Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 53403 

1Offer 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). 

2Order No. 831, FERC Stats. & Regs. ¶ 31,387 at 

PP 11–13. 

3 Id. P 1. 

4 Id. P 78. 

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 

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 Energy Offers .............................................................................................. 34 

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

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 


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53404 Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 

5Offer 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). 

6Order No. 831, FERC Stats. & Regs. ¶ 31,387 at 

P 139. 

7 Id. P 90. 

8 Id. P 192. 

9 Id. P 207. 

10The 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. 

11TAPS 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)). 

14Order 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. 

19Cf. 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 

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

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 

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 


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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. 

20Cf. id. P 89. 

21See 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. 

23 Id. 

24American 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)). 

25See 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.’’). 

26See 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. . . .’’ ’’). 

27NYISO Request for Clarification/Rehearing at 5, 

11–13. 

28NYISO 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. 

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) 

http://www.nyiso.com/public/webdocs/markets_

operations/documents/Manuals_and_Guides/ 

Manuals/Operations/dayahd_schd_mnl.pdf. 

31NYISO Request for Clarification/Rehearing at 

13–15. 

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 

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 

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 


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32 Id. at 13 (citing N.Y. Indep. Sys. Operator, Inc., 

146 FERC ¶ 61,061, at PP 2–4, 20 (2014)). 

33See id. at 14. 

34See supra P 15. 

35AMP/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). 

36Exelon 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)). 

37See Order No. 831, FERC Stats. & Regs. ¶ 

31,387 at PP 104–108. 

38See id. PP 106–107. 

39AMP/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)). 

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. 

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

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 shortrun 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 


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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. 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)). 48See Order No. 831, FERC Stats. & Regs. 

¶ 31,387 at P 144. 

49See id. P 87. 

50For 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). 

51See Order No. 831, FERC Stats. & Regs. 

¶ 31,387 at P 140 (‘‘[A]n RTO/ISO or a Market 

Continued 

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 marketclearing 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 

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


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Monitoring Unit must verify that cost-based 

incremental energy offers above $1,000/MWh 

reasonably reflect a resource’s actual or expected 

costs.’’). 

52See supra P 22. 

53Order No. 831, FERC Stats. & Regs. ¶ 31,387 at 

P 83. 

54TAPS Request for Clarification/Rehearing at 

12–15. 

55 Id. at 12–16. 56Order No. 831, FERC Stats. & Regs. ¶ 31,387 at 

P 195. 57See, e.g., id. PP 180, 183, 185. 58See, e.g., id. PP 179, 181, 188–189. 59 Id. P 193. 60 Id. P 194. 

61 Id. P 196. 

62Order No. 831 does not apply to emergency 

purchases, such as emergency import purchases. 

See id. P 198. 

63 Id. P 197. 

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 

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. 

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 

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


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64Exelon 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)). 

65TAPS 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.’’)). 

67NYISO Request for Clarification/Rehearing at 

15–16. 

68TAPS Request for Clarification/Rehearing at 

17–18. 

69See 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)). 

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

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 

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 

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 


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53410 Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 

70For 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. 

71Order 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). 75 5 U.S.C. 601–12. 

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

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. 

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. 

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 (http://

www.ferc.gov) and in FERC’s Public 

Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern 

time) at 888 First Street NE., Room 2A, 

Washington DC 20426. 

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 

■ 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 


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Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 53411 

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 

AGENCY: Office of Surface Mining 

Reclamation and Enforcement (OSMRE), 

Interior. 

ACTION: Final rule; approval of 

amendment. 

SUMMARY: 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: 

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 

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 

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 

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 


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