh hard
cap level established by the Commission is not supported by substantial
evidence, and that the $1,724/MWh offer cited in Order No. 831 was not
a legitimate cost-based incremental energy offer.\11\ Rather, TAPS
states, the $1,724/MWh offer was the estimated cost of a resource
calculated according to PJM's Cost Development Guidelines, but the
actual cost of that resource was less than $1,500/MWh. TAPS argues
that, given the large discrepancy between estimated and actual costs,
it was inappropriate for the Commission to rely on an estimated $1,724/
MWh offer as the basis for the $2,000/MWh hard cap level. TAPS asserts
that, even if it was appropriate for the Commission to rely upon
estimated costs, the Commission should not have used the $1,724/MWh
level, since it was estimated using a methodology that is not compliant
with Order No. 831. TAPS contends that the Commission should instead
set the hard cap level at $1,500/MWh or, alternatively, at $1,800/MWh
if the Commission determines that there was a legitimate cost-based
incremental energy offer of $1,724/MWh.\12\ TAPS also argues that the
Commission failed to meaningfully address the analytical evidence TAPS
presented in its comments supporting a $1,500/MWh hard cap.\13\
---------------------------------------------------------------------------
\11\ TAPS Request for Clarification/Rehearing at 2 (citing Pac.
Gas & Elec. Co. v. FERC, 373 F.3d 1315 (D.C. Cir. 2004); Canadian
Ass'n of Petroleum Producers v. FERC, 254 F.3d 289 (D.C. Cir. 2001)
(Canadian Ass'n of Petroleum Producers)).
\12\ Id. at 5-11.
\13\ Id. at 10 (citing Canadian Ass'n of Petroleum Producers,
254 F.3d at 299 (an agency's ``failure to respond meaningfully'' to
objections raised by a party renders its decision arbitrary and
capricious)).
---------------------------------------------------------------------------
b. Determination
7. We deny TAPS' request for rehearing of the $2,000/MWh level of
the hard cap. In Order No. 831, the Commission determined that a hard
cap was necessary to limit any adverse impact on LMPs due to imperfect
information about a resource's short-run marginal costs that might
arise during the verification process.\14\ The Commission also
recognized that a hard cap that is too low might suppress LMPs below
the marginal cost of production.\15\ In determining the $2,000/MWh
level of the hard cap, the Commission therefore struck a balance
between competing goals: (1) Limiting any adverse impacts on LMPs due
to imperfect information during the verification process and (2)
reducing the likelihood of suppressing LMPs below the marginal cost of
production.
---------------------------------------------------------------------------
\14\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 87.
\15\ Id. P 91.
---------------------------------------------------------------------------
8. The overall offer cap structure set forth in Order No. 831 and
the overall market structure of RTOs/ISOs in which the offers arise
affected the balance struck by the Commission in setting the level of
the hard cap. The hard cap does not stand alone, meaning that it is not
the only way of ensuring that an offer does not reflect the exercise of
market power and that the price resulting from an incremental energy
offer is just and reasonable. In balancing the competing goals, the
Commission effectively recognized that the hard cap serves as a
backstop to the mitigation established through both the cost-based
requirement and the verification process--the other elements of the
offer cap structure. The cost-based offer requirement serves a
``mitigation function'' \16\ by requiring incremental energy offers
above $1,000/MWh be cost-based. The verification requirement also
addresses market power concerns.\17\ The hard cap ``limit[s] the
adverse impact that any imperfect information about resources' short-
run marginal costs during the verification process could have on
LMPs.'' \18\ The Commission factored in these two other elements of the
offer-cap structure in balancing the competing goals to set the level
of the hard cap.
---------------------------------------------------------------------------
\16\ Id. P 83.
\17\ Id. P 139.
\18\ Id. P 87.
---------------------------------------------------------------------------
9. In setting that level, the Commission also considered the
overall market structure of RTOs/ISOs--a structure designed to ensure
that markets are competitive and not subject to the exercise of market
power, through for instance, existing market power mitigation
processes.\19\ The hard cap
[[Page 53405]]
also serves as backstop to those existing market mitigation
processes.\20\
---------------------------------------------------------------------------
\19\ Cf. id. PP 85-90. Additionally, all six RTOs/ISOs have
market power mitigation rules designed to prevent market
participants from exercising market power. See, e.g., California
Independent System Operator Corporation, eTariff, 39; ISO New
England Inc., Markets and Services Tariff, Market Rule 1, Appendix
A; Midcontinent Independent System Operator, Inc., FERC Electric
Tariff, Module D; New York Independent System Operator, Inc., Market
Administration and Control Area Services Tariff, Attachment H; PJM
Interconnection, L.L.C., Intra-PJM Tariffs, OATT, Tariff Operating
Agreement, Attachment M; and Southwest Power Pool, Inc., OATT, Sixth
Revised Volume No. 1, Attachment AF.
\20\ Cf. id. P 89.
---------------------------------------------------------------------------
10. Based on the record, the Commission set the level of the hard
cap to $2,000/MWh. The Commission determined that $2,000/MWh was the
level that short-run marginal costs would rarely exceed.\21\ The cost-
based incremental energy offer of $1,724/MWh referenced in Order No.
831, and which TAPS questions, regardless of the methodology by which
it was derived, was only one point of reference for the Commission
within the context of the broader record. Specifically, the Commission
also examined the evidence in the record regarding high natural gas
prices that occurred during the Polar Vortex when some resources
experienced short-run marginal costs above $1,000/MWh.\22\
---------------------------------------------------------------------------
\21\ See id. n.200 (citing Envtl. Action, Inc. v. FERC, 939 F.2d
1057, 1064 (D.C. Cir. 1991) (``it is within the scope of the
agency's expertise to make such a prediction about the market it
regulates, and a reasonable prediction deserves our deference
notwithstanding that there might also be another reasonable
view.''). See also Michigan Consol. Gas Co. v. FERC, 883 F.2d 117,
124 (1989) (``It is also quite clear FERC may make predictions--
``[m]aking . . . predictions is clearly within the Commission's
expertise'' and will be upheld if ``rationally based on record
evidence.'') (citing East Tennessee Natural Gas Co. v. FERC, 863
F.2d 932, 938-39 (1988) (citing Associated Gas Distributors v. FERC,
824 F.2d 981, 1008 (1987)))).
\22\ Id. P 92.
---------------------------------------------------------------------------
11. The alternative $1,500/MWh and $1,800/MWh hard cap levels that
TAPS proposed would result in a balance different than the one chosen
by the Commission. Lower hard cap levels such as these would increase
the likelihood of suppressing prices below the marginal cost of
production and would thereby run contrary to the Commission's price
formation efforts to ensure that LMPs reflect the short-run marginal
cost of the marginal resource. We therefore reject TAPS' request for
rehearing and the alternative hard cap levels proposed. As stated
above, we continue to find that the $2,000/MWh hard cap reasonably
balances reducing the likelihood of suppressing LMPs while limiting any
adverse impact on LMPs from imperfect information about resources'
short-run marginal costs during the verification process.
12. Further, we reject TAPS' argument that the Commission failed to
meaningfully address its $1,500/MWh alternative proposal. The
Commission addressed this alternative in adopting the $2,000/MWh hard
cap.\23\ In any event, in a rulemaking, the Commission need not respond
to every comment or analyze every alternative. Rather, the Commission
must respond to ``comments which, if true. . .would require a change in
an agency's proposed rule.'' \24\ The Commission's determination
regarding the $2,000/MWh hard cap is not invalidated merely because
there may be a reasonable alternative.\25\
---------------------------------------------------------------------------
\23\ Id.
\24\ American Min. Congress v. EPA, 907 F.2d 1179, 1187-88 (D.C.
Cir. 1990) (American Min. Congress) (citing Thompson v. Clark, 741
F.2d 401, 408 (D.C. Cir. 1984) (Thompson); ACLU v. FCC, 823 F.2d
1554, 1581 (D.C. Cir.1987) (ACLU)).
\25\ See United Distribution Cos. v. FERC, 88 F.3d 1105, 1169-70
(D.C. Cir. 1996) (United Distribution Cos.) (``FERC correctly
counters that the fact that AEPCO may have proposed a reasonable
alternative . . . is not compelling. The existence of a second
reasonable course of action does not invalidate an agency's
determination.'').
---------------------------------------------------------------------------
2. Implementation of the Hard Cap
a. Requests for Rehearing/Clarification
13. NYISO seeks clarification that Order No. 831 does not require
that incremental energy offers above $2,000/MWh be used to determine
merit-order dispatch in all RTOs/ISOs, and, in the alternative, seeks
rehearing on this issue.\26\ NYISO states that, to the extent the
Commission intended to establish a requirement, the Commission did not
seek comment on the requirement in the NOPR, did not demonstrate that
the requirement must be imposed on all RTOs/ISOs in order to ensure
just and reasonable rates, and did not consider the burdens the
requirement would impose on NYISO.\27\
---------------------------------------------------------------------------
\26\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at P 90
(``With respect to the treatment of cost-based incremental energy
offers above $2,000/MWh, we expect RTOs/ISOs to use such offers to
determine merit-order dispatch. We note that the Commission allowed
this approach when accepting PJM's current offer cap structure. . .
.'' '').
\27\ NYISO Request for Clarification/Rehearing at 5, 11-13.
---------------------------------------------------------------------------
14. NYISO asserts that such a requirement would introduce foreign
market design elements into NYISO that were developed by PJM to be
compatible with its own pricing method, market rules, and software.\28\
Specifically, NYISO explains that PJM's design accommodates
discrepancies between schedules and price, using a secondary ex post
process to determine LMPs that is separate from the process for
determining resource schedules. However, NYISO states that it uses a
common ex ante process to determine both locational based marginal
prices (LBMPs) and resource schedules. NYISO asserts that, because its
process utilizes the same offers for scheduling and pricing, it would
be challenging to allow resources to be committed and scheduled based
on validated incremental energy offers above $2,000/MWh, but then cap
the offers for purposes of calculating LBMPs and ancillary services
prices. According to NYISO, this would require resource-intensive and
potentially costly software changes, make validation of prices and
schedules more complex, and require NYISO to redirect resources from
other efforts that are more certain to benefit consumers and markets.
Additionally, NYISO contends that implementing an offer cap that only
limits the offer prices used to determine LBMPs can lead to a
divergence between resource schedules and prices that can harm market
participants.\29\
---------------------------------------------------------------------------
\28\ NYISO also maintains that RTOs/ISOs do not need to have
identical software or market rules, and that the practical ability
to implement software changes justifies accommodating regional
circumstances. Id. at 6 (citing N.Y. Indep. Sys. Operator, Inc., 142
FERC ] 61,202, at PP 24-26 (2013); N.Y. Indep. Sys. Operator, Inc.,
133 FERC ] 61,246, at P 25 (2010)).
\29\ Id. at 7-11.
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15. In addition, NYISO requests clarification that RTOs/ISOs are
permitted to apply the same offer cap to both incremental energy and
minimum generation offers,\30\ and in the alternative seeks rehearing
on this issue. Currently, NYISO's tariff applies a $1,000/MWh offer cap
to all day-ahead and real-time energy offers, including minimum
generation offers. NYISO argues that applying different offer caps to
incremental energy offers and minimum generation offers could
incentivize suppliers to artificially shape their offers to conform to
the different offer caps rather than offer in a manner that accurately
reflects a resource's costs, which would result in less optimal
commitment, dispatch, and pricing. Furthermore, NYISO states that if
minimum generation offer caps are lower than incremental energy offer
caps, generators may not offer to supply energy if they do not expect
to be able to recoup their costs.\31\ NYISO also states that the
Commission previously granted waiver of the $1,000/MWh offer cap on
both incremental energy offers and minimum generation offers in
[[Page 53406]]
response to spikes in natural gas costs caused by the Polar Vortex.\32\
---------------------------------------------------------------------------
\30\ In NYISO, the first block in a resource's incremental
energy offer is called a ``minimum generation bid'' and includes the
costs a resource incurs to operate at its economic minimum operating
level. NYISO, Manual 11--Day-Ahead Scheduling Manual, Sec. 4.3.3.
(October 2016) https://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_and_Guides/Manuals/Operations/dayahd_schd_mnl.pdf.
\31\ NYISO Request for Clarification/Rehearing at 13-15.
\32\ Id. at 13 (citing N.Y. Indep. Sys. Operator, Inc., 146 FERC
] 61,061, at PP 2-4, 20 (2014)).
---------------------------------------------------------------------------
b. Determination
16. Regarding NYISO's concerns on economic merit-order dispatch, we
clarify that Order No. 831 did not require cost-based incremental
energy offers above $2,000/MWh to be used to determine economic merit-
order dispatch. We recognize that some RTO's/ISO's existing commitment,
dispatch, and pricing algorithms are structured differently, and the
Commission in Order No. 831 did not require RTOs/ISOs to change their
current practices or software to use cost-based incremental energy
offers above $2,000/MWh for determining economic merit-order dispatch.
However, in the event that RTOs/ISOs must select from several offers
above $2,000/MWh, we encourage RTOs/ISOs to make those selections on a
least-cost basis when possible, in order to minimize the cost to serve
load.
17. We also clarify that application of the offer cap and
verification requirement adopted in Order No. 831 to minimum generation
offers, as NYISO requests, is appropriate. Applying different offer
caps to minimum generation and incremental energy offers could give
resources the incentive to shape their offers in a manner that does not
reflect their costs.\33\ Furthermore, this application is consistent
with prior Commission orders regarding NYISO's offer cap discussed
above.\34\
---------------------------------------------------------------------------
\33\ See id. at 14.
\34\ See supra P 15.
---------------------------------------------------------------------------
B. Verification Requirement
18. The requests for rehearing regarding the verification
requirement focus on the use of expected costs in the verification
requirement and whether to subject imports to the verification
requirement.
1. Expected Costs
19. The requests for rehearing regarding expected costs include the
definition of expected costs and whether they should be included in the
regulatory text as well as market power concerns related to the use of
expected costs in the verification process.
a. Definition and Regulatory Text
i. Requests for Rehearing
20. AMP/APPA seek rehearing of Order No. 831, arguing that the
Commission was arbitrary and capricious because it failed to provide a
reasonable justification for allowing sellers' expected costs to set
LMP, and that the Commission also unjustifiably expanded the definition
of cost-based offers to include ``expected'' costs. According to AMP/
APPA, in order for LMPs to send accurate signals regarding the actual
cost of producing energy, LMPs should be based on actual costs. AMP/
APPA argue that, since some commenters stated that pre-verification of
actual costs would not be possible, the Commission should have
concluded that offers above $1,000/MWh should not set LMP, and instead,
required such costs to be recovered via uplift.\35\
---------------------------------------------------------------------------
\35\ AMP/APPA Request for Rehearing at 9-13 (citing Motor
Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29,
43 (1983) (Motor Vehicle Mfrs. Ass'n); United Distrib. Cos., 88 F.3d
at 1169).
---------------------------------------------------------------------------
21. Exelon requests rehearing of the fact that the regulatory text
does not include the ``actual or expected'' phrase when it describes
the costs to be verified. Exelon argues that the current regulatory
text fails to adequately capture the Commission's intent described in
the preamble, specifically that costs may be either actual or expected.
Exelon asserts that, in order to avoid confusion and also satisfy due
process and regulatory notice requirements, the Commission should amend
the regulatory text to specify that the verified costs can be ``actual
or expected.'' \36\
---------------------------------------------------------------------------
\36\ Exelon Request for Clarification/Rehearing at 6-8 (citing
U.S. v. Chrysler Corp., 158 F.3d 1350 (D.C. Cir. 1998); Upton v.
SEC, 75 F.3d 92 (2d Cir. 1996); General Electric Co. v. EPA, 53 F.3d
1324 (D.C. Cir. 1995)).
---------------------------------------------------------------------------
ii. Determination
22. We disagree with AMP/APPA's argument that the use of expected
costs in the verification process to set LMPs was arbitrary and
capricious, and thus deny its request for rehearing. The record
demonstrates that certain natural gas resources do not know their
actual short-run marginal costs at the time they submit their
incremental energy offers, and thus it is just and reasonable, and
consistent with current practice, for such resources to offer based on
their expected costs.\37\ Given this record, the Commission
appropriately responded to the many comments filed by clarifying in
Order No. 831 that market participants could offer based on expected
costs. In circumstances when actual costs are not known, a resource
offer based on expected short-run marginal cost constitutes a
competitive offer. Further, contrary to AMP/APPA's assertion, in Order
No. 831 the Commission did not expand the definition of the specific
types of short-run marginal costs that a resource could include in its
cost-based incremental energy offer above $1,000/MWh, but rather, the
Commission stated that it expected that the RTO/ISO would build on its
existing mitigation processes for calculating or updating cost-based
incremental energy offers. Further, in Order No. 831, the Commission
required an RTO/ISO to explain in its compliance filing what factors it
will consider in the verification process for cost-based incremental
energy offers above $1,000/MWh and whether such factors are currently
considered in existing market power mitigation provisions. Thus, the
Commission was not arbitrary and capricious because its decision to
permit verified expected costs above $1,000/MWh to set LMP is
consistent with current RTO/ISO practices that allow cost-based
incremental energy offers to be based on expected, rather than actual
costs, as demonstrated in the record.\38\
---------------------------------------------------------------------------
\37\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at PP 104-
108.
\38\ See id. PP 106-107.
---------------------------------------------------------------------------
23. We grant Exelon's request to amend the regulatory text by
adding the words ``actual or expected'' as suggested by Exelon. We
agree that these revisions will provide more certainty to market
participants and more clearly state the Commission's intention that
both actual and expected costs over $1,000/MWh may be submitted for
verification.
b. Market Power Concerns
i. Requests for Rehearing
24. AMP/APPA seek rehearing contending that Order No. 831 is
arbitrary and capricious because it fails to address market power
concerns that may arise if resources exaggerate expected costs included
in cost-based incremental energy offers above $1,000/MWh.\39\ According
to AMP/APPA, there are strong incentives for an owner of a fleet of
resources, for example, to inflate expected costs of one resource
during a constrained period in order to increase earnings for all of
its resources. AMP/APPA further argue that there is an opportunity to
inflate costs because natural gas prices are higher during constrained
periods, and this is also when the price of natural gas is less
transparent because the price paid by a market seller for gas on the
bilateral market is farthest away from index prices.\40\
---------------------------------------------------------------------------
\39\ AMP/APPA Request for Rehearing at 13-16 (citing Motor
Vehicle Mfrs. Ass'n, 463 U.S. at 43).
\40\ Id. at 13-15 (citing Joint Comments of PJM and SPP, Docket
No. RM16-5-000, at 10-11 (filed Apr. 4, 2016); Comments of ISO-NE
Market Monitor, Docket No. RM16-5-000, at 7 (filed Apr. 4, 2016)).
---------------------------------------------------------------------------
25. AMP/APPA further assert that Order No. 831 failed to address
whether
[[Page 53407]]
allowing offers above $1,000/MWh to set LMP could lead to market power
concerns in the natural gas market.\41\ In support of this position,
AMP/APPA reference the PJM Market Monitor's comments in the Order No.
831 proceeding stating that removing the offer cap entirely could
exacerbate market power in the natural gas markets and also impact
electricity markets.\42\ AMP/APPA further note that the Internal Market
Monitor for ISO-NE (ISO-NE Market Monitor) stated that, in ISO-NE.,
raising the offer cap could expose the energy markets to uncompetitive
conditions in the natural gas markets.\43\ AMP/APPA therefore propose
that offers above $1,000/MWh should be based upon actual costs in order
to be used to set LMP, since the use of expected costs can exacerbate
market power concerns, but offers above $1,000/MWh based on expected
costs should be recovered via uplift.\44\
---------------------------------------------------------------------------
\41\ Id. at 15-16.
\42\ Id. at 15 (citing PJM Market Monitor, Comments, Docket No.
RM16-5-000, at 4 (filed Apr. 4, 2016)).
\43\ Id. (citing ISO-NE Market Monitor, Comments, Docket No.
RM16-5-000, at 3 (filed Apr. 4, 2016)).
\44\ Id. at 17.
---------------------------------------------------------------------------
26. AMP/APPA seek rehearing of Order No. 831, arguing that the
Commission's use of expected costs in setting LMP was arbitrary and
capricious, and that the Commission did not explain its departure from
relevant precedent.\45\ Specifically, AMP/APPA argue that allowing
expected costs to be used to verify cost-based incremental energy
offers above $1,000/MWh contravenes the Federal Power Act (FPA) and is
inconsistent with precedent requiring certain safeguards when granting
market-based rates. AMP/APPA maintain that the Commission's authority
under the FPA to grant market-based rate authority has been upheld in
court because the Commission periodically conducts ex ante examinations
of a public utility's market power as well as enforceable ex post
reporting.\46\ According to AMP/APPA, however, Order No. 831 never
requires RTOs/ISOs or Market Monitors to ensure that the market-
clearing LMPs resulting from a seller's offer exceeding $1,000/MWh are
actually cost-based. AMP/APPA assert that permitting verification based
on expected costs does not meet the ex post reporting requirement that
would allow the Commission to determine whether these expected costs
and resulting market-clearing prices are just and reasonable. AMP/APPA
therefore conclude that Order No. 831 is unlawful because the
Commission cannot rely on market forces to regulate rates in lieu of
imposing reporting requirements on generators.\47\
---------------------------------------------------------------------------
\45\ Id. at 8 (citing PSEG Energy Res. & Trade LLC v. FERC, 665
F.3d 203, 208 (D.C. Cir. 2011); Motor Vehicle Mfrs. Ass'n, 463 U.S.
at 43; FCC v. Fox Television Stations, 556 U.S. 502, 515 (2009)).
\46\ Id. at 5 (citing California ex rel. Lockyer v. FERC, 383
F.3d 1006, 1013-14 (9th Cir. 2004)).
\47\ Id. at 6-8 (citing Blumenthal v. FERC, 552 F.3d 875, 882-83
(D.C. Cir. 2009); FPC v. Texaco, 417 U.S. 380, 399 (1974)).
---------------------------------------------------------------------------
ii. Determination
27. We deny AMP/APPA's request for rehearing and alternative
proposal regarding market power concerns and the use of expected costs.
We disagree with AMP/APPA that incremental energy offers above $1,000/
MWh based on expected costs present market power concerns; the
verification requirement in Order No. 831 was specifically designed to
address market power concerns and ensure that all incremental energy
offers above $1,000/MWh are indeed cost-based. Pursuant to the
verification requirement, resources may only submit incremental energy
offers above $1,000/MWh if they are cost-based, and the RTO/ISO or
Market Monitoring Unit must verify that any such offer reasonably
reflects that resource's actual or expected short-run marginal costs.
Incremental energy offers above $1,000/MWh may not be used to calculate
LMPs if such offers cannot be verified by the RTO/ISO or Market
Monitoring Unit prior to the market clearing process. In Order No. 831,
the Commission specifically found that ``the verification requirement
reasonably addresses market power concerns associated with incremental
energy offers above $1,000/MWh because such offers will be required to
be cost-based, which should deter attempts by resources to exercise
market power.'' \48\ The verification requirement in Order No. 831 is
therefore designed to prevent the concerns AMP/APPA raise about
resources including ``inflated'' or ``exaggerated'' expected costs in
cost-based incremental energy offers above $1,000/MWh.
---------------------------------------------------------------------------
\48\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at P 144.
---------------------------------------------------------------------------
28. We reject as unsupported AMP/APPA's claim that the Final Rule
did not address concerns about market power in the natural gas market.
The excerpts from the PJM Market Monitor's and ISO-NE Market Monitor's
comments that AMP/APPA included in its request for rehearing expressed
general concern about removing a hard cap in energy markets given
potential concerns about market power in natural gas markets. However,
Order No. 831 did not remove a hard cap in energy markets--it adopted a
$2,000/MWh hard cap. As discussed above, we balanced several
considerations in adopting a $2,000/MWh but the fact that a hard cap
continues to remain in place addresses the comments AMP/APPA cites, to
the extent there is market power in the natural gas markets.
Additionally, the excerpt from the ISO-NE Market Monitor's comments
cited by AMP/APPA discusses the relationship between natural gas
markets and energy markets and expresses general concerns about limited
transparency into the competitive conditions in natural gas spot
markets. Again, the $2,000/MWh hard cap addresses this concern as it
recognizes that the verification process required by Order No. 831 may
be less effective during extreme conditions in the natural gas
market.\49\
---------------------------------------------------------------------------
\49\ See id. P 87.
---------------------------------------------------------------------------
29. We deny AMP/APPA's request for rehearing regarding market-based
rates because Order No. 831 does not depart from Commission precedent,
and the Commission's action was not arbitrary and capricious. Contrary
to AMP/APPA's claims, a market participant with market-based rate
authority that submits a cost-based incremental offer above $1,000/MWh
for a resource would continue to be subject to the existing reporting
and other requirements that are imposed on entities with market-based
rate authority,\50\ consistent with the precedent cited by AMP/APPA.
Further, contrary to AMP/APPA's assertions, the verification process
specifically requires that the RTO/ISO or Market Monitoring Unit ensure
that incremental energy offers are in fact cost-based, meaning that the
offer must reasonably reflect that resource's actual or expected short-
run marginal costs.\51\
[[Page 53408]]
As discussed above, the record demonstrates that it is appropriate to
use expected costs in the verification of cost-based incremental energy
offers because when actual costs are not known, a resource offer based
on expected short-run marginal cost constitutes a competitive
offer.\52\ In Order No. 831, the Commission stated that ``[a] cost-
based incremental energy offer is based on the associated resource's
short-run marginal cost, which constitutes a competitive offer free
from the exercise of market power.'' \53\ Therefore, the use of
expected costs in the verification process does in fact allow the
Commission to determine whether the resulting market clearing prices
would be just and reasonable.
---------------------------------------------------------------------------
\50\ For example, entities with market-based rate authority must
file Electric Quarterly Reports with the Commission, consistent with
Order Nos. 2001 and 768. Revised Public Utility Filing Requirements,
Order No. 2001, FERC Stats. & Regs. ] 31,127, reh'g denied, Order
No. 2001-A, 100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100
FERC ] 61,342, order directing filing, Order No. 2001-C, 101 FERC ]
61,314 (2002), order directing filing, Order No. 2001-D, 102 FERC ]
61,334, order refining filing requirements, Order No. 2001-E, 105
FERC ] 61,352 (2003), order on clarification, Order No. 2001-F, 106
FERC ] 61,060 (2004), order revising filing requirements, Order No.
2001-G, 120 FERC ] 61,270, order on reh'g and clarification, Order
No. 2001-H, 121 FERC ] 61,289 (2007), order revising filing
requirements, Order No. 2001-I, FERC Stats. & Regs. ] 31,282 (2008);
Elec. Mkt. Transparency Provisions of Section 220 of the Fed. Power
Act, Order No. 768, FERC Stats. & Regs. ] 31,336 (2012), order on
reh'g, Order No. 768-A, 143 FERC ] 61,054 (2013). They must also
timely report to the Commission any change in status that would
reflect a departure from the characteristics the Commission relied
upon in granting their market-based rate authority. 18 CFR 35.42
(2017).
\51\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at P 140
(``[A]n RTO/ISO or a Market Monitoring Unit must verify that cost-
based incremental energy offers above $1,000/MWh reasonably reflect
a resource's actual or expected costs.'').
\52\ See supra P 22.
\53\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 83.
---------------------------------------------------------------------------
2. Verification of Imports
a. Request for Rehearing
30. TAPS seeks rehearing of Order No. 831's exemption of all
imports from the verification requirement for incremental energy offers
above $1,000/MWh and asserts that it is unjust and unreasonable and
arbitrary, and that it puts internal and external resources on unequal
footing.\54\ According to TAPS, the Commission's finding that some
imports are not resource-specific and therefore cannot have their costs
verified does not support exempting all imports from the verification
requirement. Therefore, TAPS proposes that only resource-specific
imports whose costs are verified by the receiving RTO/ISO should be
able to set LMP, while other imports with offers above $1,000/MWh that
are not verified should receive uplift payments if their costs are
verified after-the-fact. TAPS further argues that failing to verify the
costs of imports presents a greater opportunity and incentive for
generators to exercise market power. TAPS presents a hypothetical
example of a market participant that owns generators both inside and
outside of an RTO/ISO and asserts that such a market participant could
use its external generators to make import offers above $1,000/MWh that
its internal generators would not be permitted to make. TAPS states
that, if the market participant's external resource sets the LMP in the
RTO/ISO (i.e., as an import), all of that market participant's internal
resources would receive infra-marginal rents. According to TAPS, such
behavior would be difficult to monitor because Order No. 831 does not
require cost information from external resources. TAPS therefore argues
that, on rehearing, the Commission should prevent import offers above
$1,000/MWh from setting LMP in the importing RTO/ISO unless the import
offer costs are verified in advance, and that the Commission should
only permit uplift payments to imports that have been cost-verified
after-the-fact.\55\
---------------------------------------------------------------------------
\54\ TAPS Request for Clarification/Rehearing at 12-15.
\55\ Id. at 12-16.
---------------------------------------------------------------------------
b. Determination
31. We deny TAPS' request for rehearing regarding the treatment of
imports. In Order No. 831, the Commission found that exempting
incremental energy offers from imports above $1,000/MWh from the
verification requirement was justified because imports are not
similarly situated to internal resources.\56\ Because they are not
similarly situated, it was not arbitrary or capricious to treat import
offers from external resources differently than offers from internal
resources. Specifically, the Commission found that internal resources
and imports are not similarly situated because, based on the
record,\57\ it may be impossible to identify the costs underlying an
import offer because they are not resource-specific. Further, Order No.
831 remains consistent with current market power mitigation measures in
RTOs/ISOs that generally apply to internal resources but not to
imports.
---------------------------------------------------------------------------
\56\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 195.
\57\ See, e.g., id. PP 180, 183, 185.
---------------------------------------------------------------------------
32. With respect to TAPS' proposed alternative which would prevent
import offers above $1,000/MWh from setting LMP if the costs cannot be
verified, we reject it because, as supported in the record,\58\ we
continue to find that such a prohibition could discourage imports at
times when they are most needed to provide additional supply and
increased competition.\59\ Further, as the Commission explained in
Order No. 831, such a prohibition could also result in uneconomic flows
between RTOs/ISOs.\60\
---------------------------------------------------------------------------
\58\ See, e.g., id. PP 179, 181, 188-189.
\59\ Id. P 193.
\60\ Id. P 194.
---------------------------------------------------------------------------
33. In Order No. 831, the Commission also considered market power
concerns similar to those raised by TAPS in its rehearing request, but
did not find that they warranted requiring cost-verification for import
offers above $1,000/MWh. The Commission explained that because ``market
participants can import energy from adjacent markets and sell that
energy in the RTO/ISO energy market . . . it is difficult for external
resources in an adjacent market to withhold.'' \61\ The hypothetical
example TAPS presents in its request for rehearing does not persuade us
otherwise. First, and as the Commission explained in Order No. 831, it
is unlikely that a resource-specific import transaction can
successfully withhold energy from the destination market because any
resource-specific import transaction is also competing against an
import transaction that simply buys from the export market at the
prevailing export market price. Second, the import offer in that
example would only benefit a market participant that owns a fleet of
internal and external generation (which is online and being compensated
at the LMP in TAPS' hypothetical example) if the import offer actually
cleared the importing RTO/ISO's energy market. However, such an import
offer would only clear this market at a price above $1,000/MWh if it
were below the verified cost-based incremental energy offers of other
internal resources and below other import offers. Thus, such an import
would be beneficial to the importing RTO/ISO market as it would lower
the clearing price compared to a situation without it. Therefore, TAPS'
example demonstrates that imports can lower an importing RTO/ISO's LMP,
which supports the Commission's rationale for allowing import offers
above $1,000/MWh to set LMP.\62\ For these additional reasons, we find
that the regulations regarding the treatment of imports in Order No.
831 are just and reasonable and not arbitrary and capricious and reject
TAPS' proposal to prevent import offers above $1,000/MWh from setting
LMP in the importing RTO/ISO unless the import offer's costs have been
verified. For similar reasons, we deny TAPS' proposal regarding uplift
payments to imports. Finally, we note that in Order No. 831, the
Commission stated it would consider RTO/ISO proposals under FPA section
205 to verify or otherwise review the costs of imports or exports and/
or develop additional mitigation provisions for import and export
transactions with offers above $1,000/MWh.\63\
---------------------------------------------------------------------------
\61\ Id. P 196.
\62\ Order No. 831 does not apply to emergency purchases, such
as emergency import purchases. See id. P 198.
\63\ Id. P 197.
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[[Page 53409]]
C. Costs Included in Cost-Based Incremental Energy Offers
1. Requests for Rehearing/Clarification
34. Exelon requests clarification, and alternatively rehearing,
that the Commission did not intend to exclude any particular categories
of variable costs, particularly those not tied to the price of the
commodity associated with the resource's fuel supply. Exelon asserts
that a resource's cost-based incremental energy offer is comprised not
only of those costs linked to the price of fuel, but also of other
variable costs, including but not limited to balancing costs and
transportation costs. Exelon states that if the Commission does not
grant its requested clarification, then it seeks rehearing on the basis
that exclusion of other variable costs from cost-based incremental
energy offers would lead to an unjust and unreasonable result.\64\
---------------------------------------------------------------------------
\64\ Exelon Request for Clarification/Rehearing at 4-6, 7-8
(citing Motor Vehicle Mfrs. Ass'n, 463 U.S. at 43; NorAm Gas
Transmission Co. v. FERC, 148 F.3d 1158, 1165 (D.C. Cir. 1998); PPL
Wallingford Energy LLC v. FERC, 419 F.3d 1194, 1198 (D.C. Cir.
2005)).
---------------------------------------------------------------------------
35. TAPS requests clarification, and alternatively rehearing,
regarding whether opportunity costs may be recovered in addition to the
$100/MWh adder.\65\ TAPS asserts that in Order No. 831, the Commission
did not respond to the arguments it raised in response to the NOPR, did
not explicitly state whether the $100/MWh adder includes opportunity
costs, and did not state whether RTOs/ISOs can allow opportunity costs
when developing their verification methodologies. TAPS asks the
Commission to clarify that if an RTO/ISO allows adders, the maximum
total amount of such adders, including both opportunity costs and any
other difficult-to-quantify costs, cannot exceed $100/MWh. TAPS asserts
that, if the Commission intended to permit RTOs/ISOs to propose
verification methodologies that allow for the recovery of opportunity
costs in addition to the $100/MWh adder, the Commission should grant
rehearing because opportunity costs should not be allowed under the
``extreme'' price levels at issue in this proceeding.\66\
---------------------------------------------------------------------------
\65\ TAPS Request for Clarification/Rehearing at 2 (citing
Canadian Ass'n of Petroleum Producers, 254 F.3d 289).
\66\ Id. at 16-18 (citing PJM Interconnection, L.L.C., 126 FERC
] 61,145, at P 28 n.34 (2009) (``The opportunity cost associated
with providing `must run' output is the value associated with the
lost opportunity to produce energy during a higher valued time
period within the year.'')).
---------------------------------------------------------------------------
36. NYISO requests that the Commission clarify that, when
calculating uplift payments for the recovery of verified costs, only
actual, documented out-of-pocket costs should be paid after-the-fact
and that no risk-related adders or opportunity costs be allowed when
cost information is not submitted in a sufficiently timely manner to
permit review and verification. NYISO states that it is concerned that
the submission of legitimate, verifiable costs that exceed the $1,000/
MWh offer cap close in time to the day-ahead or real-time market close
could deny NYISO sufficient time to perform cost verification. NYISO
states that this could cause the resource's offer to be mitigated to a
level that does not include the unverified, additional costs and could
cause the resource to be committed when it would not have otherwise
been or receive a larger schedule than it otherwise would have. NYISO
asserts that its requested clarification would ensure all resources
have an incentive to submit timely information to the RTO/ISO.\67\
---------------------------------------------------------------------------
\67\ NYISO Request for Clarification/Rehearing at 15-16.
---------------------------------------------------------------------------
2. Determination
37. We deny Exelon's request for clarification, and alternatively
rehearing, regarding whether the verification requirement intended to
exclude particular categories of actual or expected costs, particularly
variable costs that are non-fuel related costs. In Order No. 831, the
Commission neither required RTOs/ISOs to change the methodologies they
currently use to develop cost-based offers in order to satisfy the
verification requirement nor prescribed the specific types of short-run
marginal costs that could be included in cost-based incremental energy
offers above $1,000/MWh. We do not prejudge what types of costs RTOs/
ISOs may propose as part of their compliance filings.
38. We deny TAPS' request for clarification, and alternatively
rehearing, regarding whether the $100/MWh limit on adders applies to
opportunity costs. Opportunity costs are legitimate short-run marginal
costs and not adders above cost. Cost-based incremental energy offers
based on opportunity costs may currently set LMP in many RTOs/ISOs.
Given that, in Order No. 831, the Commission did not require RTOs/ISOs
to change the specific costs that they permit resources to include in
cost-based incremental energy offers, resources in RTOs/ISOs that
permit the use of opportunity costs in this manner may continue to do
so after implementing Order No. 831. Because opportunity costs should
be considered part of a cost-based incremental energy offer, whether or
not the offer exceeds $1,000/MWh, verifiable opportunity costs should
not be subject to the $100/MWh limit on adders above cost. We do not
prejudge the validity of including verifiable opportunity costs in
cost-based incremental offers above $1,000/MWh or the verification
methods of such costs that RTOs/ISOs may propose as part of their
compliance filings. We also reject TAPS' argument that the Commission
failed to meaningfully address its arguments stating that opportunity
costs should not be permitted at the ``extreme'' prices contemplated in
this rulemaking.\68\ As stated above, in a rulemaking, the Commission
need not respond to every comment or analyze every alternative.\69\ As
explained here, opportunity costs are legitimate short-run marginal
costs that should be considered part of a cost-based incremental energy
offer, regardless of whether that offer exceeds $1,000/MWh. Some
current RTO/ISO practices permit cost-based incremental energy offers
based on opportunity costs to set LMP, and the Commission in Order No.
831 did not require RTOs/ISOs to change which costs they may include in
cost-based incremental energy offers. Therefore, TAPS' comments would
not have resulted in a change in the rule.
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\68\ TAPS Request for Clarification/Rehearing at 17-18.
\69\ See supra P 12 (citing American Min. Congress, 907 F.2d at
1187-88; (citing Thompson, 741 F.2d at 408; ACLU, 823 F.2d at
1581)).
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39. We grant NYISO's request for clarification regarding the
calculation of uplift payments. Resources are only eligible to receive
uplift payments to make them whole to, at most, their submitted cost-
based incremental energy offers if the associated offer and cost
information is submitted in a sufficiently timely manner and verified
by the RTO/ISO, meaning offers and supporting information must be
provided consistent with RTO/ISO offer submission guidelines and
approved by the RTO/ISO or Market Monitoring Unit. Consistent with
Order No. 831, the after-the-fact uplift payment that a resource would
be eligible to receive if its cost-based incremental energy offer above
$1,000/MWh is not verified prior to market clearing shall include only
actual verifiable costs. We agree with NYISO that opportunity costs,
like other costs, must be submitted in a timely manner. However, we
clarify that if a resource avails itself of an RTO's/ISO's current
rules to allow a resource to include opportunity costs in its cost-
based incremental energy offer, then that RTO/ISO must give that
resource an
[[Page 53410]]
opportunity to recover those opportunity costs through an uplift
payment, subject to verification. We further clarify that a resource
may not receive uplift payments for incremental energy costs in excess
of the costs included in its verified incremental energy offer. That
is, a resource may not submit a cost-based incremental energy offer
based on expected costs prior to the market clearing process and
subsequently receive uplift payments to make it whole to an offer above
the $/MWh level(s) of its offer(s).\70\ In this instance, allowing a
resource to receive uplift in excess of its verified cost-based
incremental energy offer could give that resource the incentive to
submit offers that do not reflect its actual short-run marginal costs
and could thus result in inefficient resource selection.
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\70\ For example, a resource may not submit a $2,300/MWh offer
based on expected short-run marginal cost that is verified and
clears the market and receive uplift associated with incremental
energy costs above $2,300/MWh, even if that resource's actual short-
run marginal cost, based on an after-the-fact review, is $2,500/MWh.
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40. Further, such after-the-fact uplift payments may not include
any adders above cost, including risk related adders, because actual
costs are known after-the-fact.\71\ This finding is consistent with
Commission precedent regarding PJM's requests for waivers of certain
tariff provisions related to its offer cap.\72\
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\71\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 146.
\72\ In the 2015 PJM offer cap order, the Commission found that
``the 10 percent adder [above costs] is unjust and unreasonable as
applied to ex post review of documented costs, because the cost
[sic] are no longer uncertain.'' See PJM Interconnection L.L.C., 153
FERC ] 61,289, at P 31 (2015). See also PJM Interconnection, L.L.C.,
149 FERC ] 61,059, at P 13 (2014).
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III. Information Collection Statement
41. The Paperwork Reduction Act (PRA) \73\ 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,\74\ in turn, require approval of certain information
collection requirements imposed by agency rules.
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\73\ 44 U.S.C. 3501-3520.
\74\ 5 CFR 1320 (2017).
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42. The Commission is amending its regulations to clarify what the
Commission already required in Order No. 831--that either actual or
expected costs included in incremental energy offers above $1,000/MWh
may be submitted for verification. The Commission estimates that there
will be no net change to burden.
43. Interested persons may obtain information on the reporting
requirements by contacting: 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 requirements of
this rule may also be sent to the Office of Information and Regulatory
Affairs, Office of Management and Budget, Washington, DC 20503
[Attention: Desk Officer for the Federal Energy Regulatory Commission].
For security reasons, comments should be sent by email to OMB at
oira_submission@omb.eop.gov. Comments submitted to OMB should refer to
FERC-516C and OMB Control Number 1902-0287.
IV. Regulatory Flexibility Act Certification
44. The Regulatory Flexibility Act of 1980 (RFA) \75\ 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.
The Commission has determined that there will not be a significant
impact on a substantial number of small entities, therefore these
requirements under the RFA do not apply.
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\75\ 5 U.S.C. 601-12.
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V. Document Availability
45. 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 (https://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.
46. 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.
47. 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.
VI. Effective Date
48. These regulations are effective January 16, 2018.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Non-discriminatory open
access transmission tariffs.
By the Commission.
Issued: November 9, 2017.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Regulatory Text
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. Revise Sec. 35.28(g)(9) to read as follows:
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(g) * * *
(9) A resource's incremental energy offer must be capped at the
higher of $1,000/MWh or that resource's cost-based incremental energy
offer. For the purpose of calculating Locational Marginal Prices,
Regional Transmission Organizations and Independent System Operators
must cap cost-based incremental energy offers at $2,000/MWh. The actual
or expected costs underlying a resource's cost-based incremental energy
offer above $1,000/MWh must be verified before that offer can be used
for purposes of calculating Locational Marginal Prices. If a resource
submits an incremental energy offer above $1,000/MWh and the actual or
expected costs underlying that offer cannot be verified before the
market clearing process begins, that offer may not be used to calculate
Locational Marginal Prices and the resource would be eligible for a
make-whole payment if that resource is dispatched and the
[[Page 53411]]
resource's actual costs are verified after-the-fact. A resource would
also be eligible for a make-whole payment if it is dispatched and its
verified cost-based incremental energy offer exceeds $2,000/MWh. All
resources, regardless of type, are eligible to submit cost-based
incremental energy offers in excess of $1,000/MWh.
[FR Doc. 2017-24803 Filed 11-15-17; 8:45 am]
BILLING CODE 6717-01-P
