155 FERC ¶ 61,276

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM15-24-000; Order No. 825]

Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission 

Organizations and Independent System Operators

(Issued June 16, 2016)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule

SUMMARY: The Federal Energy Regulatory Commission (Commission) is revising its 

regulations to address certain practices that fail to compensate resources at prices that 

reflect the value of the service resources provide to the system, thereby distorting price 

signals, and in certain instances, creating a disincentive for resources to respond to 

dispatch signals. We require that each regional transmission organization and 

independent system operator align settlement and dispatch intervals by: (1) settling 

energy transactions in its real-time markets at the same time interval it dispatches energy; 

(2) settling operating reserves transactions in its real-time markets at the same time 

interval it prices operating reserves; and (3) settling intertie transactions in the same time 

interval it schedules intertie transactions. We also require that each regional transmission 

organization and independent system operator trigger shortage pricing for any interval in 

which a shortage of energy or operating reserves is indicated during the pricing of 

resources for that interval. Adopting these reforms will align prices with resource 
Docket No. RM15-24-000 - 2 -

dispatch instructions and operating needs, providing appropriate incentives for resource 

performance.

EFFECTIVE DATE: This rule will become effective 75 days after publication in the 

FEDERAL REGISTER.

FOR FURTHER INFORMATION CONTACT:

Stanley Wolf (Technical Information)

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6841

Stanley.Wolf@ferc.gov

Pamela Quinlan (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE 

Washington, DC 20426

(202) 502-6179

Pamela.Quinlan@ferc.gov

Alicia Cobb (Legal Information) 

Office of the General Counsel – Energy Markets

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8501

Alicia.Cobb@ferc.gov

SUPPLEMENTARY INFORMATION:
155 FERC ¶ 61,276

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Cheryl A. LaFleur, Tony Clark,

and Colette D. Honorable.

Settlement Intervals and Shortage Pricing in Markets 

 Operated by Regional Transmission Organizations and

 Independent System Operators

Docket No. RM15-24-000

ORDER NO. 825 

FINAL RULE

(Issued June 16, 2016)

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction ............................................................................................................................1.

II. Background...........................................................................................................................9.

III. Discussion............................................................................................................................13.

A. Settlement Interval Reform..............................................................................................13.

1. Need for Reform...........................................................................................................13.

2. Settlement Interval Reform for Energy Transactions and Operating Reserves ...........17.

a. Proposal ....................................................................................................................17.

i. Energy Transactions .............................................................................................17.

ii. Operating Reserves..............................................................................................21.

b. Current Practices in the RTOs/ISOs ........................................................................22.

i. Energy Transactions .............................................................................................22.

ii. Operating Reserves .............................................................................................23.

c. Comments on the Proposed Settlement Interval Reform ......................................27.

i. Comments from the RTOs/ISOs...........................................................................28.

ii. Comments by Market Monitors...........................................................................36.

iii. Comments Supporting the Proposed Settlement Interval Reform ....................39.

iv. Comments Opposed to the Proposed Settlement Interval Reform ....................49.

d. Commission Determination .....................................................................................53.
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i. Energy Transactions .............................................................................................53.

ii. Operating Reserves..............................................................................................69.

3. Interties.........................................................................................................................74.

a. Commission Request for Comments........................................................................74.

i. Comments by RTOs/ISOs....................................................................................75.

ii. Comments by Market Monitors ..........................................................................80.

iii. Comments in Support of Applying Settlement Reform to Interties...................82.

iv. Comments Opposed to Applying Settlement Reform to Interties......................86.

b. Commission Determination .....................................................................................88.

4. Demand Response Resources.......................................................................................92.

a. Comments ...............................................................................................................92.

b. Commission Determination ...................................................................................98.

5. Load ..............................................................................................................................100.

a. Comments.................................................................................................................100.

b. Commission Determination .....................................................................................104.

B. Shortage Pricing Reform..................................................................................................105.

1. Need for Reform...........................................................................................................105.

2. NOPR Proposal.............................................................................................................109.

3. Comments on the Proposed Shortage Pricing Reform.................................................110.

a. Comments by RTOs/ISOs........................................................................................110.

b. Comments by Market Monitors...............................................................................121.

c. Comments Supporting the Shortage Pricing Reform ..............................................127.

d. Comments Recommending Changes to the Shortage Pricing Reform ....................137.

e. Comments Opposed to the Proposed Shortage Pricing Reform ..............................141.

4. Commission Determination..........................................................................................161.

C. Compliance and Implementation......................................................................................181.

1. Commission Proposal...................................................................................................181.

2. Comments ....................................................................................................................182.

a. Comments from RTOs/ISOs....................................................................................183.

b. Comments Urging Flexibility in Implementation ...................................................188.

c. Compliance Filing Deadline.....................................................................................191.

d. Implementation Deadline ........................................................................................192.

e. Simultaneous Implementation..................................................................................200.

f. Costs..........................................................................................................................201.

3. Commission Determination..........................................................................................204.

D. Requests Beyond the Scope of this Proceeding ...............................................................211.

1. Comments.....................................................................................................................211.

2. Commission Determination..........................................................................................230.

IV. Information Collection Statement .......................................................................................231.

V. Environmental Analysis .......................................................................................................236.

VI. Regulatory Flexibility Act...................................................................................................237.
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VII. Document Availability.......................................................................................................240.

VIII. Effective Date and Congressional Notification................................................................243.

APPENDIX: List of Commenters.............................................................................................

I. Introduction

1. In this Final Rule, we address certain practices that fail to compensate resources at 

prices that reflect the value of the service resources provide to the system, thereby 

distorting price signals, and in certain instances, creating a disincentive for resources to 

respond to dispatch signals. We require, pursuant to section 206 of the Federal Power 

Act (FPA),1that each regional transmission organization (RTO) and independent system 

operator (ISO) align settlement and dispatch2intervals by: (1) settling energy 

transactions in its real-time markets at the same time interval it dispatches energy; 

(2) settling operating reserves transactions in its real-time markets at the same time 

interval it prices operating reserves;

3

and (3) settling intertie transactions4in the same 

 

1

16 U.S.C. 824e (2012).

2 As mentioned in the Notice of Proposed Rulemaking, the Commission 

sometimes uses the term “dispatch” as shorthand when describing how RTOs/ISOs 

acquire and price energy and operating reserves. With respect to operating reserves, the 

Commission uses dispatch to describe the intervals at which they are acquired and priced. 

See Settlement Intervals and Shortage Pricing in Markets Operated by Regional 

Transmission Organizations and Independent System Operators, 80 Fed. Reg. 58,393 

(Sept. 29, 2015), FERC Stats. & Regs. ¶ 32,710, at P 1 (2015) (NOPR).

3 Operating reserves refer to certain ancillary services procured in the wholesale 

market, although they are often defined differently in each RTO/ISO. Operating reserves 

typically include: (a) Regulating Reserve, used to account for very short-term deviations 

between supply and demand (e.g., 4 to 6 seconds); (b) Spinning, or Synchronous Reserve, 

(continued...)
Docket No. RM15-24-000 - 4 -

time interval it schedules intertie transactions (settlement interval requirements). We also 

require, pursuant to section 206 of the FPA, that each RTO/ISO establish a mechanism to

trigger shortage pricing for any interval in which a shortage of energy or operating 

reserves is indicated during the pricing of resources for that interval (shortage pricing 

requirement). 

2. Some current RTO/ISO settlement practices fail to reflect the value of providing a 

given service, thereby distorting price signals and failing to provide appropriate signals 

for resources to respond to the actual operating needs of the market. One such practice 

occurs when RTOs/ISOs dispatch resources every five minutes but perform settlements 

based on an hourly integrated price, or when RTOs/ISOs schedule intertie transactions 

every fifteen minutes, but perform settlements on an hourly integrated price. This 

misalignment between dispatch and settlement intervals distorts the price signals sent to 

resources and fails to reflect the actual value of resources responding to operating needs 

 

which is capacity held in reserve and synchronized to the grid and able to respond within 

a relatively short amount of time (e.g., within 10 minutes), to be used in case of a 

contingency, such as the loss of a generator; and (c) Non-Spinning Reserve, capacity 

that is not synchronized to the grid and which can take longer to respond (e.g., within 

10-30 minutes) in case of a contingency. Federal Energy Regulatory Commission, 

Price Formation in Organized Wholesale Electricity Markets: Staff Analysis of Shortage 

Pricing, Docket No. AD14-14-000, at 3 n.7 (Oct. 2014), http://www.ferc.gov/legal/staffreports/2014/AD14-14-pricing-rto-iso-markets.pdf (Shortage Pricing Paper). 

4

Intertie transactions are transactions across RTO/ISO borders, including imports, 

exports and wheel-through transactions.
Docket No. RM15-24-000 - 5 -

because compensation will be based on average output and average prices across an hour, 

rather than output and prices during the periods of greatest need within a particular hour. 

3. We also find that a second problem occurs if there is a mismatch between the time 

when a system experiences a shortage of energy and operating reserves and the time 

when prices reflect the shortage condition. This can be particularly problematic when, 

for example, an RTO’s/ISO’s market rules require a shortage to last a minimum time 

period before triggering shortage pricing. In this instance, short-term prices fail to reflect 

system conditions and potential reliability costs, as well as the value of both internal and 

external market resources responding to a dispatch signal. In addition, inaccurate price 

signals are provided to market participants if shortage pricing is still in effect after the 

shortage has been resolved.

4. To address these problems associated with differing dispatch intervals and 

settlement intervals, as well as with shortage pricing triggers, we are setting forth the 

settlement interval requirements and the shortage pricing requirement in this Final Rule.5

These settlement interval and shortage pricing requirements will help ensure that 

resources have price signals that provide incentives to conform their output to dispatch 

instructions, and that prices reflect operating needs at each dispatch interval. 

5. As set forth in the NOPR, we reiterate the goals of price formation are to: 

(1) maximize market surplus for consumer and suppliers; (2) provide correct incentives 

 

5 We are not at this time proposing to change the price paid by any RTO/ISO when 

shortage pricing is triggered. 
Docket No. RM15-24-000 - 6 -

for market participants to follow commitment and dispatch instructions, make efficient 

investments in facilities and equipment, and maintain reliability; (3) provide transparency 

so that market participants understand how prices reflect the actual marginal cost of 

serving load and the operational constraints of reliably operating the system; and, 

(4) ensure that all suppliers have an opportunity to recover their costs.6 

6. As noted in the NOPR, the reforms adopted in this Final Rule advance at least 

two of the Commission’s goals with respect to price formation. First, the proposed 

reforms will help provide correct incentives for market participants to follow 

commitment and dispatch instructions,7to make efficient investments in facilities and 

equipment, and to maintain reliability. Specifically, requiring RTOs/ISOs to align the 

settlement and dispatch intervals will more accurately reward resources that are providing 

energy and ancillary services in periods of the greatest need and will discourage 

provision of energy and ancillary services immediately following periods of system 

stress. Doing so will enhance the incentive to follow an RTO’s/ISO’s dispatch signal and 

thus help maintain system reliability. This reform will also reward resources that can 

 

6

See Notice Inviting Post-Technical Workshop Comments, Docket No. AD14-14-

000, at 1 (Jan. 16, 2015); Notice, Docket No. AD14-14-000 (June 19, 2014).

7

The Commission notes that the reforms proposed herein would further augment 

existing mechanisms in each RTO/ISO market that provide incentives to follow dispatch 

instructions, such as penalties for excessive or deficient energy and the allocation of 

commitment and dispatch costs to deviations from energy dispatch targets. See, e.g., 

MISO, FERC Electric Tariff, §§ 40.3.3(a) (36.0.0) (allocating Revenue Sufficiency 

Guarantee costs to, inter alia, resources providing excessive or deficient energy), 40.3.4 

(33.0.0) (charges for excessive or deficient energy deployment).
Docket No. RM15-24-000 - 7 -

flexibly respond to system needs, thus creating an incentive for resources to make 

efficient investments in facilities and equipment. Similarly, implementing shortage 

pricing for any dispatch interval during which a shortage of energy or operating reserves 

occurs will provide an incentive for resources to ensure that they are available to respond 

to high prices, which should help alleviate shortages and avoid shortage pricing during 

subsequent dispatch intervals. This reform would also ensure that resources operating 

during a shortage are compensated for the value of the service that they provide, 

regardless of whether the shortage is short-lived.

7. Second, the proposed reforms will also help provide transparency and certainty so 

that market participants understand how compensation and prices reflect the actual 

marginal cost of serving load and the operational constraints of reliably operating the 

system. Requiring settlement intervals to match dispatch intervals will make resource 

compensation more transparent by, among other things, increasing the proportion of 

resource payment provided through payments of energy and operating reserves rather 

than uplift. Further, requiring RTOs/ISOs to trigger shortage pricing for an interval in 

which a shortage of energy or operating reserves is indicated during the pricing of 

resources for that interval will ensure that prices transparently reflect the operational 

constraints of reliably operating the system. This increased transparency, in turn, better 

informs decisions to build or maintain resources and enhances consumers’ ability to 

hedge. The benefits summarized above and discussed in detail below would ultimately 

help to ensure just and reasonable rates. 
Docket No. RM15-24-000 - 8 -

8. As discussed below, we require each RTO/ISO to submit a compliance filing with 

the tariff changes needed to implement this Final Rule within 120 days of the Final 

Rule’s effective date. We will allow a further 12 months from the compliance filing date 

for the tariff changes implementing reforms to settlement intervals to be effective, and 

120 days from that same compliance filing date for the tariff changes implementing 

shortage pricing reforms to be effective.8 

II. Background

9. The Commission has addressed price formation in organized markets on prior 

occasions. For example, in Order No. 719, the Commission addressed shortage pricing9

and required RTOs/ISOs to develop and implement shortage pricing rules that would 

apply during operating reserve shortages to “ensure that the market price for energy 

reflects the value of energy during an operating reserve shortage.”10 The Commission 

required such rules out of concern that inappropriate price signals during an operating 

 

8

The Commission has followed a similar approach with the timelines for 

compliance and implementation in the past. See, e.g., Frequency Regulation 

Compensation in the Organized Wholesale Power Markets, Order No. 755, FERC Stats. 

& Regs. ¶ 31,324, at P 201 (2011), reh’g denied, Order No. 755-A, 138 FERC ¶ 61,123 

(2012).

9 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, FERC Stats. & Regs. ¶ 31,281, at PP 192-194 (2008), order on reh’g, Order 

No. 719-A, FERC Stats. & Regs. ¶ 31,292, order on reh’g, Order No. 719-B, 

129 FERC ¶ 61,252 (2009).

10 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194.
Docket No. RM15-24-000 - 9 -

reserve shortage would provide an insufficient incentive for market participants to take 

appropriate actions. 

10. In June 2014, the Commission initiated a proceeding, in Docket No. AD14-14-

000, to evaluate issues regarding price formation in the energy and ancillary services 

markets operated by RTOs/ISOs (price formation proceeding). In the notice initiating 

that proceeding, the Commission stated that there may be opportunities for the 

RTOs/ISOs to improve the energy and ancillary services price formation process. As set 

forth in the notice, locational marginal prices (LMP) and market-clearing prices used in 

energy and ancillary services markets ideally “would reflect the true marginal cost of 

production, taking into account all physical system constraints, and these prices would 

fully compensate all resources for the variable cost of providing service.”

11

 Pursuant to 

the notice, staff conducted outreach and convened technical workshops on the following 

four general issues: (1) use of uplift payments; (2) offer price mitigation and offer price 

caps; (3) scarcity and shortage pricing; and (4) operator actions that affect prices.12 The 

Commission also released staff reports on these topics. In one of those reports, issued in 

October 2014, staff analyzed shortage pricing issues.

13

 

 

11 Notice, Docket No. AD14-14-000, at 2 (June 19, 2014).

12 Id. at 1, 3-4.

13 See Shortage Pricing Paper.
Docket No. RM15-24-000 - 10 -

11. In its January 2015 Notice Inviting Comments, the Commission requested 

comments on questions that arose from the price formation technical workshops.14 In 

response, among other price formation issues, commenters addressed settlement intervals 

and shortage pricing. 

12. On September 17, 2015, the Commission issued a NOPR proposing to require that 

each RTO/ISO: (1) settle energy transactions in its real-time markets at the same time 

interval it dispatches and prices energy, and settle operating reserves transactions in its 

real-time markets at the same time interval it prices operating reserves; and (2) trigger 

shortage pricing for any dispatch interval during which a shortage of energy or operating 

reserves occurs.

15 The Commission sought comments on these proposals, and sought 

comment on: (1) whether settlement interval reforms are appropriate for intertie 

transactions that are scheduled on intervals different from the intervals on which 

RTOs/ISOs dispatch internal real-time energy; and (2) whether it is appropriate to align 

the settlement interval for intertie transactions with external scheduling intervals, e.g., 

fifteen minutes.16 Additionally, the Commission sought comment on whether to require 

that RTOs/ISOs settle real-time operating reserves transactions at the same interval as 

real-time energy dispatch and settlement intervals or whether a settlement interval that 

 

14 Notice Inviting Post-Technical Workshop Comments, Docket No. AD14-14-000 

(Jan. 16, 2015). 

15 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 14.

16 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 39.
Docket No. RM15-24-000 - 11 -

differs from an RTO’s/ISO’s real-time energy dispatch interval would be appropriate for 

some operating reserves transactions.17 Finally, the Commission sought comment on the 

implementation schedule and the costs of implementation.18 A list of commenters and 

the abbreviated names used for them in this Final Rule appears in the Appendix.

III. Discussion

A. Settlement Interval Reform

1. Need for Reform

13. In the NOPR,19 the Commission preliminarily found that the current RTO/ISO 

settlement practice of using hourly integrated prices for real-time settlement and 

five-minute dispatch instructions may fail to reflect the value of providing a given 

service, and may contribute to lack of a response to the actual operating needs of those 

markets. In addition, the Commission stated that the use of hourly integrated prices for 

real-time settlement may discourage resources from following five-minute dispatch 

instructions, and may increase the need for uplift payments. Therefore, the Commission 

preliminarily found that the use of hourly integrated prices for real-time settlement may 

result in rates that are unjust and unreasonable.

14. Commenters generally agree with the Commission’s preliminary finding regarding 

the settlement interval proposal. For example, EPSA states that “[w]hen real-time 

 

17 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 40.

18 NOPR, FERC Stats. & Regs. ¶ 32,710 at PP 56, 60.

19 NOPR, FERC Stats. & Regs. ¶ 32,710 at PP 26-33.
Docket No. RM15-24-000 - 12 -

settlements for generation or dispatchable demand are calculated based on hourly prices 

that are the simple average of sub-hourly prices resulting from the actual dispatch, there 

is a distortion to the real-time price signal impacting both reliability and efficiency.”20 

Similarly, Potomac Economics states that the inconsistency between five-minute dispatch 

instructions and hourly-average price settlement intervals “creates incentives for 

generators to not follow the dispatch signal or to simply be inflexible by a) restricting 

dispatch range (the difference between a generator’s minimum dispatch level and 

maximum dispatch level) or b) offering a slower dispatch ramp rate.”21 Potomac 

Economics notes that while MISO makes uplift payments to generators to alleviate these 

incentive issues, such payments are “an inferior substitute for a true alignment where 

each generator, importer or exporter would settle based on the actual value of energy 

corresponding with its production or transactions in each five-minute interval.”22 

ELCON asserts that hourly prices do not “reflect system needs and costs, and may result 

in over or under recovery of costs depending on how the shortage plays out during the 

hour. When SPP moved to sub-hourly settlements, overall system costs were lower.”23

 

20 EPSA Comments, Pope Aff. at 2-3. 

21 Potomac Economics Comments at 4.

22 Potomac Economics Comments at 4-5.

23 ELCON Comments at 2.
Docket No. RM15-24-000 - 13 -

15. In some instances, commenters assert that the Commission should not affirm its 

preliminary finding on the settlement interval proposal. APPA and NRECA assert that 

Commission approval of any five-minute settlement implementation process should 

require vetting and approval by the RTOs’/ISOs’ stakeholders.24 Direct Energy asserts 

that the Commission should solicit further information from the RTOs/ISOs before 

determining whether or not to direct settlement interval reforms.25

16. Based on analysis of the record, we adopt our preliminary findings, and, as 

described in detail below, conclude that certain RTO/ISO settlement practices are not just 

and reasonable and are unduly discriminatory and preferential. Accordingly, we direct 

each RTO/ISO to align its settlement and dispatch intervals by settling energy 

transactions in its real-time markets at the same time interval it dispatches energy, settling 

operating reserves transactions in its real-time markets at the same time interval it prices 

operating reserves, and settling intertie transactions in the same time interval it schedules 

intertie transactions, as discussed further herein. 

 

24 APPA and NRECA Comments at 4.

25 Direct Energy Comments at 6.
Docket No. RM15-24-000 - 14 -

2. Settlement Interval Reform for Energy Transactions and 

Operating Reserves

a. Proposal

i. Energy Transactions

17. In the NOPR, the Commission proposed to require that each RTO/ISO settle 

energy transactions in its real-time markets at the same time interval it dispatches energy. 

The Commission preliminarily found the use of hourly integrated prices for real-time 

settlement may have the unintended effect of distorting price signals, and, in certain 

instances, contributing to market participants’ failing to respond appropriately to 

operating needs.26 Specifically, the Commission stated that hourly integrated prices for

real-time settlement may: (1) not accurately reflect the value a resource provides to the 

system; (2) discourage resources from following dispatch instructions; and (3) cause 

increased uplift payments. Therefore, the Commission preliminarily found that the use of 

hourly integrated prices for real-time settlement may result in rates that are unjust and 

unreasonable.

18. To remedy any potentially unjust and unreasonable rates caused by the use of 

hourly integrated prices for real-time settlement, the Commission proposed in the NOPR

to require that each RTO/ISO settle energy transactions in its real-time markets at the 

same time interval it dispatches energy.

27

 

 

26 NOPR, FERC Stats. & Regs. ¶ 32,710 at PP 26-33.

27 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.
Docket No. RM15-24-000 - 15 -

19. The Commission explained that in the short-term, the settlement interval proposal 

should improve incentives for resources to respond quickly to dispatch instructions, 

which should in turn lead to operators taking fewer out-of-market actions to ensure that 

supply meets demand. The Commission noted that by improving resources’ response to 

dispatch instructions, the settlement interval proposal would result in a more efficient use 

of generation resources to the benefit of all consumers. In the long-term, the Commission 

maintained that these reforms should provide more accurate price signals, which should 

provide, together with other market price signals, the appropriate incentives to build or 

maintain resources that can respond to energy or operating reserve deficiencies.

28

 

20. In addition, the Commission noted, where settlement and dispatch intervals are 

aligned, resources dispatched economically during high-priced periods would receive 

those higher prices rather than an hourly average of the dispatch interval LMPs, thereby 

reducing the need to make uplift payments. 

ii. Operating Reserves

21. The Commission proposed requiring that each RTO/ISO “settle operating reserves 

transactions in its real-time markets at the same time interval it prices operating 

reserves.”29 Although the Commission noted that dispatch and pricing of energy and 

operating reserves are closely linked through co-optimization in the real-time market, it 

 

28 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 35.

29 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.
Docket No. RM15-24-000 - 16 -

also noted that certain RTOs/ISOs acquire operating reserves on a different time interval 

than they dispatch energy.30 The Commission sought comment on whether the 

Commission should require RTOs/ISOs to settle all real-time operating reserves 

transactions at the same time interval as real-time energy dispatch and settlement 

intervals, or whether a settlement interval that differs from an RTO’s/ISO’s real-time 

energy dispatch interval would be appropriate for some operating reserves transactions.31 

b. Current Practices in the RTOs/ISOs

i. Energy Transactions

22. The following table describes how each RTO/ISO currently dispatches and settles 

real-time energy transactions: 

 

30 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 40. 

31 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 40.
Docket No. RM15-24-000 - 17 -

Table 1: RTO/ISO Dispatch and Settlement Intervals for Energy

ii. Operating Reserves 

23. The RTOs/ISOs vary in how they settle and treat operating reserves. For example, 

CAISO represents that it settles its operating reserve transactions on fifteen-minute 

 

32 See CAISO, eTariff, § 34.5 (17.0.0); ISO-NE, Transmission, Markets and 

Services Tariff, Market Rule 1, § III.2.3 (15.0.0); MISO, FERC Electric Tariff, § 40.2 

(34.0.0); NYISO Markets and Services Tariff, § 4.4.2.1 (17.0.0); PJM OATT, 

Attachment K, Appendix, § 2.3 (2.0.0); SPP, OATT, Sixth Revised Volume No. 1, 

Attachment AE, § 6.2.2 (1.0.0).

33 See CAISO, eTariff, § 11.5 (2.0.0), Appendix A, Settlement Interval (2.0.0); 

ISO-NE, Transmission, Markets and Services Tariff, Market Rule 1, § III.2.2(b) (15.0.0); 

MISO, FERC Electric Tariff, §§ 40.3 (32.0.0), 40.3.1 (32.0.0), 40.3.3 (36.0.0); NYISO, 

NYISO Tariffs, NYISO Markets and Services Tariff, §§ 4.4.2.1, 4.4.2.8 (17.0.0); PJM, 

Intra-PJM Tariffs, OATT, Attachment K, Appendix, §§ 2.5(e), (4.0.0), 3.2.1(e), (f) 

(28.0.0); SPP, OATT, Sixth Revised Volume No. 1, Attachment AE, §§ 8.6, 8.6.1 (2.1.0).

The above tariff citations refer to internal transactions. CAISO settles its intertie 

interchange transactions on fifteen-minute intervals. See CAISO, eTariff, HASP Block 

Intertie Schedule (0.0.0).

Real-Time Dispatch32 Real-Time Settlement33

CAISO 5 minute 5 minute

ISO-NE 5 minute hourly average

MISO 5 minute hourly average

NYISO 5 minute 5 minute

PJM 5 minute hourly average

SPP 5 minute 5 minute
Docket No. RM15-24-000 - 18 -

intervals and dispatches energy on five-minute intervals.34 MISO states that it currently 

calculates settlements for real-time operating reserves transactions at the same interval 

that they are dispatched, i.e., five minutes, but that actual settlements are on an hourly 

basis due to the specific calculations MISO makes. 

24. The PJM Market Monitor explains that the synchronized and regulation reserves 

markets in PJM clear hourly but already incorporate five-minute LMP data for 

calculating opportunity costs. The PJM Market Monitor states that the offer price in 

PJM’s synchronized reserve market includes both the direct short-run marginal cost of 

providing synchronized reserves, which does not vary every five minutes, and the 

opportunity cost of providing synchronized reserves, which does vary with five-minute 

LMPs. The PJM Market Monitor explains that PJM currently updates the opportunity 

cost every five minutes using five-minute LMP data for the Tier 2 synchronized reserve 

market and recalculates the market clearing price every five minutes, with settlement 

based on the average of the five-minute clearing price.35 

25. The PJM Market Monitor explains that, in PJM’s regulation market, the offer price 

includes both the direct short-run marginal cost of providing regulation, which does not 

vary every five minutes, and the opportunity cost of providing regulation, which varies 

with five-minute LMPs. The PJM Market Monitor adds that PJM currently updates the 

 

34 CAISO Comments at 8.

35 PJM Market Monitor Comments at 8.
Docket No. RM15-24-000 - 19 -

opportunity cost every five minutes using five-minute LMP data for the regulation market 

and recalculates the clearing price every five minutes, with settlement based on the 

average of five-minute clearing prices. The PJM Market Monitor also notes that PJM 

purchases other forms of operating reserves on a cost basis, including Tier 1 

synchronized reserves, non-synchronized reserves, and day-ahead scheduling reserves.36

26. NYISO explains that it uses five-minute intervals to settle its real-time markets for 

energy, regulation service, and operating reserves.37 ISO-NE currently has hourly 

integrated settlement for its real-time energy transactions and its real-time operating 

reserves. However, ISO-NE states it intends to implement five-minute settlement of 

real-time operating reserves in connection with implementing five-minute settlement of 

real-time energy transactions, which is a current discussion among ISO-NE 

stakeholders.38 SPP prices and settles operating reserve products in its real-time 

market on a dispatch interval, or five minute, basis.39

 

36 PJM Market Monitor Comments at 8.

37 NYISO Comments at 2-3.

38 ISO-NE Comments at 2-3.

39 SPP Market Protocols, Sections 4.5.4 and 4.5.9.
Docket No. RM15-24-000 - 20 -

c. Comments on the Proposed Settlement Interval Reform 

27. Twenty-seven of the thirty commenters providing input on this issue generally 

support the NOPR’s proposed settlement interval reform.

40

 As described below, many 

assert that the proposed reform will align the price signals with system conditions and 

provide accurate incentives for generation units to follow dispatch instructions.41 Others 

point to additional benefits. 

i. Comments from the RTOs/ISOs

28. The ISO/RTO Council supports the Commission’s goals of aligning prices with 

resource dispatch instructions and operating needs and specifically supports the 

settlement interval proposal for energy transactions. The ISO/RTO Council states that 

the proposed settlement interval reform will make resource compensation more 

 

40 Ameren Comments at 1, 3-4; ANGA Comments at 2-5; CAISO Comments at 2; 

CEA Comments at 3-6; Dominion Comments at 1-2; DTE Comments at 3-4; EDP 

Renewables Comments at 2; EEI Comments at 2; ESA Comments at 2-4; Entergy 

Nuclear Power Marketing Comments at 2; EPSA Comments at 1-5; Exelon Comments at 

4; Financial Marketers Coalition Comments at 1; Golden Spread Initial Comments at 1-3; 

Inertia Power and DC Energy Comments at 2; ISO-NE Comments at 1; MISO Comments 

at 2, 9; NEI Comments at 1; NGSA Comments at 2-5; ODEC Comments at 3; PJM 

Power Providers Comments at 2-5; Potomac Economics Comments at 2; Powerex 

Comments at 6; PSEG Comments at 3; Public Interest Organizations Comments at 5; 

SPP Market Monitor Comments at 2; Westar Comments at 1.

41 Inertia Power and DC Energy Comments at 2; Potomac Economics Comments 

at 1; Westar Comments at 1; PSEG Comments at 3.
Docket No. RM15-24-000 - 21 -

transparent by increasing the proportion of payments to resources through the price paid 

for energy as opposed to uplift.42 

29. In separate comments, NYISO, ISO-NE, MISO, and PJM support the settlement 

interval proposal for both energy and operating reserve transactions. Likewise, in 

separate comments, CAISO supports the settlement interval proposal for energy 

transactions, but does not support requiring RTOs/ISOs to settle all real-time operating 

reserves transactions at the same interval as real-time energy dispatch and settlement 

intervals. 

30. CAISO states that the settlement interval proposal would improve market 

efficiency, and that accurate price signals provide market participants with incentives to 

develop needed capabilities and to offer those capabilities into the market.43 CAISO 

states that where settlement and dispatch intervals are aligned, resources dispatched 

economically during high-priced periods should receive high prices, thus reducing the 

need to pay uplift caused by non-alignment of settlement and dispatch intervals.44 

31. However, CAISO does not support requiring RTOs/ISOs to settle all real-time 

operating reserves transactions at the same interval as real-time energy dispatch and 

settlement intervals. Instead, CAISO asserts that it is appropriate to maintain its current

 

42 ISO/RTO Council Comments at 2.

43 CAISO Comments at 7.

44 CAISO Comments at 7.
Docket No. RM15-24-000 - 22 -

fifteen-minute procurement and settlement interval for operating reserves transactions, 

which differs from the five-minute real-time energy dispatch interval. CAISO explains 

that its current settlement methodology aligns ancillary services commitment with 

internal generation commitment and intertie transactions scheduling so that the market 

accurately reflects the overall amount of supply resources available to provide energy and 

ancillary services.45 

32. NYISO supports the settlement interval proposal and asserts that its use of 

five-minute intervals to settle its real-time markets for energy, regulation service, and 

operating reserves, has provided significant incentives for resources to follow dispatch 

instructions and opportunities for supply resources to obtain full payment for their 

performance based on actual system conditions.46 

33. ISO-NE contends that settling on sub-hourly or five-minute intervals would help 

to improve price signals and resource compensation.47 ISO-NE states that five-minute 

settlements will help improve price formation by ensuring that compensation for realtime performance sends more accurate market signals of power system conditions when 

energy is provided.48 ISO-NE supports the settlement interval proposal for operating 

reserve transactions. It asserts that settling all real-time operating reserves transactions at 

 

45 CAISO Comments at 17-18.

46 NYISO Comments at 2-3.

47 ISO-NE Comments at 2.

48 ISO-NE Comments at 2.
Docket No. RM15-24-000 - 23 -

the same interval as real-time energy dispatch and settlement intervals would assist in 

aligning dispatch following incentives in markets that simultaneously co-optimize energy 

and reserve dispatch in real-time. ISO-NE states it intends to implement five-minute 

settlement of real-time operating reserves in connection with implementing five-minute 

settlement of real-time energy transactions, which is a current discussion among ISO-NE 

stakeholders.49

34. MISO asserts that the inconsistency between dispatch and settlements may 

produce financial outcomes that do not align with the guiding principles of co-optimized 

(energy and ancillary services) security constrained economic dispatch.50 If the 

Commission requires five-minute settlements of operating reserves, MISO states that it 

would modify its operating reserves settlements from its current hourly method of settling 

operating reserves to align with real-time energy transactions.51

35. PJM states that ancillary services, including operating reserves, should settle on 

the same interval as energy because they are co-optimized. PJM argues that not doing so 

could yield discrepancies between the prices used to settle each product and could 

therefore undo enhancements made since implementation of Order No. 719, reduce 

 

49 ISO-NE Comments at 2-3.

50 MISO Comments at 2.

51 MISO Comments at 7-8.
Docket No. RM15-24-000 - 24 -

market efficiencies, disrupt operations, and hinder proper price formation.52 PJM states 

that it intends to change its market rules to settle energy and ancillary services

transactions in its real-time energy market at the same interval on which it dispatches 

resources.

53

 

ii. Comments by Market Monitors

36. The PJM Market Monitor agrees that it would be appropriate to implement 

five-minute pricing for the reasons stated in the NOPR, and that implementing 

five-minute settlements will contribute significantly to reducing uplift payments in PJM, 

an ongoing goal in the PJM region.54 The PJM Market Monitor states that, while it is 

appropriate to include the impact of five-minute LMP changes on the cost of operating 

reserves in the form of synchronized reserves and regulation, the PJM design for these 

markets currently incorporates those impacts. The PJM Market Monitor asserts that no 

additional changes to PJM market and non-market mechanisms for acquiring operating 

reserves are currently necessary to incorporate changes in five-minute LMPs.55 

37. Potomac Economics, which serves as the market monitor for ISO-NE, MISO, and 

NYISO, argues that hourly settlements encourage resources not to follow dispatch 

instructions or to decrease their flexibility by restricting dispatch ranges and offering 

 

52 PJM Comments at 9.

53 PJM Comments at 2.

54 PJM Market Monitor Comments at 2, 4.

55 PJM Market Monitor Comments at 8-9.
Docket No. RM15-24-000 - 25 -

slower ramp rates, and states that MISO pays uplift to alleviate these issues. 

Potomac Economics cites its 2014 MISO State of the Market Report to show how 

five-minute settlements would change total payments to resources compared to current 

hourly settlements. This analysis showed that fossil-fueled resources in 2014 received 

settlements that were $35 million less than they would have received if the settlement 

were based on five-minute prices and output, and that only one-fifth of this lost value 

was paid via uplift. In contrast, Potomac Economics represents that non-fossil resources 

were paid on net in hourly revenues slightly above what they would have received with 

five-minute settlements. Potomac Economics asserts that five-minute settlement provides

greater compensation to fossil resources, more accurately representing the flexibility

fossil resources provide to the system. In contrast, Potomac Economics argues that 

hourly settlement overvalues wind resources because such resources cannot ramp up in 

response to higher prices, are negatively correlated with load and contribute to higher 

congestion at higher output levels.56 Potomac Economics states that the settlement 

interval proposal will provide incentives for better resource performance, will improve 

price signals, and will improve markets’ short-run commitment and dispatch of existing 

resources.

57

 

56 Potomac Economics Comments at 6. 

57 Potomac Economics Comments at 1.
Docket No. RM15-24-000 - 26 -

38. The SPP Market Monitor agrees with the Commission’s preliminary finding that 

aligning settlement and dispatch intervals would make resource compensation more 

transparent by increasing the proportion of resource payments made through energy and 

operating reserve payments instead of uplift.58 The SPP Market Monitor states that 

aligning dispatch and settlement intervals in neighboring markets would enhance price 

signals at seams and enhance market efficiency.59

iii. Comments Supporting the Proposed Settlement 

Interval Reform 

39. Many commenters expressly support the NOPR’s settlement interval proposal, 

citing many of the benefits that were outlined in the NOPR.

60

 They generally argue that 

the settlement interval proposal will provide incentives for generators to follow dispatch 

more precisely, thus leading to better resource performance, and improved reliability.61

 

58 SPP Market Monitor Comments at 2.

59 SPP Market Monitor Comments at 2-3.

60 Ameren Comments at 1, 3-4; ANGA Comments at 2-5; CAISO Comments at 2; 

CEA Comments at 3-6; Dominion Comments at 1-2; DTE Comments at 3-4; EDP 

Renewables Comments at 2; EEI Comments at 2; ESA Comments at 2-4; Entergy 

Nuclear Power Marketing Comments at 2; EPSA Comments at 1-5; Exelon Comments at 

4; Financial Marketers Coalition Comments at 1; Golden Spread Initial Comments at 1-3; 

Inertia Power and DC Energy Comments at 2; ISO-NE Comments at 1; MISO Comments 

at 2, 9; NEI Comments at 1; NGSA Comments at 2-5; PJM Power Providers Comments 

at 2-5; Potomac Economics Comments at 2; Powerex Comments at 6; PSEG Comments 

at 3; Public Interest Organizations Comments at 5; SPP Market Monitor Comments at 2;

Westar Comments at 1; AEMA Comments at 2; XO Energy Comments at 1; PJM Market 

Monitor at 2; ODEC at 3.

61 Inertia Power and DC Energy Comments at 2; Westar Comments at 1, 3; 

EEI Comments at 6-7; Exelon Comments at 4-5.
Docket No. RM15-24-000 - 27 -

They also assert that the settlement interval proposal will properly compensate resources 

for the service they provide and will more fully recognize the value of flexible or fastramping resources.62

 In addition, they generally state that the settlement interval proposal 

will lead to fewer out-of-market payments, will increase transparency, and will support 

more efficient market outcomes.63

40. More specifically, Exelon asserts that the settlement interval proposal will support 

ongoing market improvements, such as ISO-NE’s performance incentive mechanism, 

effective in June 2018, that will pay resources bonuses or impose penalties based on 

performance during operating reserve shortages that last five minutes or longer. Exelon 

argues that ISO-NE’s market must settle at five-minute intervals to implement this 

mechanism completely.64

41. According to EDP Renewables, greater participation of fast ramping renewable 

resources will also enhance resource adequacy, produce cost savings for consumers, and 

improve grid resilience.65

 

62 Public Interest Organizations Comments at 2-3; ELCON Comments at 2-3; 

EDP Renewables Comments at 2-3; ESA Comments at 3; NEI Comments at 14.

63 See supra note 60; ELCON Comments at 3; Exelon Comments at 4-5.

64 Exelon Comments at 5.

65 EDP Renewables Comments at 3.
Docket No. RM15-24-000 - 28 -

42. Some commenters also argue that the settlement interval proposal will reduce 

market inefficiencies and lead to greater investment. PSEG asserts that the proposed 

reforms correct market flaws that have caused inefficiencies in both price signals and 

resource dispatch decisions.66 ELCON states that the proposed settlement reform

addresses an embedded inconsistency in market operation that promotes gaming and 

other forms of ill behavior or inefficiencies.67 EDP Renewables argues that the proposed 

reforms will also yield savings, remove opportunities for market manipulation, and 

encourage investment in new services and new technologies, all of which will result in a 

more robust and resilient grid and help both consumers and suppliers through more 

efficient market operation.68 

43. EPSA argues that implementing sub-hourly settlement intervals is needed to 

obtain the full benefits of other price formation reforms to improve the accuracy with 

which real-time prices communicate the time-dependent and location-dependent value of 

incremental energy and ancillary services.69 

44. TAPS does not oppose the settlement interval proposal, as long as it does not 

impose an undue burden on load serving entities.70

 

66 PSEG Comments at 3.

67 Public Interest Organizations Comments at 2-3; ELCON Comments at 2-3.

68 EDP Renewables Comments at 2.

69 EPSA Comments at 6-7, Pope Aff. at 4-5.

70 TAPS Comments at 4.
Docket No. RM15-24-000 - 29 -

45. EPSA supports the settlement interval proposal for operating reserves. It argues 

that real-time operating reserves should be co-optimized in the dispatch and settled with 

energy for every hourly sub-interval (generally five minutes) to ensure that resources are 

compensated for following RTO/ISO instructions and are indifferent to providing either 

energy or operating reserves during periods of high energy or operating reserves prices.71 

EPSA emphasizes the importance of sending sub-hourly price signals to ensure that 

operating reserves are available in sub-hourly intervals due to their contribution to 

maintaining reliability, further stating that sub-hourly settlements for operating reserves 

send information to the market relating to the potential profitability of incremental 

investments to enhance the sub-hourly availability of such reserves.72 EPSA argues that 

to ensure accurate prices for both energy and operating reserves, RTOs/ISOs should be 

required to co-optimize these products in real-time because suppliers should be 

indifferent to providing incremental energy and operating reserves in each sub-hourly 

interval to allow the RTO/ISO to perform a reliable least-cost dispatch.73

46. Dominion supports the settlement interval proposal for operating reserves. 

However, Dominion argues that only specific reserve products should settle at the same 

interval that they are priced and that other types of settlement provisions, such as make-

 

71 EPSA Comments, Pope Aff. at 11.

72 EPSA Comments, Pope Aff. at 11.

73 EPSA Comments, Pope Aff. at 12-13.
Docket No. RM15-24-000 - 30 -

whole payments, should not.74 Dominion explains that, in PJM, for example, “balancing 

Operating Reserves” includes the costs to dispatch resources out-of-merit for reliability 

or to cover deficiencies in the day-ahead market solution.75 According to Dominion, 

these resources do not provide a specific reserve product; rather, these resources are made

whole when they are dispatched to address a mismatch between day-ahead commitment 

and real-time requirements. Dominion therefore requests that the Commission not 

require the settlement intervals for these types of operating reserve to change.76

47. PSEG supports applying the proposed settlement intervals to both real-time energy 

transactions and real-time operating reserves. PSEG explains that given the linkage 

between energy transactions and reserve services, settling those products on different 

intervals would introduce dislocations, and incent resource actions that could disrupt 

these co-optimization objectives, essentially undermining the Commission’s objectives in 

the NOPR.77

48. The New Jersey Board concurs with the PJM Market Monitor that no changes 

should be made in PJM’s synchronized reserve and regulation markets given that the 

opportunity cost component in these ancillary services markets, which is the only cost 

component subject to five-minute changes in LMP, already accounts for the five-minute 

 

74 Dominion Comments at 3.

75 Dominion Comments at 3.

76 Dominion Comments at 3.

77 PSEG Comments at 4-5.
Docket No. RM15-24-000 - 31 -

interval changes.78 Duke acknowledges potential benefits from aligning operating 

reserve transactions with their respective settlement intervals but argues that stakeholders 

should consider whether operating reserves transactions should be aligned with 

settlement intervals for energy given the costs of doing so.

79

 Although it takes no 

position on the operating reserves proposal, EEI states that additional clarity from the 

Commission on the definition of operating reserve transactions would be helpful, given 

the varied definitions of reserve products among regions. EEI states that such regional 

variation warrants further consideration.80 

iv. Comments Opposed to the Proposed Settlement 

Interval Reform

49. Several commenters oppose the settlement interval proposal. Direct Energy states 

that the Commission should solicit information from RTOs/ISOs to determine whether 

existing generation resources are able to respond effectively to five-minute price signals

before determining whether any settlement interval reform is warranted.

81

 Direct Energy 

doubts the ability of longer lead-time resources to respond to five-minute price signals 

during periods of extreme price volatility, and surmises that look-ahead unit commitment 

and dispatch software results could exacerbate swings in generation and load balance. 

 

78 New Jersey Board Comments at 4. 

79 Duke Comments at 5.

80 EEI Comments at 9-10 & n.16.

81 Direct Energy Comments at 6.
Docket No. RM15-24-000 - 32 -

Direct Energy states that a high-priced dispatch interval could encourage dispatch of 

peaking generation, which would take several minutes with longer ramp times and cause 

other resources to ramp up more quickly. Direct Energy argues that this could lead to an 

oversupply and to depressed prices, thus making the longer-ramping resources 

responding to the original signal uneconomic by running below their costs and incurring 

uplift—the opposite of the goal of the settlement interval proposal.

82

 

50. Duke, APPA and NRECA, and Concerned Cooperatives argue that the 

Commission should refrain from requiring a one-size-fits-all approach.83 Duke, APPA 

and NRECA, and Concerned Cooperatives contend that RTO/ISO stakeholder processes 

should vet this issue and consider issues such as the costs, benefits, types of changes 

needed to implement this reform, price formation issues more generally, and unintended 

consequences.

84

 Duke states that this approach would notify the Commission with regard 

to possible solutions, cost of implementation, and the timeframe in which the RTO/ISO 

could reasonably address each issue.85 Additionally, Concerned Cooperatives disagree 

with the Commission’s conclusion that reforming the settlement intervals will result in 

more efficient use of generating resources. 

 

82 Direct Energy Comments at 3-5.

83 Duke Comments at 2-3; APPA and NRECA Comments at 4-5; Concerned 

Cooperatives Comments at 4-5.

84 Duke Comments at 4; APPA and NRECA Comments at 3; Concerned 

Cooperatives Comments at 1.

85 Duke Comments at 4-5.
Docket No. RM15-24-000 - 33 -

51. Concerned Cooperatives argue that the benefits of moving to five-minute 

settlements will not offset the cost. They state that the Potomac Economics report cited 

in the NOPR shows that switching to matching intervals would force MISO market 

participants to expend millions of dollars on upgrades and operation and maintenance 

(O&M) costs, without realizing lower rates. Instead, those participants would face an 

annual increase of approximately $28 million, after netting the estimated $6.6 million 

system benefit from the increased payments to generators of about $35 million dollars.86 

52. Concerned Cooperatives further argue that the Commission relies solely upon a 

letter filed in Docket No. AD14-14-00087 to support its finding with no analysis as to 

whether the observed increase in capacity factors for internal combustion engines in SPP 

was the result of SPP’s adoption of five-minute settlement intervals or other factors.88 

Concerned Cooperatives argue that, even if there was some marginal benefit to the 

settlement interval proposal, many market participants would not benefit from the reform 

even though they would be responsible for funding it.89 Concerned Cooperatives 

represent that 90 to 95 percent of their transactions take place in the day-ahead market, 

which settles on an hourly basis, and that adopting five-minute settlement intervals in the 

 

86 Concerned Cooperatives Comments at 10 (citing Potomac Economics, 2014 

State of the Market Report for the MISO Electricity Markets, at 43-44, Figure 19 (2015)).

87 Concerned Cooperatives Comments at 11 (citing Comments of Wärtsilä North 

America, Inc., Docket No. AD14-14-000, at 1-2 (Mar. 6, 2015)). 

88 Concerned Cooperatives Comments at 11.

89 Concerned Cooperatives Comments at 11.
Docket No. RM15-24-000 - 34 -

real-time market does not help Concerned Cooperatives hedge prices.90 Concerned 

Cooperatives also state that the National Renewable Energy Laboratory study cited in the 

NOPR in support of adopting five-minute settlement intervals also recognizes that 

limiting market complexity may be a reason to maintain hourly settlements, and that 

RTOs/ISOs already have tools to encourage resources to follow efficient schedules, such 

as uninstructed deviation penalties and ex post pricing rules. Concerned Cooperatives 

recommend that the Commission instead identify objectives and allow RTOs/ISOs to 

pursue options for achieving those objectives.91

d. Commission Determination

i. Energy Transactions

53. We adopt the NOPR proposal to require that each RTO/ISO settle energy 

transactions in its real-time markets at the same time interval it dispatches energy, as 

discussed below.

92

 We find that the settlement interval requirement for energy 

transactions will meet the Commission’s price formation goals by more accurately 

reflecting the value of the service a resource provides to the system, which, in so doing, 

helps to ensure that rates are just and reasonable and not unduly discriminatory or 

preferential.

 

90 Concerned Cooperatives Comments at 11.

91 Concerned Cooperatives Comments at 12.

92 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.
Docket No. RM15-24-000 - 35 -

54. As discussed below, providing the correct incentives for market participants to 

follow commitment and dispatch instructions, make efficient investments in facilities and 

equipment, maintain reliability, and increase transparency is fundamental to proper 

formation of energy prices, helping to ensure just and reasonable rates, terms and 

conditions of service. 

55. One important element of ensuring reliable grid operations is resources following 

dispatch instructions. The requirement that each RTO/ISO settle energy transactions at 

the same interval it dispatches energy sends accurate market signals of power system 

conditions, thus encouraging resources to follow commitment and dispatch instructions, a 

point noted by ISO-NE.

93

 

56. The settlement interval requirement for energy transactions also provides an 

incentive to make efficient investments in facilities and equipment.94 In the long-term, 

we expect that appropriate compensation would help to encourage efficient investments 

in facilities and equipment, enabling reliable service. We also find that the settlement 

interval requirement will provide incentives to more flexible resources, thus leading to 

more efficient markets, as noted by several commenters.95 More flexible resources will 

help system operators address transient system conditions. We find that greater 

 

93 ISO-NE Comments at 2.

94 EPSA Comments, Pope Aff. at 4.

95 Public Interest Organizations Comments at 2-3; ELCON Comments at 2-3; 

EDP Renewables Comments at 2-3; ESA Comments at 3; NEI Comments at 14.
Docket No. RM15-24-000 - 36 -

participation of these more flexible resources should generally enhance resource 

adequacy because it allows the participation of diverse resources and improves reliability, 

as noted by EDP Renewables.

96

 

57. The settlement interval requirement for energy transactions should help in 

maintaining reliability because resources will have a greater incentive to follow dispatch 

instructions, as noted by Exelon.

97

 In addition, these reforms will provide resource 

owners with a greater incentive to adequately maintain their equipment, conduct 

maintenance during non-peak periods, and invest in new and upgraded equipment. As 

noted by CAISO, linking prices with compensation will pay resources for providing 

needed flexibility to the market operator and would motivate these resources to improve 

their operational performance.

98

 

58. The settlement interval requirement for energy transactions also results in more 

accurate market prices, reducing the need for out-of-market operator actions. Under an 

hourly settlement system, resources do not have the same incentive to follow five-minute 

prices since compensation is based on an hourly average. Therefore, system operators 

are more likely to take out-of-market actions in real-time, such as increasing the use of 

regulating reserves or committing additional resources, to ensure that adequate resources 

 

96 EDP Renewables Comments at 2-3.

97 Exelon Comments at 4-5.

98 CAISO Comments at 7.
Docket No. RM15-24-000 - 37 -

are available to meet system needs. Such actions may result in uplift. By providing 

incentives to follow dispatch instructions, the settlement interval requirement should 

reduce such operator actions and, thereby, reduce uplift.99 When this occurs, energy 

prices are based on more observable market fundamentals – such as the marginal cost of 

serving load and the operational constraints of reliably operating the system – and not on 

less observable operator action.100 As a result of a reduction in out-of-market uplift 

payments, resources will perceive stronger financial incentives to perform, especially 

during stressed system conditions, when the performance of all resources is paramount. 

Further, we note, this increased transparency, in turn, better informs decisions to build or 

maintain resources.

59. Taken together, the benefits we expect as a result of this settlement reform will 

ensure that rates are just and reasonable and not unduly discriminatory or preferential.

 

99 Reducing out-of-market uplift payments can be beneficial to RTOs’/ISOs’ 

market participants because, among other reasons, charges to market participants for 

uplift are often volatile. As a result, market participants may build risk premiums into 

their resource bids in the real-time energy market to shield them from the uncertainty 

associated with unexpected uplift charges. See Staff Analysis of Uplift in RTO and ISO 

Markets, Docket No. AD14-14-000, at 18 (Aug. 2014), http://www.ferc.gov/legal/staffreports/2014/08-13-14-uplift.pdf. In addition, making system conditions and 

compensation more transparent through market prices will make that price apparent to all 

available resources and thus encourage them to fully participate in the market, which is 

likely to reduce generation costs incurred by load.

100 In addition to greater transparency, reducing uplift is a goal generally. For 

example, “[t]he implementation of five minute settlements would contribute significantly 

to the reduction of uplift payments, which is an ongoing goal of PJM, of the Market 

Monitor and of PJM members.” PJM Market Monitor Comments at 4.
Docket No. RM15-24-000 - 38 -

60. We are not persuaded by the arguments opposing the settlement interval proposal. 

Underlying much of the opposition is the assumption that many resources cannot take 

advantage of five-minute settlement intervals because they are not flexible enough to 

respond to five-minute dispatch. For example, Direct Energy argues that RTOs/ISOs 

should report the types of resources able to effectively modify their output to respond to 

five-minute price signals.101 The concern Direct Energy identifies is, in fact, one of the 

objectives of this reform. Specifically, resources that are not able to respond quickly 

enough to address acute system needs should not receive the same level of compensation 

as those resources that are able to flexibly respond.102 Further, we note that all 

RTOs/ISOs have a combination of resources, some of which can respond within five 

minutes and some that cannot, and that knowing the exact percentages of resources 

available to respond to prices is not determinative of whether the reforms adopted here 

will prove beneficial. Instead, we believe it is important to ensure settlement practices do 

not distort existing five-minute pricing signals.

61. We are not persuaded by Concerned Cooperatives’ argument that the settlement 

interval proposal should be rejected because market participants, such as Concerned 

Cooperatives, funding the reform do not have a large fraction of their positions in the 

 

101 Direct Energy Comments at 6.

102 This rule does not require resources to be dispatched more quickly than they 

are now, but it does increase the incentive for those resources that can and do respond 

quickly. 
Docket No. RM15-24-000 - 39 -

real-time market and therefore will not benefit significantly from it.103 We find that 

aligning prices and settlement intervals will enhance the operation of markets by ensuring 

resources respond to actual system condition regardless of the percentage of resources 

that clear in the day-ahead market. 

62. We also disagree with Concerned Cooperatives’ statement that the Commission 

relied upon a single document to support its finding without additional analysis.

104

 

Commenters supporting the reform have provided sound economic analysis and examples 

demonstrating the value of the proposed settlement reform.105 Though Concerned 

Cooperatives state that many market participants would not benefit from the reform even 

though they would be responsible for funding it,

106 we believe that many market 

participants are likely to benefit from the reform through improved economic incentives 

to respond to system needs. Potomac Economics’ analysis of fossil-fueled and nonfossil-fueled resources107 demonstrates that settlement reform will incentivize generator 

flexibility, improve generators’ dispatch performance, and increase investments in more 

flexible resources. 

 

103 Concerned Cooperatives Comments at 11.

104 Concerned Cooperatives Comments at 11.

105 EPSA Comments, Pope Aff. at 2-14; Potomac Economics Comments at 3-7; 

See also supra note 60.

106 Concerned Cooperatives Comments at 11.

107 Potomac Economics Comments at 5-6.
Docket No. RM15-24-000 - 40 -

63. Concerned Cooperatives express concern that adopting five-minute settlement 

intervals could result in errors and disputes that could lead to resettlement and uncertainty 

for the market.

108 All RTOs/ISOs currently compute five-minute LMPs. Therefore, there 

is no new data being generated or calculated that would lead to additional need for 

resettlement or increased uncertainty. Concerned Cooperatives have cited neither 

examples of more errors and disputes on RTO/ISO systems currently using five-minute 

settlement intervals, nor examples of additional resettlement and uncertainty for the 

market. Also, we find that, while administratively-determined uninstructed deviation 

penalties (which Concerned Cooperatives suggest could be used in lieu of settlement 

reform) are appropriate in certain contexts, settlements based on the actual value of 

energy corresponding with its production or transaction in each five-minute interval 

provide more accurate incentives for resources to respond to price signals. 

64. Concerned Cooperatives also assert that the objective of incenting market 

participants to follow dispatch instructions or invest in upgrades must be considered in 

the context of existing market rules that already may provide incentives for investment in 

faster ramping capability.109 To the extent an RTO/ISO has a functional mechanism to 

encourage the installation of fast-ramping resources, this Final Rule will augment the 

existing RTO/ISO mechanisms. 

 

108 Concerned Cooperatives Comments at 12.

109 Concerned Cooperatives Comments at 6.
Docket No. RM15-24-000 - 41 -

65. Contrary to Concerned Cooperatives’ argument, we are not persuaded to abandon 

the settlement interval proposal because a Potomac Economics report indicates that it 

would have resulted in an additional $28 million in increased energy costs on the MISO 

system in 2014.

110

 First, we recognize that that there could be higher revenues to 

generators, but we believe that this is the correct reflection of value provided in these 

circumstances and would send an improved signal for long-term investment and shortterm performance, to the overall benefit of the market. Second, it is important to note 

that the Potomac Economics report indicates that for many settlement intervals during 

2014, MISO resources were paid an hourly settlement rate lower than what five-minute 

settlements would justify. Thus, the Potomac Economics report should be viewed as 

indicating a need to correct settlement practices, rather than indicating a windfall to 

resources. Third, it is not clear that the proposal will result in generally increased energy 

payments to generators. For example, an ISO-NE study for the year 2013 found that the

net increase in real-time energy credits on its system (once the decrease in real-time 

reserve credits was considered) would have been only $600,000.111 Finally, due to the 

increased efficiencies resulting from improving incentives to respond to market price 

signals, total costs to electric wholesale customers over time are likely to decrease. 

 

110 Concerned Cooperatives Comments at 10.

111 ISO-NE, Subhourly Real-Time Market Settlements, A11 ISO Presentation 05-

07-14 Revision 1, Matt Brewster, at 11 (May 8, 2014), http://www.isone.com/committees/key-projects/subhourly-real-time-settlement.
Docket No. RM15-24-000 - 42 -

66. Additionally, some commenters argue that other types of settlement provisions, 

such as make-whole payments, should not be subject to settlement interval reform. We 

would like to clarify that the Final Rule does not apply to make-whole payments for units 

dispatched out-of-merit. 

67. We disagree with the recommendation of some commenters that the decision to 

modify settlement intervals should be subject to a stakeholder process.112 RTOs/ISOs 

implementing this Final Rule are free to use a stakeholder process within the 

implementation timelines specified herein, but we see no need to further delay this 

reform. This does not limit stakeholders’ input as RTOs/ISOs form their compliance 

filings in response to this aspect of the Final Rule. 

68. We conclude that the settlement interval requirement for energy transactions 

should ensure that hourly settlement practices do not distort five-minute price signals in 

RTOs/ISOs. Instead, the compensation provided to resources must reflect the value of a 

resource providing given services to ensure appropriate economic incentives to meet 

system needs. 

ii. Operating Reserves

69. We adopt the proposal in the NOPR that RTOs/ISOs settle real-time operating 

reserves transactions at the same time interval that they price operating reserves. This 

requirement for operating reserves will accomplish the Commission’s price formation 

 

112 APPA and NRECA Comments at 4.
Docket No. RM15-24-000 - 43 -

goals and thereby ensure just and reasonable rates, and will further preserve the cooptimization of operating reserves with energy. Under the settlement interval

requirement for operating reserves, to the extent that an RTO/ISO prices operating 

reserves transactions at a different time interval than it prices internal real-time energy 

transactions, that RTO/ISO need only settle operating reserves transactions at the same 

time interval that they are priced. Thus, we will not require an RTO/ISO to settle 

operating reserves transactions on the same time interval as it settles energy transactions. 

This will preserve the existing energy and operating reserves co-optimization 

methodologies of the various RTOs/ISOs.

70. The settlement interval requirement increases transparency and provides the 

correct incentives to maintain reliability. It also meets the Commission’s other price 

formation goals of encouraging resources to follow the RTO’s/ISO’s commitment and 

dispatch instructions and to make efficient investments. The reform to the settlement 

interval for operating reserves will increase reliability because resource owners will have 

a greater incentive to adequately maintain their equipment, conduct maintenance during 

non-peak periods, and invest in new and upgraded equipment. Similar to energy 

settlement intervals, requiring settlement intervals of operating reserves transactions to 

match the intervals upon which those reserves are priced will reduce the need for 

payments made through uplift, make resource compensation more transparent and 

help ensure that there are adequate operating reserves to maintain reliability. Finally, 

co-optimized energy and reserve prices are designed so that a resource is indifferent 

between providing energy or operating reserves. Ensuring that energy and operating 
Docket No. RM15-24-000 - 44 -

reserve settlements are done on the same basis will preserve this indifference and create 

an incentive for a resource to provide the service the RTO/ISO has instructed it to 

provide. The reform to operating reserve settlements will, by achieving the 

Commission’s price formation goals and preserving the co-optimization of energy and 

operating reserves, ensure that rates are just and reasonable.

71. While, as discussed above, some commenters also support RTOs/ISOs settling all 

real-time operating reserves transactions at the same time interval that they dispatch realtime energy,113 we are not requiring that these settlement intervals align. CAISO, in 

defending its current practices, states that it procures operating reserves and settles them 

on a fifteen-minute basis and distinguishes this type of ancillary service from five-minute 

real-time energy dispatch.114 However, CAISO, along with all of the other RTOs/ISOs,

supports the requirement that they settle operating reserves transactions at the same time 

interval that they price these transactions, which accommodates both RTOs/ISOs that 

currently settle co-optimized reserve transactions on a five-minute basis and those that 

currently settle these transactions on a fifteen-minute basis. Accordingly, we clarify that 

CAISO’s understanding in this regard is consistent with how operating reserves and 

energy on its system are “priced,” as contemplated by the wording of the settlement 

interval regulations adopted by this Final Rule.

 

113 PSEG Comments at 4-5; EPSA Comments, Pope Aff. at 11-13.

114 CAISO Comments at 17-18. 
Docket No. RM15-24-000 - 45 -

72. NYISO states that, although it uses sub-hourly settlements in its real-time market, 

in certain cases, the Commission has approved NYISO performing settlements on an 

hourly basis, and NYISO argues it should not be required to bring those settlements into 

alignment with its normal dispatch intervals.115 NYISO cites limited energy storage 

resources as an example of services that currently settle hourly and yet follow dispatch 

instructions and provide resource response in real-time. To the extent NYISO or other 

RTOs/ISOs seek to argue on compliance that their existing market rules are consistent 

with or superior to the Final Rule reforms adopted herein, the Commission will entertain 

those at that time.116

73. Although generally supporting the settlement interval requirement for operating 

reserves, some commenters question whether such a requirement should apply to all 

reserve products or assert that regional variations should be considered.117 We appreciate 

that regional variations may exist among the many different reserve products in the 

RTOs/ISOs and we clarify that all operating reserve products that have a market-based 

price are subject to the settlement interval reform. 

 

115 NYISO Comments at 3-4.

116 See, e.g., Demand Response Compensation in Organized Wholesale Energy 

Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322, at P 4 & n.7, order on reh’g and 

clarification, Order No. 745-A, 137 FERC ¶ 61,215 (2011), reh'g denied, Order 

No. 745-B, 138 FERC ¶ 61,148 (2012), vacated sub nom. Elec. Power Supply Ass’n v. 

FERC, 753 F.3d 216 (D.C. Cir. 2014), rev’d & remanded sub nom. FERC v. Elec. Power 

Supply Ass’n, 136 S. Ct. 760 (2016). 

117 See, e.g., Dominion Comments at 3; EEI Comments at 10.
Docket No. RM15-24-000 - 46 -

3. Interties

a. Commission Request for Comments

74. The Commission sought comment on whether the proposed reforms are 

appropriate for intertie transactions scheduled on intervals different from the intervals on 

which RTOs/ISOs dispatch internal real-time energy.

118

i. Comments by RTOs/ISOs

75. The ISO/RTO Council asserts that aligning dispatch and pricing should also apply 

to intertie transactions, adding that this would prevent price discrepancies and may 

reduce uplift.

119

76. PJM asserts that intertie transactions should be included in the scope of the 

Final Rule, noting that it plans to settle intertie transactions on a five-minute basis, 

consistent with its proposal for its real-time energy market. PJM suggests that, where a 

transaction is curtailed or the MW quantity is reduced during a fifteen-minute interval 

due to a reliability directive, each five-minute interval in the transaction should settle on 

the integrated transaction MW quantity that flowed during the five-minute interval.120 

77. ISO-NE argues that external interties should settle no less often than the 

intervals for which they are scheduled. ISO-NE represents that its proposals to 

implement sub-hourly settlements would fully meet this objective at all its external 

 

118 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 39.

119 ISO/RTO Council Comments at 2.

120 PJM Comments at 8.
Docket No. RM15-24-000 - 47 -

interfaces.121 NYISO argues that intertie and internal transactions should have the same 

settlement interval because this alignment will promote competition, identify the most 

economic supply option, provide equal incentives to respond to the same operating 

conditions, and improve the efficiency of interregional transactions.122

78. CAISO notes that it already schedules and settles intertie transactions and internal 

resources on a fifteen-minute basis.123 However, CAISO also provides three options 

for scheduling imports and exports on an hourly basis: (1) economic-bid hourly block; 

(2) economic-bid hourly block with a single intra-hour schedule change that will be 

dispatched to zero within the hour if a fifteen-minute price is less than an import’s bid 

price or greater than an export’s bid price; and (3) self-scheduled hourly.124 CAISO 

requests that the Commission state that CAISO’s current market design with granular 

dispatch and settlement of its real-time energy market is consistent with the settlement 

interval proposal.

125

79. CAISO asserts that a blanket requirement that hourly intertie schedules revert to 

hourly pricing, as was previously the case under its prior market design, would result in 

the same adverse market outcomes it resolved through its fifteen-minute market 

 

121 ISO-NE Comments at 2.

122 NYISO Comments at 5.

123 CAISO Comments at 12.

124 CAISO Comments at 9.

125 CAISO Comments at 10.
Docket No. RM15-24-000 - 48 -

enhancement.126 CAISO requests that the Commission clarify that the availability of 

hourly block intertie bidding options would not violate the settlement interval proposal

because its current market design ensures all internal and external transactions are cleared 

and settled based on fifteen-minute market intervals that optimize all transactions in its

markets.127

ii. Comments by Market Monitors

80. The PJM Market Monitor asserts that intertie transactions in PJM cannot be 

measured accurately enough to support five-minute settlements, noting that accurate 

measurement is difficult because of differences between actual and scheduled flows. 

The PJM Market Monitor thus recommends that settlements be based on the same 

fifteen-minute interval used for external scheduling intervals. The PJM Market Monitor 

asserts that this approach would more accurately reflect LMP during the actual time 

period of the transaction and would make the period and settlement of the transaction 

consistent.128 

 

126 CAISO Comments at 14.

127 CAISO Comments at 15.

128 PJM Market Monitor Comments at 7.
Docket No. RM15-24-000 - 49 -

81. The PJM Market Monitor states that alternative settlement approaches include 

using the integrated price over the same fifteen-minute interval used in scheduling and 

using five-minute interval settlements.129 

iii. Comments in Support of Applying Settlement 

Reform to Interties

82. The New Jersey Board, EEI, EPSA, Dominion, and EDP Renewables concur with 

the PJM Market Monitor that intertie settlements should be at fifteen-minute intervals, 

the same interval as external scheduling.

130

83. Golden Spread states that alignment between dispatch and settlement intervals is 

generally desirable for the reasons listed in the NOPR, and notes that it believes SPP 

already aligns dispatch and settlement intervals for intertie transactions on a five-minute 

basis.

131

84. ANGA, PSEG, and the Financial Marketers Coalition assert that the logic 

underlying the proposed settlement reform as applied to internal transactions should 

apply equally to intertie transactions, and ANGA recommends that the Commission 

 

129 The PJM Market Monitor in its comments provides examples of these 

alternatives. PJM Market Monitor Comments at 5-7.

130 New Jersey Board Comments at 3-4; EEI Comments at 9; EPSA Comments, 

Pope Aff. at 9; Dominion Comments at 4; EDP Renewables Comments at 5.

131 Golden Spread Initial Comments at 2.
Docket No. RM15-24-000 - 50 -

consider evolving these interfaces to five-minute dispatch and settlement, perhaps over 

the next three to five years.132 

85. Although it generally agrees that the settlement interval proposal should apply 

equally to internal and intertie transactions, Financial Marketers Coalition states that, in 

CAISO, clearing some transactions (such as load and generation) on a five-minute price 

and others (such as internal and intertie convergence bids) on a fifteen-minute price has 

yielded price divergence instead of convergence. 

iv. Comments Opposed to Applying Settlement 

Reform to Interties

86. Inertia Power and DC Energy argue that intertie economic dispatch intervals 

cannot easily be aligned with internal real-time energy dispatch but emphasize the 

importance of maintaining the highest possible consistency across the seams to ensure a 

more efficient, resilient, and reliable electrical system.133 

87. Duke states that the issue of whether to apply the settlement interval proposal to 

intertie transactions should be discussed in the RTO/ISO stakeholder processes and that 

they should be treated comparably to reforms to internal transactions.134

 

132 ANGA Comments at 3-4; Financial Marketers Coalition Comments at 3-4; 

PSEG Comments at 5.

133 Inertia Power and DC Energy Comments at 4-5.

134 Duke Comments at 5.
Docket No. RM15-24-000 - 51 -

b. Commission Determination

88. Based upon the comments received on this issue, we modify the regulatory text 

proposed in the NOPR to require each RTO/ISO to settle intertie transactions in the same 

time interval that it schedules intertie transactions. The settlement interval requirement 

for intertie transactions will facilitate the coordination of the scheduling and settlement of 

intertie transactions, and will discourage inefficient practices such as the chasing of 

inaccurate intertie prices. For example, if there are very high prices in the first fifteen 

minutes of an hour, resources will know that for that entire operating hour, there will be a 

high integrated hourly price. This provides an incentive for resources to increase the 

volume of intertie transactions for the remainder of the hour, even if the price for the 

subsequent fifteen-minute interval is much lower reflecting that it may no longer be 

efficient to schedule such intertie transactions. Most commenters, as described above, 

agree that such a requirement will aid in the achievement of these goals. 

89. However, a difference of opinion exists between PJM and the PJM Market 

Monitor. PJM supports moving to a five-minute settlement interval for intertie 

transactions while the PJM Market Monitor supports aligning the settlement interval for 

intertie transactions with the fifteen-minute scheduling interval for these transactions. 

90. If an RTO/ISO settles or proposes to settle intertie transactions using a shorter 

time interval than by which it schedules such transactions, the RTO/ISO may propose to 

do so in its compliance filing and demonstrate that such a proposal is consistent with or 

superior to the Commission’s intertie reforms. The compliance filing proceeding will 

provide a forum in which to consider alternative practices and resolve disputes that may 
Docket No. RM15-24-000 - 52 -

arise within regions, as well as provide for the development of a more complete record on 

these issues. 

91. We decline to clarify for CAISO that the availability of hourly block intertie 

bidding options would not violate the settlement interval requirement for interties. Such 

a determination is more appropriately made upon reviewing CAISO’s compliance filing 

and CAISO should justify its proposed treatment for intertie transactions there.

4. Demand Response Resources

a. Comments 

92. Several commenters discuss the application of the settlement interval proposal to

demand response resources even though the Commission did not specifically solicit those 

comments and did not make a separate proposal concerning demand response resources 

apart from other resources considered in the NOPR. 

93. The PJM Market Monitor, with the New Jersey Board concurring, recommends 

that five-minute pricing in energy markets explicitly cover all resources providing 

energy, including demand side and storage resources.

135

 PJM Market Monitor 

recommends that the Commission require any associated, necessary metering associated 

with applying the requirement to demand resources.136 

94. Public Interest Organizations also urge the Commission to make clear that its 

proposed reforms apply to all resources able to participate in wholesale energy 

 

135 PJM Market Monitor Comments at 2; New Jersey Board Comments at 2.

136 PJM Market Monitor Comments at 2; New Jersey Board Comments at 2.
Docket No. RM15-24-000 - 53 -

markets.137 PSEG similarly supports the application of the settlement interval proposal to 

demand response resources. PSEG states that real-time settlements for demand response 

resources, or any other load-side resources that are price responsive in wholesale markets, 

should be based on five-minute intervals, in the same manner as the supply resources 

with which it competes.138 PSEG acknowledges that some demand resources will lack 

necessary meters and/or communication, and states that it would be reasonable to allow 

these resources a transition period to install them without delaying overall 

implementation.139

95. AEMA states that it recommends that demand response resources have the option 

to continue to settle on the basis of one-hour meter readings. AEMA asserts that demand 

resources use hourly intervals because only hourly interval metering may be available 

and even new advanced metering infrastructure is only capable of fifteen minute interval 

data, whereas settling on five-minute intervals could entail adding an expense that is an 

economic barrier to entry for some resources.

140

 

96. AEMA also states that few demand response resources have the operational 

communications to modify their demand at frequent intervals and that frequent demand 

 

137 Public Interest Organizations at 5.

138 PSEG Comments at 5.

139 PSEG Comments at 5.

140 AEMA Comments at 4.
Docket No. RM15-24-000 - 54 -

changes would require more robust communications than may be economic.141 AEMA 

further states that the Net Benefits Price Threshold that many RTOs/ISOs established in 

response to FERC Order No. 745 is applied on an hourly basis and that the industry has 

universally adopted hourly baseline methodologies for demand response resources.

142

97. AEMA explains that much of the current energy-related demand response 

participation relies on the commitment to dispatch for one or more hours and if the bidoffer is accepted for demand response resources, those resources are eligible for uplift 

payments if the energy prices fall below their bid-offer during their committed dispatch 

time. AEMA requests that these bid offer guarantees continue to be incorporated in the 

Final Rule.143

b. Commission Determination 

98. In using the term “resource” in the NOPR, the Commission intended for the 

settlement interval proposal to apply to all supply resources, including demand response 

resources. We find that, as with other resources, aligning the price signal and dispatch 

signal provides demand response resources capable of following a given dispatch signal 

the incentive to do so, resulting in a more efficient use of demand response resources in 

the real-time energy and operating reserve markets. As stated above, all RTOs/ISOs have 

 

141 AEMA Comments at 4.

142 AEMA Comments at 3-5 (citing Order No. 745, FERC Stats. & Regs. 

¶ 31,322).

143 AEMA Comments at 5.
Docket No. RM15-24-000 - 55 -

a combination of resources, some of which can respond within five minutes and some 

that cannot, and that includes demand response resources. It is important to provide a 

price signal to all resources, regardless of type or capability, as this will provide proper 

compensation to those resources capable of responding to five-minute dispatch signals, 

and will incentivize such capability to those resources that do not currently have it. 

99. In response to concerns about the need to upgrade metering technology for 

demand response resources, we note that this Final Rule does not contemplate requiring 

any new metering capability, such as five-minute revenue quality metering, and that such 

metering is not necessary for implementation given RTOs’/ISOs’ ability to create 

five-minute load and generation profiles using telemetry and hourly revenue quality data. 

We also do not require any changes to baseline methodologies. Although a more 

granular baseline may provide additional value, RTOs/ISOs need not change their 

baseline methodology to comply with this Final Rule. Finally, we find that AEMA’s 

arguments regarding the Net Benefits Price Threshold144 and “make whole” rules are 

beyond the scope of this Final Rule because it does not require any changes to the 

Net Benefits Price Threshold or make-whole payments. Even if modest changes to these 

provisions were required for RTOs/ISOs to comply with this Final Rule, the benefits of 

this rule would justify such modifications.

 

144 AEMA Comments at 3. 
Docket No. RM15-24-000 - 56 -

5. Load

a. Comments

100. A number of commenters state the proposed rule did not specify whether the 

settlement interval proposal would apply to load,145 or, in other words, whether it would 

change how load is settled and measured.

101. EEI, PSEG, SCE, AEMA, EPSA and CAISO recommend that the Commission not 

apply the settlement reform to load.

146

 The primary arguments these commenters cite 

against applying the settlement interval proposal to load include: (1) the benefit of 

settling load on an interval basis is not likely to outweigh the cost, which may include the 

need for new expensive metering;147 (2) settlement reform alone will not encourage price 

responsive load without corresponding changes to state-jurisdictional retail rate design;148

and (3) because load is not dispatchable, there is no dispatch interval that aligns with 

load.149 Direct Energy recommends either not applying the settlement reform to load or 

delaying implementation until the majority of load has the ability, incentive and 

 

145 For purposes of this Final Rule, the term “load” generally refers to 

consumption of electricity in the wholesale markets, but not to demand response acting as 

a supply resource in the wholesale markets.

146 EEI Comments at 8-9; PSEG Comments at 5-6; SCE Comments at 2; AEMA 

Comments at 4-5; EPSA Comments, Pope Aff. at 6-7; CAISO Comments at 16-17.

147 SCE Comments at 2.

148 SCE Comments at 2.

149 CAISO Comments at 16-17.
Docket No. RM15-24-000 - 57 -

information necessary to respond to five-minute settlements.

150

 EEI specifically requests

that the Commission clarify that it is not proposing to change how load is metered.151 

102. PJM, however, states that it is advantageous to apply the proposed rule to load, 

and proposes to settle load on the same interval as dispatch intervals by using a 

combination of state-estimator and telemetry data for each settlement interval.152 PJM 

states that it thus does not foresee changes being required for market participants’ 

metering.153 

103. Mr. Centolella states that advancing load settlements to reflect the actual interval 

demand of each load serving entity’s customers could remove an important barrier to 

developing the next generation of responsive demand. Mr. Centolella also encourages 

the Commission to work with states to optimize collecting customer data, and to evaluate 

how to support efficient price formation related to the load data used in wholesale 

settlements.154

 

150 Direct Energy Comments at 7. See also Supplemental Comments of 

Direct Energy (filed Mar. 4, 2016).

151 EEI Comments at 8-9.

152 PJM Comments at 5.

153 PJM Comments at 5.

154 Mr. Centolella Comments at 4-6.
Docket No. RM15-24-000 - 58 -

b. Commission Determination

104. We clarify that the Commission did not propose to apply the settlement interval 

proposal to load. We also clarify that adoption of the settlement interval requirements are 

not intended to change how load is metered. The Commission’s basis for requiring 

changes to the settlement interval focused exclusively on supply resources rather than 

load. As a result, we have no record to require any changes to the settlement interval for 

load. However, we are not prohibiting settling load on a five-minute basis, and will 

evaluate any such proposals on a case-by-case basis in separate proceedings submitted 

pursuant to section 205 of the FPA.

B. Shortage Pricing Reform

1. Need for Reform

105. In the NOPR, the Commission stated that shortage prices send a short-term price 

signal to provide an incentive for the performance of existing resources and help to 

maintain reliability. The Commission noted that some RTOs/ISOs currently restrict the 

use of shortage pricing to certain causes of shortages, or some RTOs/ISOs require a 

shortage to exist for a minimum amount of time before triggering shortage pricing.155 

The Commission further noted that not invoking shortage pricing when there is a 

shortage (regardless of the duration or cause of that shortage) distorts price signals that 

are designed to elicit increased supply and to compensate resources for the value of the 

 

155 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 46.
Docket No. RM15-24-000 - 59 -

services they provide when the system needs energy or operating reserves. Because these 

price signals fail to reflect adequately the value that a resource provides to the system, the 

Commission preliminarily found in the NOPR that the resulting price is not just and 

reasonable.156

106. The Commission also noted that its rationale regarding shortage pricing was 

similar to the rationale the Commission relied on in Order No. 719, in which the 

Commission determined that “rules that do not allow for prices to rise sufficiently during 

an operating reserve shortage to allow supply to meet demand are unjust, unreasonable, 

and may be unduly discriminatory” and that such rules “may not produce prices that 

accurately reflect the value of energy.”157 

107. Commenters generally support the rationale provided by the Commission in 

support of the need for reform. For example, as discussed below, MISO, NYISO and 

ISO-NE all support the need for reform, and CAISO supports the conceptual need, but 

requests further clarifications. EEI and EPSA also support the Commission’s shortage 

pricing proposal. Conversely, SPP and PJM, in joint comments, oppose implementing 

shortage pricing in all dispatch intervals, and request revisions if the Commission adopts 

its proposed reforms. 

 

156 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 47.

157 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 48 (citing Order No. 719, FERC 

Stats. & Regs. ¶ 31,281 at P 192).
Docket No. RM15-24-000 - 60 -

108. Based on analysis of the record, we adopt our preliminary findings and conclude 

that existing shortage pricing triggers that do not invoke shortage pricing when there is a 

shortage (regardless of duration or cause) are unjust and unreasonable and are unduly 

discriminatory and preferential. Thus, there is a need to reform the use of shortage 

pricing in RTO/ISO markets, as discussed further herein. 

2. NOPR Proposal

109. In order to remedy the potentially unjust and unreasonable rates caused by 

restrictions on shortage pricing, the Commission proposed to require that RTOs/ISOs 

institute mechanisms that trigger shortage pricing for any dispatch interval during which 

a shortage of energy or operating reserves occurs. 

3. Comments on the Proposed Shortage Pricing Reform

a. Comments by RTOs/ISOs

110. MISO states that it supports shortage pricing reform and maintains that MISO’s 

current practices are already consistent with the Commission’s proposal. Specifically, 

MISO states its operating reserve demand curve is used in the five-minute dispatch 

interval and triggers shortage pricing in any five-minute interval in which operating 

reserve requirements cannot be fully satisfied, regardless of duration or causation.158 

MISO also states that its recent implementation of extended locational marginal pricing 

(ELMP) considers offline fast-start resources in its price setting algorithm to more 

 

158 MISO Comments at 10.
Docket No. RM15-24-000 - 61 -

accurately reflect the cost of the next MW to meet demand during scarcity conditions.159 

MISO notes that if no economic offline fast-start resources are eligible, it will rely upon 

the operating reserve demand curve values for shortage pricing. MISO states that it is 

already compliant with the proposed rule on shortage pricing.160

111. ISO-NE supports the shortage pricing proposal and asserts that its current market 

rules and real-time pricing systems already comply with the proposed requirement.161

112. NYISO supports the shortage pricing proposal, and states that it uses demand 

curves to price all reserve shortages, regardless of their duration. NYISO adds that it 

currently implements shortage pricing in its day-ahead and real-time markets using 

various demand curves for operating reserves, regulating reserves, and transmission 

security, where the demand curves represent the escalating value of each product as the 

level of any shortage increases.162 NYISO also states that it does not interpret the NOPR 

to be addressing the use of offline resources in real-time pricing or to be implying that 

 

159 See MISO, Extended Locational Marginal Pricing, Docket No. ER12-668-000 

(filed Dec. 22, 2011).

160 MISO Comments at 11-12.

161 ISO-NE Comments at 3.

162 NYISO Comments at 6.
Docket No. RM15-24-000 - 62 -

practices, such as the NYISO’s “Hybrid Pricing” rules,163 are inconsistent with the 

NOPR.164

113. CAISO agrees with the concept behind the shortage pricing reform and supports 

its implementation, subject to certain clarifications. CAISO expects that its existing tariff 

provisions implementing scarcity pricing for energy and ancillary services already 

comply with the NOPR’s proposal. CAISO explains that, in any fifteen-minute interval 

of the fifteen-minute market, it will co-optimize the procurement of energy and ancillary 

services based on submitted supply bids and the forecast of demand and its ancillary 

services requirements. CAISO further explains that, in any given fifteen-minute interval, 

if effective supply bids are insufficient to clear forecasted demand, scarcity pricing will 

trigger and thereby indicate a shortage of supply for that applicable fifteen-minute

interval. CAISO states that, similarly, if ancillary services bids are not sufficient to meet 

the ancillary services procurement target, ancillary services scarcity pricing will trigger 

for that interval.165

 

163 NYISO’s Hybrid Pricing rules were adopted in 2001. See New York Indep. Sys. 

Operator, Inc., 95 FERC ¶ 61,121 (2001). The Hybrid Pricing rules apply to Real-Time 

Market pricing and relax the minimum operating limits of certain fast-start, block-loaded 

resources in order to permit them to be eligible to set price based on the incremental need 

that required their commitment.

164 NYISO Comments at 7.

165 CAISO Comments at 20.
Docket No. RM15-24-000 - 63 -

114. CAISO notes that within a fifteen-minute operating interval it may need to deploy 

operating reserves to address a contingency in the case of operating reserves, or in the 

case of regulation to continuously balance supply and demand. CAISO states that it is 

important that the Final Rule clarify that the deployment of operating reserves or 

regulation does not necessarily mean a shortage exists. CAISO notes that in some cases

the deployment of reserves is made through alternative deployment mechanisms and not 

in the co-optimization function of the market.166 CAISO also explains that in any given 

fifteen-minute market interval, if a shortage is observed, shortage pricing will trigger 

within that interval and CAISO will not wait for the shortage to materialize beyond that 

interval before triggering shortage pricing. However, CAISO states that not all price 

signals triggered by “transient shortages” provide incentives to resources that have the 

capability to respond to brief-duration shortages.167

115. PJM and SPP filed joint comments opposing triggering shortage pricing in any 

dispatch interval in which a shortage of energy or operating reserves occurs. First, PJM 

and SPP state that they support shortage pricing only when “a shortage of a particular 

 

166 CAISO explains that during each fifteen-minute interval in which the resources 

are deployed, the system is not actually short of supply bids when the operating reserves 

for that interval are procured. Also, CAISO states that once the reserves are deployed, to 

the extent that the market allows for full recovery of the required reserves, the 

contingency event itself does not trigger scarcity pricing for ancillary services. 

According to CAISO, this is because no actual shortage of operating reserves exists 

unless there are insufficient resources to meet operational needs for operating reserves in 

the next applicable fifteen-minute market interval. CAISO Comments at 21-22.

167 CAISO Comments at 23.
Docket No. RM15-24-000 - 64 -

product exists that presents reliability concerns.”

168

 PJM and SPP argue that applying 

shortage prices to shortage events that do not cause reliability concerns allows price 

increases even when such events are transitory, do not pose reliability concerns, and 

cannot be addressed due to limitations on resource response. PJM and SPP maintain that 

applying shortage pricing to some transient shortages will give inaccurate prices and 

could potentially degrade system reliability, and may also result in market pricing and 

operations that are contrary to the Commission’s stated goals.169

116. PJM and SPP further state that they have in place rules related to this issue 

consistent with the principles and goals of shortage pricing. PJM and SPP urge the 

Commission to provide flexibility by allowing RTOs/ISOs to implement shortage pricing 

in the context of their regional rules. This, PJM and SPP assert, will ensure that 

inefficient pricing does not result.170

117. PJM and SPP argue that allowing transient periods of shortage to trigger shortage 

pricing could overstate the severity of the operating condition and result in prices that do 

not accurately reflect operating conditions on the system, or last long enough to allow 

market participants responding to them to take meaningful action. In fact, PJM and SPP 

assert that responses may occur after the relevant interval has passed, which could be 

 

168 PJM and SPP Comments at 1.

169 PJM and SPP Comments at 1-2.

170 PJM and SPP Comments at 2-3.
Docket No. RM15-24-000 - 65 -

counterproductive operationally and economically. PJM and SPP pose two examples to 

illustrate this point. As the first example, they posit: PJM carrying the required amount 

of reserves when a market seller of a generation resource lowers the resource’s economic 

maximum capability, for a brief time (ten minutes or less), causing PJM to have less 

reserves than its requirement. Currently, PJM can recover these reserves by re-executing 

its dispatch engine and re-dispatching its system; but under the shortage pricing reform, 

this could invoke shortage pricing, which would then attract more suppliers than needed 

and create disincentives for resources to back down once the event was over. In another 

example, they posit: PJM has scheduled a resource with a ten-minute start-up time to 

come online to provide energy so that another resource may be reduced to provide 

reserves; but if the resource scheduled to come online actually takes twenty minutes 

instead of ten, shortage pricing would be triggered under the shortage pricing proposal, 

and the second resource, instead of having its output reduced to provide reserves would 

now need to continue to provide energy, thus potentially leaving PJM short on reserves 

for a brief period.171

118. PJM and SPP introduce another hypothetical scenario from the SPP region. PJM 

and SPP state that SPP can temporarily use operating reserves to meet energy 

requirements during transient periods when system conditions do not present reliability 

concerns. PJM and SPP argue that while this may technically compromise the operating 

 

171 PJM and SPP Comments at 4.
Docket No. RM15-24-000 - 66 -

reserve requirement, the condition is transient and is recovered in less than ten minutes. 

According to PJM and SPP, this is not an operating reserve shortage, but rather a 

transient reallocation of capacity to manage temporary energy needs caused by the 

operational characteristics of resources. PJM and SPP further state that the examples 

described above do not present emergency conditions or reliability concerns that would 

justify shortage pricing.

172

119. In order to “recognize and respect the fact that not all instances of shortages justify 

shortage pricing,” PJM and SPP propose alternative language for any Final Rule on 

shortage pricing:

Each RTO/ISO must establish tariff provisions that implement 

shortage pricing for pre-defined operating conditions related to a 

shortage of energy or operating reserves. The Commission will 

allow each RTO/ISO to develop those provisions based on their 

regional circumstances, provided that the rules are consistent with 

shortage pricing principles and are designed to facilitate the goals of 

this [Final Rule]. The Commission expects that each RTO/ISO will 

explain why their provisions, or why their current rules, comply with 

this rule.

173

 

120. PJM and SPP further assert that a universal shortage pricing rule requiring 

shortage pricing even for transient circumstances would require the implementation of 

operating reserve demand curves that distinguish prices relative to varying degrees of 

shortage. PJM and SPP explain further that in PJM’s case, the current operating reserve 

 

172 PJM and SPP Comments at 5-6.

173 PJM and SPP Comments at 7. 
Docket No. RM15-24-000 - 67 -

demand curves are a step function, which would need to be changed, and in SPP’s case it 

would likely consider the implementation of a pricing gradient demand curve based on 

different degrees of shortages and their impact on reliability, rather than steep step 

curves.

174

b. Comments by Market Monitors

121. Potomac Economics explains that all the markets that it monitors (ISO-NE, 

NYISO, and MISO) are designed to price all shortages, regardless of duration.175 

Potomac Economics states that it strongly supports the shortage pricing reform and 

argues that pricing all shortages, regardless of duration, provides efficient incentives for 

resources to be flexible and to perform well, which ultimately lowers costs to consumers 

and improves reliability.176 Potomac Economics states that, together with the alignment 

of dispatch and settlement intervals, a requirement for RTOs/ISOs to price “transitory 

shortages” rewards units that can respond quickly to help the RTO/ISO remedy the 

shortage and, in doing so, addresses the diminished reliability caused by the shortage.177 

122. Potomac Economics states that transitory shortages typically occur when the 

system is ramp-constrained, and that these are true shortages, because if a large 

contingency occurs during this period (e.g., a generator tripping off-line), the RTO/ISO 

 

174 PJM and SPP Comments at 8.

175 Potomac Economics Comments at 9.

176 Potomac Economics Comments at 7. 

177 Potomac Economics Comments at 7.
Docket No. RM15-24-000 - 68 -

will not have the ability to replace the capacity because its other generators are already 

ramping as quickly as possible. Potomac Economics states that the Commission’s 

proposal will lead to resources offering faster ramp rates, offering wider dispatch ranges 

and not self-scheduling resources, and offering shorter start times for natural gas turbines. 

Potomac Economics states that the proposal also has important long-term implications as 

it provides efficient incentives for participants to build more flexible, fast-ramping 

generating resources, and to make maintenance decisions on existing resources to 

increase their flexibility.178

123. Potomac Economics also states that allowing offline resources to set real-time 

energy and ancillary services prices can be efficient, but there are also conditions under 

which the use of these resources can artificially lower energy prices and obscure 

shortages.179 Potomac Economics explains that if an RTO’s/ISO’s pricing model allows 

infeasible or uneconomic units to set prices, the offline units represent an artificial 

increase in real-time supply that will depress real-time prices. Further, Potomac 

Economics explains that the artificial increase in real-time supply can have a large effect 

when the system is experiencing an operating reserve or transmission shortage, which is 

ultimately not priced as a shortage because an offline unit has set the price.180

 

178 Potomac Economics Comments at 8.

179 Potomac Economics Comments at 9.

180 Potomac Economics Comments at 10.
Docket No. RM15-24-000 - 69 -

124. Potomac Economics recommends that the Commission require RTOs/ISOs to 

demonstrate that their real-time pricing models do not allow offline units to set prices in a 

manner that undermines its real-time shortage pricing. Potomac Economics believes that 

this can be demonstrated by the RTO/ISO describing how and when offline units set realtime prices and showing that when offline units have set price historically that they are 

generally committed and dispatched as well. Potomac Economics further asserts that if 

the RTOs/ISOs cannot demonstrate this in their compliance filing, then they may need to

make changes to their pricing models to ensure that they satisfy the Commission’s price 

formation goals.

181

 

125. The PJM Market Monitor states that five-minute shortage pricing would correctly 

reflect actual shortage conditions and should be implemented if PJM can accurately 

measure the level of reserves on a five-minute basis, which the PJM Market Monitor 

understands that PJM currently cannot do. The PJM Market Monitor asserts that, without 

accurate measurement of reserves at minute-by-minute granularity, system operators 

cannot know with certainty that a shortage condition exists, thus masking the trigger for 

five-minute shortage pricing. The PJM Market Monitor recommends that if PJM cannot 

measure operating reserves on a five-minute basis, the Commission should direct PJM to 

develop methods to do so. The PJM Market Monitor asserts that if RTOs/ISOs cannot 

 

181 Potomac Economics Comments at 9-11. 
Docket No. RM15-24-000 - 70 -

demonstrate that they can accurately measure reserves at minute-by-minute granularity, 

they should not implement five-minute shortage pricing until they have that capability.182

126. The SPP Market Monitor supports the Commission’s proposal to require 

RTOs/ISOs to trigger shortage pricing for any dispatch interval during which a shortage 

of energy and operating reserves occurs. The SPP Market Monitor states that SPP’s 

Integrated Marketplace uses administratively-determined scarcity pricing demand curves 

to set prices during capacity shortages. The SPP Market Monitor explains that, during 

shortages, quick-start and fast-ramping resources – which generally have higher costs and 

low capacity factors – earn a significant portion of their annual revenue. The SPP Market 

Monitor asserts that scarcity pricing serves as an important mechanism for sending 

correct price signals to these resources; however, the SPP Market Monitor states that SPP 

is not sending this price signal during ramp-constrained operating reserve shortages since 

the SPP market rules do not allow insufficient ramping capability to trigger scarcity 

pricing of operating reserves.183 The SPP Market Monitor requests that the Commission 

address the ramp-constrained operating reserve shortage pricing issue in the Final 

Rule.184

 

182 PJM Market Monitor Comments at 9.

183 SPP Market Monitor Comments at 4 (citing SPP Tariff, Attachment AE 

§§ 5.1.2.1 and 8.3.4.2).

184 SPP Market Monitor Comments at 4-6.
Docket No. RM15-24-000 - 71 -

c. Comments Supporting the Shortage Pricing Reform

127. Several other commenters express support for shortage pricing reform. These 

commenters agree that the proposed shortage pricing reform will increase transparency, 

create incentives to trigger quick response from supply, promote investment in resources 

that can respond to short duration shortages, and provide revenues to resources that 

reflect the value of the service provided.185 In addition, several commenters, including 

EPSA and Westar, support the shortage pricing proposal and state that it should apply to 

all shortages, regardless of duration.186 

 

185 Ameren Comments at 1, 3-4; ANGA Comments at 2-5; CAISO Comments 

at 2; CEA Comments at 3-6; Dominion Comments at 1-2; DTE Comments at 3-4; 

EDP Renewables Comments at 2; EEI Comments at 2; ESA Comments at 2-4; 

Entergy Nuclear Power Marketing Comments at 2; EPSA Comments at 1-5; Exelon 

Comments at 4; Financial Marketers Coalition Comments at 1; Golden Spread Initial 

Comments at 1-3; Inertia Power and DC Energy Comments at 2; ISO-NE Comments at 1; 

MISO Comments at 2, 9; NEI Comments at 1; NGSA Comments at 2-5; PJM Power 

Providers Comments at 2-5; Potomac Economics Comments at 2; Powerex Comments 

at 6; PSEG Comments at 3; Public Interest Organizations Comments at 5; SPP 

Market Monitor Comments at 2; Westar Comments at 1; Duke Comments at 7.

186 EPSA Comments at 9; EPSA Comments, Pope Aff. at 15; Golden Spread 

Initial Comments at 6; PJM Power Providers Comments at 4; Powerex Comments at 6; 

EDP Renewables Comments at 5-6; Entergy Nuclear Power Marketing Comments at 2; 

Exelon Comments at 6; PSEG Comments at 13; Westar Comments at 5; NEI Comments 

at 14; CEA Comments at 4; NGSA Comments at 5.
Docket No. RM15-24-000 - 72 -

128. Several commenters support the Commission’s shortage pricing proposal, arguing 

that market clearing prices should reflect shortage or emergency situations so that 

generators are provided transparent price signals that reflect the market conditions.

187

 

EPSA and Westar note that reflecting a shortage price signal during transient shortage 

events will result in a price signal that incents resources to respond to real-time system 

constraints based on a price that reflects the value of loss of load even if the event is less 

than ten minutes in duration.188 Further, Westar states that if the “steepness” of 

regulation and operating reserve demand scarcity pricing curves is a concern then an 

RTO/ISO should create separate operating reserve scarcity demand curves for transitory 

periods versus periods lasting longer than ten minutes.189 

129. Some commenters state that the shortage pricing proposal will provide an 

incentive for existing resources to offer their supply and to be available if shortages occur 

and will provide an incentive for incremental investments to enable existing or new 

generation or dispatchable demand to respond to shortages, regardless of duration.190 

Further, CEA states that without appropriate compensation prices invariably become 

distorted insofar as they do not reflect the increased value of that resource with utmost 

 

187 EEI Comments at 10; EPSA Comments at 9; PJM Power Providers Comments 

at 4; Westar Comments at 5; NEI Comments at 14.

188 EPSA Comments at 9; Westar Comments at 5.

189 Westar Comments at 5.

190 EPSA Comments, Pope Aff. at 15; NEI Comments at 14; CEA Comments at 4; 

NGSA Comments at 5.
Docket No. RM15-24-000 - 73 -

accuracy and granularity.191 In addition, NGSA comments that the proposal will 

encourage investments by generators that allow them to more reliably perform, leading to 

greater regional fuel assurance.192

130. ANGA states that while a shortage may be transient and last only a single 

five-minute interval, some resources are able to move quickly enough to meet these shifts 

in demand and, hence, reduce overall system instability. Further, ANGA maintains, 

allowing prices to respond to these small shortages also sends a long-term price signal to 

the market, highlighting where and what types of resources are needed on the system,

which improves overall system reliability. ANGA also agrees with EPSA’s position, 

recorded in the NOPR, that all markets should prioritize establishing shortage pricing 

based on operating reserve demand curves and co-optimized with the energy market. 

ANGA states that this is a least-cost solution and recommends that the Commission 

direct the RTOs/ISOs to include in their compliance filing a plan for modifying their 

rules, to the extent necessary, to include these features in both the day-ahead and 

real-time markets.193

131. Powerex supports the Commission’s proposal to require RTOs/ISOs to apply 

shortage pricing for any dispatch interval during which a shortage of energy or operating 

 

191 CEA Comments at 4.

192 NGSA Comments at 5.

193 ANGA Comments at 5.
Docket No. RM15-24-000 - 74 -

reserves occurs.

194

 Powerex contends that shortage pricing mechanisms tied to real-time 

conditions provide revenues to generators and demand side resources that provide energy 

and reserves when needed, which is an advantage over the capacity markets long-term 

focus on load growth and reliability.195 

132. EDP Renewables states that the Commission’s shortage pricing proposal would 

result in more accurate price signals than under existing market rules, and therefore 

would encourage greater investment in new production and storage technologies with the 

ability to respond quickly to shortages.196 Similarly, ESA asserts that the shortage 

pricing reform will improve the ability for a resource to be compensated based on the 

value of the service the resource provides.197 ESA maintains that, for energy storage 

resources to help ensure grid reliability, an economic incentive must exist to incorporate 

those resources onto the grid.198 

133. Exelon and Inertia Power assert that implementing shortage pricing for any 

interval during which a shortage could occur will provide the right incentives for 

generating resources and will promote adequate incentives for resource adequacy. 

Exelon and Inertia Power state that it is economically more efficient for prices to reflect 

 

194 Powerex Comments at 6.

195 Powerex Comments at 8.

196 EDP Renewables Comments at 5-6.

197 ESA Comments at 4.

198 ESA Comments at 4.
Docket No. RM15-24-000 - 75 -

the value of the marginal resource during shortage periods, and that this is particularly 

true in instances where generation resources must compete with alternatives, such as 

exporting power to a neighboring market or not consuming a scarce fuel.199 

134. PSEG states that it supports the shortage pricing proposal, that the proposal would 

address concerns about transparency, and that it would accomplish Order No. 719’s 

objective of enhancing market efficiency by establishing a price that reflects the value of 

the loss of load and encourage resources to respond to shortage events.200 PSEG further 

states that the absence of shortage pricing in the appropriate intervals is inefficient within 

individual RTOs/ISOs as well as between them, and it can frustrate the objectives of 

Coordinated Transaction Scheduling, which is currently being deployed by several 

RTOs/ISOs.201

135. Golden Spread supports the Commission’s proposed shortage pricing reform and 

argues that even the smallest amount of operating reserve and energy shortage should be 

reflected in scarcity pricing.202 Golden Spread states that it has invested hundreds of 

millions of dollars in a fleet of new quick-start, fast-ramping generation resources in 

anticipation of the proper working of efficient marginal cost-based energy markets. 

Golden Spread states that to the extent these resources are not fully compensated because 

 

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

200 PSEG Comments at 13.

201 PSEG Comments at 14.

202 Golden Spread Reply Comments at 4. 
Docket No. RM15-24-000 - 76 -

shortage pricing is masked, the value of these assets to Golden Spread’s members and 

their consumers is diminished.203

136. DTE states that, as a member of MISO, it has largely supported the changes MISO 

has made through ELMP to ensure that generators are provided accurate price signals, 

akin to the shortage pricing proposal.204 

d. Comments Recommending Changes to the Shortage 

Pricing Reform

137. Several commenters propose changes to the shortage pricing reform, or identify 

implementation issues in specific RTOs/ISOs. 

138. Golden Spread, for example, states that the current SPP rules allow the temporary 

use of operating reserves to meet energy requirements during transient periods without 

invoking shortage pricing; in other words, SPP’s rules encourage “price manipulation”

undermining the transparency needed to incentivize longer term economic and reliable 

solutions.205 

139. Golden Spread identifies examples of issues with certain SPP processes that it 

argues need to be addressed to comply with this reform and provides the following 

recommendations to resolve them: (1) relax constraints to allow economic dispatch to 

solve when there is a resource capacity constraint, global power balance constraint, 

 

203 Golden Spread Reply Comments at 7.

204 DTE Comments at 5.

205 Golden Spread Reply Comments at 5.
Docket No. RM15-24-000 - 77 -

resource ramp constraint or operating constraint;206 (2) prevent insufficient ramping 

capability to be subject to scarcity pricing;207 (3) include fast-start technologies in a 

Reliability Unit Commitment action to avoid scarcity events, which then eliminates 

scarcity prices;208 and (4) use of the concept of “head-room” to not factor much-needed 

ramping capacity in the LMP, which is reducing transparency and creating large 

uplifts.209

140. ELCON states that the shortage pricing proposal should be adopted only if the 

Commission promotes the development of technology-neutral fast-ramp products paid to 

provide the specific shortage service, and for which compensation would not inflate realtime LMPs.210

 ELCON asserts that it conditionally supports the provision on shortage 

price triggers when applied to technology-neutral fast-ramping products – products it 

states could be provided by demand response, energy storage technologies, or generation

– but not to real-time shortage pricing in which every resource dispatched or called by the 

system operator during a dispatch interval is paid the same price.211

 

206 Golden Spread Comments at 8.

207 Golden Spread Comments at 7-8.

208 Golden Spread Comments at 9-10.

209 Golden Spread Comments at 10.

210 ELCON Comments at 2.

211 ELCON Comments at 3-6.
Docket No. RM15-24-000 - 78 -

e. Comments Opposed to the Proposed Shortage Pricing 

Reform

141. Several commenters oppose the shortage pricing proposal. Several commenters

argue that while the NOPR does not address the price level of the shortage pricing, to the 

extent that RTOs/ISOs do change shortage pricing triggers, the RTOs/ISOs should also 

evaluate whether shortage pricing levels remain just and reasonable.212 For example, 

Concerned Cooperatives and APPA and NRECA argue that the NOPR will raise prices 

for consumers, but the Commission fails to quantify the cost impact of the shortage 

pricing proposal on consumers or the potential benefits to the market and consumers.213

Concerned Cooperatives add that any changes to the shortage pricing triggers in the 

RTO/ISO markets must be cost-justified on the basis of quantifiable improvements in 

market efficiencies and cost reductions. Furthermore, Concerned Cooperatives argue that 

the Commission’s shortage pricing will raise prices for consumers and increase revenues 

to incumbent generators.214 

142. APPA and NRECA assert that it is important to understand how various resource 

types would respond to price signals created by the shortage pricing proposal. 

Specifically, they assert that the NOPR did not discuss whether a five-minute shortage 

 

212 APPA and NRECA Comments at 12; TAPS Comments at 14-15; Concerned 

Cooperatives Comments at 13.

213 Concerned Cooperatives Comments at 13-14; APPA and NRECA Comments 

at 6.

214 Concerned Cooperatives Comments at 13.
Docket No. RM15-24-000 - 79 -

pricing event would produce a sufficient response or only reflect a transient shortage 

resolvable without resorting to shortage pricing.215 APPA and NRECA reference PJM 

representative Adam Keech’s comment at the October 28, 2014 workshop on scarcity and 

shortage pricing, justifying PJM’s current minimum duration of 30 minutes prior to 

triggering shortage pricing, and assert that the shortage pricing proposal runs the risk of 

rewarding generators that are already online just because another generator has not fully 

ramped up yet.216 APPA and NRECA state that the NOPR neither discussed the degree 

to which the RTOs/ISOs are already in compliance with the proposal, the extent to which 

implementation would impact the frequency of shortage pricing events or impact prices, 

nor did it require RTOs/ISOs to undertake this analysis.217 APPA and NRECA state that 

shortage pricing was triggered relatively infrequently in PJM and MISO, but more 

frequently in NYISO.218

143. APPA and NRECA question the extent to which shortage pricing would improve 

short-term system efficiency. They comment that existing variations among RTOs/ISOs 

in shortage pricing approaches create an opportunity to analyze the efficacy of more 

frequent shortage events. They request that the Commission direct the RTOs/ISOs to 

 

215 APPA and NRECA Comments at 6-7.

216 APPA and NRECA Comments at 7.

217 APPA and NRECA Comments at 9.

218 APPA and NRECA Comments at 9-10.
Docket No. RM15-24-000 - 80 -

provide evidence or examine whether the theoretical benefits of the shortage pricing 

proposal can be validated with actual resource decisions. APPA and NRECA caution 

that, without such analysis, entities, such as generators already online that cannot easily 

ramp up or down or financial marketers, could benefit financially without contributing to 

system efficiency.219 Concerned Cooperatives also note that the Commission’s rationale 

that prices must rise to reflect the true value of generation offered during operational

shortages for the market to function properly fails to consider that only half of the market, 

i.e., generators, may be able to respond to the price signal in real-time.220 

144. On the topic of long-term incentives, several commenters assert that no evidence 

exists that price signals as volatile and transient as shortage prices would be the basis for 

capital investments, whether to improve flexibility, whether to delay or avoid retirements,

and especially not for the construction of new resources. APPA and NRECA assert 

that, even with a slight uptick in merchant plant construction compared to prior years, 

95 percent of new construction was built under contract in 2014, and 98 percent of new 

construction was built under contract in 2013.221 Further, Concerned Cooperatives argue 

that the evidence presented at the technical conferences preceding the NOPR demonstrate 

 

219 APPA and NRECA Comments at 10-11.

220 Concerned Cooperatives Comments at 14.

221 APPA and NRECA Comments at 11-12; TAPS Comments at 7-13; Concerned 

Cooperatives Comments at 15-16.
Docket No. RM15-24-000 - 81 -

that short-term price signals from shortage pricing do not result in the long-term resource 

investment contemplated in the NOPR.222

145. Concerned Cooperatives contend that the RTOs/ISOs could develop better 

products, such as a fast-ramping product, that could encourage investment in more 

flexible resources without having to pay every resource a high price during shortage 

intervals of short duration.223 Moreover, APPA and NRECA encourage the Commission 

to examine alternative methods of achieving its stated goal of incentivizing the 

availability of resources during periods of shortage, such as separately priced ramping 

products. APPA and NRECA urge the Commission to also examine whether such 

methods might achieve this goal at a lower cost to consumers.224 Concerned 

Cooperatives further argue that the Commission’s proposal is simply a transfer of wealth 

from consumers to generators without value to consumers, because, as the Commission 

admitted in the NOPR, some shortage events are so short that suppliers cannot react to 

the price signal.225

146. ODEC states that, in the example provided by PJM, if a unit is slow in 

coming online for a five-minute interval, it is not clear that shortage pricing would not 

over-compensate a resource, or if supply can even respond to such a short-term event in 

 

222 Concerned Cooperatives Comments at 15-16.

223 Concerned Cooperatives Comments at 22-24.

224 APPA and NRECA Comments at 12.

225 Concerned Cooperatives Comments at 15-16.
Docket No. RM15-24-000 - 82 -

sufficient time for the price signal to create an incentive to change behavior. ODEC 

states that it therefore believes that shortage pricing during transient shortages may be 

unjust and unreasonable because it will increase prices paid by load without 

corresponding benefits.226 

147. APPA and NRECA also express concern that more frequent shortage pricing 

creates incentives to exercise market power and game market rules due to the potential 

for higher energy and operating reserve prices. They assert that if the proposal moves 

forward, each RTO/ISO should be required to reevaluate its market power mitigation 

rules and propose new or additional mitigation measures if necessary.227 In addition, 

Concerned Cooperatives also argue that revising RTO/ISO tariffs to invoke shortage 

pricing more frequently is likely to increase opportunities for exploitation of consumers, 

but that the NOPR does not propose to require RTOs/ISOs to include in their compliance 

filings an analysis of needed reforms to ensure that consumers remain protected against 

the exercise of market power.228 

148. Concerned Cooperatives also argue that if the Commission issues a final rule in 

this proceeding, RTOs/ISOs must be required to demonstrate that their shortage pricing 

mechanisms comply with four overarching principles, by providing for (1) prices that 

 

226 ODEC Comments at 6.

227 APPA and NRECA Comments at 15-16.

228 Concerned Cooperatives Comments at 15.
Docket No. RM15-24-000 - 83 -

reflect the marginal costs of meeting the shortage; (2) a cap that is designed to mitigate 

adverse financial impacts on parties who are short; (3) prices that escalate with greater 

levels of shortage, because marginal costs will vary by shortage; and (4) a mechanism to 

ensure that revenues earned through shortage pricing are not duplicated by capacity 

market revenues.229

149. The New Jersey Board urges the Commission to allow PJM to retain its current 

shortage pricing mechanism—a thirty-minute look-ahead dispatch algorithm that 

identifies reserve shortages as only those lasting a minimum of thirty minutes. The 

New Jersey Board agrees with PJM that five-minute shortfalls are not necessarily 

symptomatic of system stress, but are merely transient shortfalls that can be quickly 

addressed through system re-dispatch. 

150. More broadly, TAPS argues that any price signal during transient scarcity events 

is meaningless because resources cannot respond in time to the higher prices.230 In 

addition, Direct Energy says that targeting transient shortages will create control issues 

and increase uplift, and the application of RTO/ISO shortage penalty factors to these 

transient situations will likely lead to higher prices than would otherwise be produced, 

creating unjust and unreasonable rates for generation compensation.231 

 

229 Concerned Cooperatives Comments at 24-25.

230 TAPS Comments at 7-13.

231 Direct Energy Comments at 10-11.
Docket No. RM15-24-000 - 84 -

151. Regarding definitions, Direct Energy asserts that a true shortage implies that 

insufficient capacity exists on an RTO’s/ISO’s system to meet energy and reserve 

requirements. In contrast, Direct Energy argues, transient shortage conditions are not 

true shortages because they simply reflect the operating characteristics of the generators 

being used to meet energy and reserve targets. Direct Energy argues that in a transient 

shortage condition, the RTO/ISO has the capacity to meet energy and reserve 

requirements and the transient shortage period represents the period of time it takes to 

deploy generation resources to meet those targets.232

152. Direct Energy claims the response an RTO/ISO receives based on the shortage 

pricing signals sent during transient shortage conditions is likely to cause a control issue 

when generation already being ramped through RTO/ISO dispatch to resolve the shortage 

condition hits its dispatch targets. Further, Direct Energy argues unjust and unreasonably 

higher prices would result from targeting “transient” shortages because of the impact of 

shortage pricing penalty factors in transient shortage circumstances, because the shortage 

pricing reserve penalty factors would be applied to a marginal unit providing energy that 

is not the highest opportunity cost reserve unit. Thus, Direct Energy argues the 

Commission should either revise its proposal to reflect issues with transient shortages of 

 

232 Direct Energy Comments at 10-11.
Docket No. RM15-24-000 - 85 -

operating reserves, or permit individual RTOs/ISOs to evaluate this proposal and 

consider tariff revisions to address true shortages and to send appropriate price signals.233

153. Concerned Cooperatives and APPA and NRECA argue that the NOPR does not 

account for differences among the RTOs/ISOs, maintaining that shortage pricing issues 

should be resolved through individual stakeholder processes.234 Alternatively, Concerned 

Cooperatives request that the Commission not implement shortage pricing reform until an 

RTO/ISO demonstrates that it has eliminated the conditions that cause “artificial” 

shortages (those arising from mathematical modeling when no actual operational shortage 

exists), adopts rules preventing shortage pricing from being applied during artificial 

shortages, and adopts rules ensuring that shortage price levels are reduced during 

artificial shortages to reflect that these are not real shortages.235

154. Concerned Cooperatives also note that the NOPR fails to provide a comparison of 

the market design in RTO/ISO-administered markets that trigger shortage pricing for a 

shortage event of any duration and those that use longer duration events as the trigger.236 

Concerned Cooperatives argue that, before imposing a uniform rule, the Commission 

should determine whether these different shortage pricing rules have resulted in 

incremental resource development, improved generator response to shortage conditions, 

 

233 Direct Energy Comments at 11-13.

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

235 Concerned Cooperatives Comments at 18.

236 Concerned Cooperatives Comments at 26.
Docket No. RM15-24-000 - 86 -

and/or reduced the need for uplift charges. Concerned Cooperatives state that in some 

cases, uplift payments may be the most cost-effective solution for consumers.237

155. Several commenters point to various efforts in RTOs/ISOs that may impact 

shortage pricing. Concerned Cooperatives argue that the Commission should not address 

price formation issues in a piecemeal fashion, as changes to one element will impact the 

need for other reforms. Concerned Cooperatives note that several RTOs/ISOs already 

have rules providing adequate incentives for resource performance and investment, such 

as PJM’s Reliability Pricing Model, ISO-NE’s Forward Capacity Market, or MISO’s 

ELMP.238 Concerned Cooperatives assert that the Commission provides no evidence that 

more frequent triggering of shortage pricing is necessary to ensure resource adequacy or 

improve resource performance and flexibility when RTOs/ISOs use other market tools to 

achieve the same objectives set forth in the NOPR. 

156. The New Jersey Board, APPA and NRECA and ODEC all acknowledge PJM’s 

Capacity Performance Program239 and argue to varying degrees that shortage pricing need 

not be considered here given this PJM reform or that the Commission should consider 

whether there would be overlap between this PJM reform and the shortage pricing 

 

237 Concerned Cooperatives Comments at 26.

238 Concerned Cooperatives Comments at 18-21.

239 See PJM Interconnection, L.L.C., 151 FERC ¶ 61,208 (2015).
Docket No. RM15-24-000 - 87 -

proposal.240 Furthermore, APPA and NRECA state that another factor in determining 

whether the shortage pricing proposal would improve market efficiency and benefit 

consumers is the extent to which there is an overlap between this proposal and other 

RTO/ISO market rules.241 APPA and NRECA also point out that, in some RTOs/ISOs

such as NYISO, scarcity pricing is an additional and separate revenue stream that can 

balance reliance on capacity market revenues.242 Further, ODEC suggests that, instead of 

requiring an expansion of scarcity pricing to transient time periods, the Commission 

require PJM to consider the need to reduce, if not eliminate, scarcity pricing in light of 

the new Capacity Performance construct.243

157. Concerned Cooperatives note that the NOPR fails to identify the number of 

additional shortages that would be triggered in RTO/ISO markets that do not invoke 

shortage pricing for a single settlement interval. They argue that the NOPR also fails to

quantify what that cost might potentially be for consumers, particularly in PJM, which 

recently sought to increase its energy offer caps to $2,000 per MWh which could produce 

LMPs of $3,700 per MWh during shortage events. Concerned Cooperatives state 

that the NOPR provides no evidence that prices at this level are just and reasonable for a 

 

240 New Jersey Board Comments 4-6; APPA and NRECA Comments at 14. 

241 APPA and NRECA Comments at 13.

242 APPA and NRECA Comments at 14-15.

243 ODEC Comments at 8.
Docket No. RM15-24-000 - 88 -

five-minute shortage where a resource cannot respond and/or the event is triggered by an 

artificial shortage.244 

158. PG&E urges the Commission to examine transient shortages and their attendant 

price spikes, and resolve modeling issues that are causing these shortages. PG&E 

understands that shortage pricing might be appropriate to the extent that such pricing 

provides a meaningful price signal to resources. However, PG&E argues that most price 

spikes in the CAISO over the past five years have been so short that they have not 

provided a meaningful opportunity for resources to respond.245 For example, PG&E 

states that from 2012 through 2014, the CAISO five-minute market saw positive price 

spikes (>$250/ MWh) in approximately 0.75 percent of the intervals. PG&E argues that 

transitory price spikes do not contribute to market efficiency, but result in increased 

market costs, and they give false signals to virtual participants, which can distort 

day-ahead awards and prices. PG&E also asserts that these transitory price spikes have 

contributed to price divergence between day-ahead and real-time and have resulted in 

significant uplift costs.246

159. PG&E notes that CAISO is already taking significant steps to address modeling 

issues that create transient shortages and attendant transient price spikes. For example, 

 

244 Concerned Cooperatives Comments at 25.

245 PG&E Comments at 1-2.

246 PG&E Comments at 1-2.
Docket No. RM15-24-000 - 89 -

PG&E states that CAISO is working to augment the real-time dispatch function with a 

Flexible Ramping Product which will help avoid ramp-induced shortages that cause 

scarcity conditions in real-time. PG&E also explains that CAISO is considering applying 

different penalty prices for infeasibilities depending on the level of constraint relaxation, 

which will more appropriately reflect the cost of constraint violations. PG&E asserts that 

a small violation of the power balance constraint may be covered by deploying regulation 

reserves at a smaller cost per megawatt-hour than a larger violation, which may require 

more costly load shedding.247

160. Dominion states that it is concerned that some shortages are merely transient in 

nature due to slight differences in modeling and the ramping of generation, and may not 

warrant sending a shortage price signal to the market. Dominion argues that issues 

regarding transient shortages should be addressed prior to implementation of the 

proposed reforms.248 Dominion states that the Commission should require RTOs/ISOs to 

specifically explain how the RTOs/ISOs will address this issue as part of their 

compliance filings. Further, Dominion asserts that the modification of shortage pricing 

triggers to better correlate to dispatch intervals should coincide with implementation of 

the Commission’s proposal to align settlement intervals with dispatch intervals. 

 

247 PG&E Comments at 2.

248 Dominion Comments at 4-5.
Docket No. RM15-24-000 - 90 -

Dominion argues that this will align a resource’s timely response to shortage pricing with 

payment for its response.249 

4. Commission Determination

161. For the reasons discussed below, we adopt the NOPR shortage pricing proposal 

and modify the regulatory text to clarify that shortage pricing is required only when a 

shortage of energy or operating reserves is indicated by the RTO’s/ISO’s software. 

162. Specifically, we require each RTO/ISO to trigger shortage pricing for any interval 

in which a shortage of energy or operating reserves is indicated during the pricing of 

resources for that interval. As stated in the NOPR, the shortage pricing requirement

should “ensure that a resource is compensated based on a price that reflects the value of 

the service the resource provides.”250 This rationale applies to any shortage “regardless 

of the duration or cause of [the] shortage.”251 It thus would apply to “transient 

shortages.” Several commenters specifically agreed with this analysis.252 Under this 

requirement, whenever a shortage of energy or operating reserves is indicated in an 

 

249 Dominion Comments at 5.

250 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 52.

251 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 47; see also id. P 9 (“This reform 

would also ensure that resources operating during a shortage are compensated for the 

value of the service that they provide, regardless of whether the shortage is short-lived.”).

252 See, e.g., Inertia Power and DC Energy Comments at 6 (citing NYISO 

Comments, Docket No. AD14-14-000, at 28-29 (Mar. 6, 2015), Potomac Economics 

Comments, Docket No. AD14-14-000, at 25-26 (Mar. 6, 2015), and Calpine Comments, 

Docket No. AD14-14-000, at 20 (Mar. 6, 2015)); SPP Market Monitor Comments at 3; 

Golden Spread Comments at 3-4.
Docket No. RM15-24-000 - 91 -

RTO’s/ISO’s pricing run software for a particular pricing interval, shortage pricing 

should be invoked even if during that period resources are ramping up to a particular 

level they are likely to reach in a few minutes. 

163. We find that the shortage pricing requirement will help ensure that prices rise 

sufficiently and appropriately to allow supply to meet demand during an operating 

reserve shortage, and thus will more accurately reflect the value a resource provides.

253

 

Better formed prices help ensure just and reasonable rates by providing appropriate 

incentives for market participants to follow commitment and dispatch instructions, 

maintain reliability, provide transparency of the underlying value of the service so that 

operational and investment decisions are based on prices that reflect the actual marginal 

cost of serving load and the operational constraints of reliable system operation, and 

encourage efficient investments in facilities and equipment. 

164. As for incentives to follow dispatch, as noted in the NOPR, if a resource is 

compensated based on a price that reflects the value of the service the resource provides, 

the resource will have appropriate incentives to address energy or reserve shortages. As 

explained by Potomac Economics, the higher prices (relative to non-shortage price 

intervals) resulting from the shortage pricing proposal will enhance resource flexibility 

by leading to: (1) faster resource ramp rates; (2) wider dispatch ranges and not selfscheduling resources; (3) shorter start times for natural gas turbines; and (4) an incentive 

 

253 See NOPR, FERC Stats. & Regs. ¶ 32,710 at P 48 (citing Order No. 719, FERC 

Stats. & Regs. ¶ 31,281).
Docket No. RM15-24-000 - 92 -

to build more flexible, fast-ramping generating resources and to perform maintenance on 

existing resources that increases their flexibility.254 In addition, shortage pricing during 

all reserve deficiencies also sends the correct price signal to already operating resources 

to take any actions necessary to remain operational during the shortage event. For 

instance, a resource that is already operating but realizes it will need to take a forced 

outage in the near-term will receive a clear signal to delay that forced outage, to the 

extent possible, until the reserve shortage has been resolved. 

165. A number of commenters cite the role of appropriate shortage pricing in creating 

an incentive for market participants to make investments that will alleviate shortages in 

the future.255 EDP Renewables and ESA note that the shortage pricing proposal will 

encourage greater investment in new production and storage technologies.256 In response 

to commenters that assert that short duration shortage prices will not create a sufficient 

incentive for new entry, we agree with EPSA that appropriate shortage pricing will 

encourage more modest investments that can improve availability and response-time, 

such as weatherization of fuel supplies, heat tracing to reduce instrument failure during 

freezing temperatures, and completion of deferred maintenance such as burner 

 

254 Potomac Economics Comments at 8.

255 NEI Comments at 14; NGSA Comments at 5; EPSA Comments, Pope Aff. 

at 15; Potomac Economics Comments at 8.

256 EDP Renewables Comments at 5-6; ESA Comments at 4. ESA states that the 

shortage pricing reform will improve the ability for a resource to be compensated based 

on the value of the service the resource provides.
Docket No. RM15-24-000 - 93 -

upgrades.257 Investments of the nature identified by commenters should enhance 

reliability in the long-run as system resources are more able to perform during critical 

system conditions.

166. With regard to transparency, an RTO’s/ISO’s action to establish prices at the times 

of shortage, including transient shortages, makes the shortage apparent to all market

participants. This maximizes the opportunities and incentives for all system resources to 

take actions to address the shortage. 

167. In response to commenters like CAISO, we clarify that we did not intend to 

impose shortage pricing if a shortage occurs during an interval for which the prices and 

dispatch decisions have already been set. We did not intend that, for example, ex post

pricing should, after binding prices have been determined by the RTO/ISO software, 

invoke shortage pricing based upon a subsequent recognition that a shortage existed in a 

particular prior interval. Similarly, the shortage pricing proposal also did not intend to 

require any changes to the frequency of existing dispatch and pricing runs for energy or

operating reserves. To the extent that operating reserves are priced at a different interval 

than energy resources are dispatched, as is the case in CAISO, this Final Rule applies to 

the interval that prices and co-optimizes both energy and operating reserves. Thus, an 

RTO/ISO need not trigger shortage pricing during a fifteen-minute operating reserve 

period if it becomes aware of a shortage within that interval, because reserve prices have 

 

257 EPSA Comments, Pope Aff. at 19.
Docket No. RM15-24-000 - 94 -

already been set for that entire fifteen-minute period. Only if that shortage is projected to 

continue into the next reserve period and there is time to factor that shortage into the 

dispatch and pricing run for the next interval does the RTO/ISO need to trigger shortage 

pricing for that next interval. 

168. Also, the shortage pricing proposal did not intend to require any changes to 

existing pricing methods, such as ELMP in MISO that allows offline resources to set 

energy prices, and we agree that the use of offline resources can result in efficient 

pricing.258 However, we agree with Potomac Economics that if an RTO’s/ISO’s pricing 

model allows infeasible or uneconomic units to set prices, the offline units represent an 

artificial increase in real-time supply that will depress real-time prices. Therefore, for the 

purpose of this Final Rule, RTOs/ISOs choosing to use offline resources to count towards 

energy and operating reserve requirements may not allow infeasible or uneconomic 

offline units to set prices through the real-time pricing model or to be counted as 

providing reserves.

169. In opposing the proposal, PJM and SPP argue that an energy or operating reserve 

shortage that the RTO/ISO expects to be resolved quickly (e.g., within ten minutes), 

 

258 See Midcontinent Indep. Sys. Operator, Inc., 150 FERC ¶ 61,143, at P 36 

(2015) (“For the reasons discussed below, we conditionally accept MISO’s Revised 

ELMP Filing, effective March 1, 2015, subject to a further compliance filing....”); 

Midcontinent Indep. Sys. Operator, Inc., Docket No. ER15-685-001 (Feb. 4, 2016) 

(delegated letter order accepting compliance filing).
Docket No. RM15-24-000 - 95 -

should not trigger shortage pricing. They note that, in PJM, for example, shortage pricing 

is not triggered until a shortage is projected to last at least thirty minutes.259 

170. We disagree that an energy or operating reserve shortage that the RTO/ISO 

expects to be resolved quickly should not trigger shortage pricing. Such a shortage 

presents exactly the type of mismatch between system conditions and pricing that the 

reform was meant to remedy. Thus, by adopting the proposed shortage pricing reform, 

we require PJM and SPP to modify their existing shortage pricing mechanisms. 

171. As summarized above, PJM and SPP provide three hypothetical situations in their 

joint comments to describe situations where they argue shortage pricing should not 

apply.

260 In all of these scenarios, RTOs/ISOs are “technically compromising the 

operating reserve requirement,” as PJM and SPP concede,

261 although such transient 

shortages may not violate NERC’s reliability standards.262 However, we find that 

RTOs/ISOs should reflect these system conditions in the price. Using shortage pricing 

for a transient shortage situation reflects in the price of operating reserves the current 

 

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

at 5. 

260 PJM and SPP Comments at 3-5. 

261 PJM and SPP Comments at 4. 

262 Requirement R6.2 of North American Electric Reliability Corporation’s 

Reliability Standard BAL-002-1 requires restoration of contingency reserves within 

90 minutes: “The default Contingency Reserve Restoration Period is 90 minutes.” In 

the Western Electric Coordinating Council (WECC), the reliability standards require 

restoration of contingency reserves within 60 minutes. WECC BAL-002-WECC-2, R1.
Docket No. RM15-24-000 - 96 -

system conditions, which include the possibility of a contingency occurring —for which 

operating reserves were procured and designed to address. This is designed to 

appropriately value those resources that provide value to the system by their ability to 

respond quickly to changing prices. As Potomac Economics states,263 transient shortages, 

which typically occur when the system is ramp-constrained, are true shortages because, if 

a large contingency occurs during such a shortage (e.g., a generator trips off-line), the 

RTO/ISO will not have the ability to replace the capacity because other generators are 

already ramping as quickly as possible. It is possible, as PJM and SPP state, that when a 

transient shortage is recognized, RTOs/ISOs can re-dispatch their system to eliminate the 

shortage quickly.264 However, until the shortage is resolved, prices should reflect the 

system conditions and the actions taken to resolve the shortage as much as possible. 

172. PJM, SPP, and Direct Energy have also not shown that applying shortage pricing 

to transient shortages will create control issues and increase uplift.265 In fact, there is 

evidence in this record that it will not. The RTOs/ISOs which currently invoke shortage 

pricing during relatively brief periods, i.e., MISO, NYISO and ISO-NE, do not appear to 

have these types of control issues. Further, we note that reflecting system conditions in 

prices should decrease uplift over time, as the costs of units committed, dispatched, or 

 

263 Potomac Economics Comments at 8.

264 PJM and SPP Comments at 4.

265 See PJM and SPP Comments at 3-5 (making this argument in the context of the 

hypotheticals discussed above); Direct Energy Comments at 10-11.
Docket No. RM15-24-000 - 97 -

designated as reserves would be reflected in prices and those units would no longer need 

to be made whole through uplift payments.

173. PJM and SPP state that application of the shortage pricing reform to transient 

shortages would likely require the implementation of operating reserve demand curves 

that distinguish prices relative to varying degrees of shortage.266 In the NOPR, the 

Commission acknowledged that, as a result of the shortage pricing reform, “an RTO/ISO 

may need to calibrate administrative shortage prices to better reflect the value of the 

service.”267 Thus, if PJM or SPP believes that a modification of the applicable operating 

reserve demand curves is appropriate in light of the shortage pricing reform, the 

appropriate forum to make such is a change is through an FPA section 205 filing. 

174. We disagree with TAPS, Concerned Cooperatives, APPA, and NRECA that the 

only effect of requiring RTOs/ISOs to trigger shortage prices in transient events is to 

provide extra revenue to generators already in the market.268 While extra revenue may 

result from prices accurately reflecting shortage conditions, we believe that is 

appropriate. The purpose for requiring the shortage pricing is to create transparent 

market prices that reflect system conditions. The benefit of triggering shortage prices for 

all shortages is that it gives all suppliers an incentive to do as much as they can, including 

 

266 PJM and SPP Comments at 7-8.

267 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 49.

268 TAPS Comments at 9; APPA and NRECA Comments at 7; Concerned 

Cooperatives Comments at 16. 
Docket No. RM15-24-000 - 98 -

investments and operational alterations, to be available the next time it appears that 

shortages may occur and shortage pricing may be invoked, even if such shortages last 

briefly. Further, as discussed above, shortage pricing during all reserve deficiencies also 

sends the correct price signal to already operating resources to take any actions necessary 

to remain operational during the shortage event.

175. We disagree with the views of those commenters269 who assert that the proposed 

rule is not justified because no evidence exists that price signals as volatile and transient 

as shortage prices would be the basis for capital investments. While shortage pricing 

revenues may not, by themselves, be enough to financially justify entirely new generation 

projects, commenters who are generation owners and project developers have indicated 

that triggering shortage prices during short duration shortages as proposed in the NOPR 

“will provide an incentive for incremental investments to enable existing or new 

generation or dispatchable demand to respond to short-duration shortages.”270 As to the 

amount of construction done recently by merchants as opposed to that done under 

long-term contracts, we note that RTOs/ISOs such as PJM have been able to maintain 

 

269 APPA and NRECA Comments at 11-12; TAPS Comments at 7-13; Concerned 

Cooperatives Comments at 15-16.

270 EPSA Comments, Pope Aff. at 15. 
Docket No. RM15-24-000 - 99 -

reliability with reliance primarily upon their capacity market and not long-term contracts 

for new generation.271

176. TAPS recommends that the Commission direct each RTO/ISO to propose new 

shortage prices for transient shortages that do not exceed the value of the incremental 

benefit (if any) provided by an additional megawatt in those circumstances, or to 

demonstrate that the RTO’s/ISO’s existing shortage prices applicable in such 

circumstances already meet that standard.272 We decline to require this in the Final Rule 

both because this was not originally proposed and because the record in this proceeding 

has not persuaded us that any RTO’s/ISO’s administrative shortage prices need to be 

modified. However, as discussed above, any RTO/ISO may file, pursuant to section 205 

of the FPA, to propose a modification of any of the administrative shortage prices as a 

result of this Final Rule, as PJM and SPP indicate they might. 

177. The PJM Market Monitor identifies an implementation issue, which may be 

unique to PJM. The PJM Market Monitor asserts that PJM cannot accurately measure the 

actual level of operating reserves on a five-minute basis. To address this, the PJM

Market Monitor and the New Jersey Board recommend that the Commission direct PJM 

 

271 See generally Monitoring Analytics, New Generation in the PJM Capacity 

Market: MW and Funding Sources for Delivery Years 2007/2008 through 2018/2019

(May 4, 2016), 

http://www.monitoringanalytics.com/reports/Reports/2016/New_Generation_in_the_PJM

_Capacity_Market_20160504.pdf. 

272 TAPS Comments at 13. PJM and SPP indicate that they may need to file to 

modify their shortage prices. See PJM and SPP Comments at 8. 
Docket No. RM15-24-000 - 100 -

to develop this measurement capability before it implements the shortage pricing

proposal.

273

 To the extent that PJM or any other RTO/ISO believes it needs to enhance 

its measurement capabilities to implement the shortage pricing requirement, it should 

propose to do so in its compliance filing.

178. Concerned Cooperatives maintains that the shortage pricing proposal may not 

achieve the price formation objective of increased transparency because generators may 

not be capable of responding fast enough to shortage pricing triggered during transient 

events.274 However, we find that the shortage pricing requirement will increase 

transparency because shortage prices provide a clear and public market signal, while 

compensation to resources provided through uplift provides a signal only to individual 

resources and after-the-fact. In addition, consistently sending a clear price signal during 

reserve deficiencies in real-time should encourage market participant behavior in the 

day-ahead market that translates into day-ahead prices that better reflect expected system 

conditions. 

179. Concerned Cooperatives, ODEC, ELCON, and PG&E suggest that the 

Commission should not adopt the shortage pricing proposal because other initiatives, 

such as PJM’s Reliability Pricing Model modifications and fast ramping products, 

already provide adequate incentives for resource performance and send the signals 

 

273 PJM Market Monitor Comments at 9. 

274 Concerned Cooperatives Comments at 6.
Docket No. RM15-24-000 - 101 -

needed for generation investment.275 We are not persuaded by these arguments. While 

other initiatives, such as PJM’s Reliability Pricing Model modifications and additional 

fast-ramping products, could decrease the occurrence of shortages and shortage pricing, 

an effective shortage pricing trigger is still required to ensure appropriate pricing when

shortages occur. This is particularly important for incenting behavior by load in the dayahead market that is consistent with expected system conditions in real-time. For 

instance, the Reliability Pricing Model modifications will send real-time price signals to 

encourage resource performance, but will not necessarily encourage accurate day-ahead 

load forecast for load. 

180. Concerned Cooperatives express concern that the Commission does not require the 

RTOs/ISOs to include, in their compliance filings, an analysis to ensure that consumers 

remain protected against the exercise of market power when the proposed reforms are 

implemented.276 However, Concerned Cooperatives do not explain why the RTOs’/ISOs’

existing market power mitigation methodologies would not prevent the exercise of 

market power during times of shortage pricing, under the proposed reforms or otherwise. 

Therefore, we do not require the RTOs/ISOs to provide a market power review and 

mitigation reforms in their compliance filings.

 

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

Comments at 2.

276 Concerned Cooperatives Comments at 15.
Docket No. RM15-24-000 - 102 -

C. Compliance and Implementation

1. Commission Proposal

181. In the NOPR, the Commission proposed that RTOs/ISOs submit compliance 

filings on both the proposed settlement reform and the proposed shortage pricing reform 

four months from the effective date of the Final Rule; that the proposed settlement reform 

become effective twelve months from the date of the compliance filings for 

implementation of reforms to settlement systems; and that the shortage pricing proposal

become effective four months from the date of the compliance filings for implementation 

of reforms to shortage pricing triggers.

277

 

2. Comments

182. As described below, some commenters sought more time to submit compliance 

filings and questioned (1) whether the Commission provided enough time to implement 

the settlement proposal; and (2) whether the Commission should extend implementation 

of the shortage pricing proposal to allow for simultaneous implementation of shortage 

pricing proposal with the settlement proposal.

a. Comments from RTOs/ISOs

183. The ISO/RTO Council argues that the Commission should not force the 

RTOs/ISOs to substantially reform their existing market structure to comply with the 

 

277 NOPR, FERC Stats. & Regs. ¶ 32,710 at PP 38, 54-55.
Docket No. RM15-24-000 - 103 -

shortage pricing proposal.278 PJM, MISO, and ISO-NE either support the compliance 

deadline or believe that they can meet the compliance deadline once a Final Rule is 

published in the Federal Register.279 

184. ISO-NE supports the implementation timeline for the shortage pricing proposal 

because it believes that its market already meets the NOPR proposal.

280

 Similarly, 

ISO-NE states that it has already engaged its participants to discuss tariff changes to 

settle the real-time markets in five-minute intervals, and is therefore not concerned with 

the implementation timeline because it anticipates tariff changes will be filed with the 

Commission in mid-2016, to be effective in 2017.281

185. MISO states that it already has a project in progress to replace the current software 

systems that perform market and transmission settlements processing,282 and it estimates 

that an additional eight months would be required to mitigate any issues related to the 

new software and complete development of the revised settlement system, allowing 

implementation by the fourth quarter of 2017.283 MISO states that the Commission 

 

278 ISO/RTO Council Comments at 3.

279 PJM Comments at 7; MISO Comments at 13; ISO-NE Comments at 1.

280 ISO-NE Comments at 3.

281 ISO-NE Comments at 2. “ISO-NE plans to implement five-minute settlement 

of real-time reserves as part of the implementation of five-minute settlement of real-time 

energy transactions, which is currently being discussed with stakeholders.” Id. at 3.

282 MISO Comments at 3.

283 MISO Comments at 6.
Docket No. RM15-24-000 - 104 -

should allow each RTO/ISO to propose, in its compliance filing, what it believes is a 

reasonable implementation schedule.284 

186. PJM asserts that it can make a compliance filing four months after the date of the 

Final Rule, but is concerned that insufficient time was suggested for implementation.285 

PJM hopes to complete an evaluation of what changes are needed in its settlement system 

around April 2016, but, depending upon on the outcome of that analysis, it estimates that 

revising the settlement process will require between fifteen to thirty-eight months.286 

PJM also states that, though it opposes the shortage pricing proposal, if the Commission 

orders some version of shortage pricing reform, the Commission should consider 

simultaneous implementation of shortage pricing with the settlement interval proposal.287

187. CAISO also states that, depending upon the specifics of the Final Rule, extra time 

may be necessary for a complete compliance filing.288

 

284 MISO Comments at 12. 

285 PJM Comments at 7.

286 PJM Comments at 3-4.

287 PJM addresses its objections to the shortage pricing proposals in the PJM and 

SPP Comments.

288 CAISO Comments at 25. CAISO has asked for certain clarifications as part of 

its comments, and states that if the Commission does not make the necessary 

clarifications, CAISO will need extra time to consider what changes would need to be 

made to its systems, and to develop implementing tariff language along with the 

supporting filing. Id.
Docket No. RM15-24-000 - 105 -

b. Comments Urging Flexibility in Implementation 

188. Several commenters urge flexibility in the implementation timelines.289 The 

New Jersey Board concurs with PJM that, given the technical uncertainties involved, the 

Commission, in the Final Rule, should provide flexibility in the implementation 

timeline.

290

 Duke states that the RTOs/ISOs should determine the implementation 

timeline after first exploring system design options, cost impacts to market participants, 

and approaches to reduce cost impacts.291 EEI and APPA and NRECA contend that not 

only is a flexible implementation timeline necessary, but RTOs/ISOs should also be 

encouraged to work with market participants to ensure they have the necessary systems 

and metering in place in advance.292 

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

implementation should account for specific differences between the RTOs/ISOs instead 

of imposing a rigid standard.293 

 

289 ISO/RTO Council Comments at 3; New Jersey Board Comments at 3; PJM 

Comments at 4; EEI Comments at 8; NEPOOL Comments at 1; Golden Spread 

Comments at 7-8.

290 New Jersey Board Comments at 3 (citing PJM Comments at 4).

291 Duke Comments at 6.

292 EEI Comments at 8; APPA and NRECA Comments at 4-5.

293 NEPOOL Comments at 5; Golden Spread Comments at 7-8; TAPS Comments 

at 14-15.
Docket No. RM15-24-000 - 106 -

190. Although TAPS argues against the proposed shortage pricing rule, it states that if 

the rule is adopted, then needed administrative shortage pricing level modifications 

should become effective when other shortage pricing modifications become effective.294 

Golden Spread also identifies issues it believes need to be addressed before the proposed 

shortage pricing requirement can be properly implemented in SPP.295

c. Compliance Filing Deadline

191. Some commenters commented on the amount of time allowed to submit a 

compliance filing. With regard to the settlement interval proposal, Concerned 

Cooperatives state that because it could take over a year to determine what market rules 

may need modification and to subsequently implement those changes, the Commission 

should require a compliance filing after one year so that RTOs/ISOs can discuss 

implementation issues with stakeholders.296 TAPS states that the four-month compliance 

deadline proposed in the NOPR is too short because a rule adjusting shortage pricing 

triggers needs to be accompanied by an adjustment to shortage pricing levels.297 

 

294 TAPS Comments at 13.

295 Golden Spread Comments at 8-10.

296 Concerned Cooperatives Comments at 12.

297 TAPS Comments at 14. 
Docket No. RM15-24-000 - 107 -

d. Implementation Deadline 

192. PSEG states that, in markets where the current equipment can be utilized, the 

twelve-month implementation timeline proposed by the NOPR would be reasonable.298 

However, PSEG notes that the Commission must take into account the time it will take 

the individual RTOs/ISOs to implement computer system changes.299 Several 

commenters assert that the timelines for implementation mentioned in the NOPR may be

too short. 

193. ODEC asserts that, instead of requiring implementation within twelve months of 

the compliance filings, if the Commission determines PJM must settle resources at the 

same interval those resources are dispatched, then the Commission should require each 

RTO/ISO to submit a proposed plan for compliance and implementation of the Final 

Rule.300

194. Exelon maintains that the implementation period for the five-minute settlement 

interval proposal should be 18 months because of the equipment changes that will be 

necessary for generators in the RTOs/ISOs that do not currently use five-minute 

pricing.301

 

298 PSEG Comments at 8. 

299 PSEG Comments at 15; Inertia Power Comments at 9.

300 ODEC Comments at 5.

301 Exelon Comments at 5.
Docket No. RM15-24-000 - 108 -

195. Ameren argues the timeline proposed in the NOPR is too short and could 

potentially increase both costs and risks to the detriment of their customers.302 As for the 

settlement interval proposal, Ameren states that the implementation timeline developed 

from its internal assessment is at least 24 months to 29 months, with a possible 

implementation date of June 1, 2018 if a Final Rule is issued in early 2016.303 

196. Dominion and IPL point out that implementation timing and specifics for market 

participants will depend upon when the RTOs/ISOs finalize their own implementation 

details, and it argues that the proposed twelve-month implementation period for 

settlement interval reforms does not appropriately take this factor into account.304 

197. DTE states that it would need a minimum of eighteen months and “several 

million dollars” to implement necessary changes to its settlement system,

305 and Duke is 

concerned that twelve months will not be enough time.

306

 DTE and Duke emphasize that 

it is essential for the Commission to encourage RTOs/ISOs to work with stakeholders and 

 

302 Ameren Comments at 6.

303 Ameren Comments at 6-7. Ameren also suggests “aligning the implementation 

of a final rule with the beginning of the MISO Planning Year, i.e. June 1, in order to 

facilitate a more seamless transition.” Id.

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

305 DTE Comments at 4-5. DTE explains that these changes would include, 

among other things, evaluating its meters and computer systems, as well as re-evaluating 

many of its current contracts. Id.

306 Duke Comments at 6-7; DTE Comments at 4-5. DTE explains that these 

changes would include, among other things, evaluating its meters and computer systems, 

as well as re-evaluating many of its current contracts. Id.
Docket No. RM15-24-000 - 109 -

market participants in order to facilitate the most cost-effective and timely 

implementation.307 Commenting on the shortage pricing proposal, Concerned 

Cooperatives, who also contend stakeholders need to work cooperatively with 

RTOs/ISOs, assert that the implementation timeline is not long enough, and that the 

Commission should allow at least a year for the RTOs/ISOs to vet the shortage pricing 

implementation details with their stakeholders.308

198. APPA and NRECA request that RTOs/ISOs ensure all market participants either 

have the necessary metering and billing systems in place or have sufficient time to add 

required systems.309

199. Only one entity, Direct Energy, requested an indefinite delay of implementation: 

specifically, for the five-minute settlement proposal, arguing that the underlying 

technology of many supply resources is not advanced enough to ensure the efficiency the 

Commission states it seeks in the NOPR.310 

 

307 DTE Comments at 5; Duke Comments at 6-7.

308 Concerned Cooperatives Comments at 26-27.

309 APPA and NRECA Comments at 4-5.

310 Direct Energy Comments at 6.
Docket No. RM15-24-000 - 110 -

e. Simultaneous Implementation

200. Some commenters argue that the Commission should synchronize implementation 

of the shortage pricing reform with the settlement interval proposal due to their 

interrelated nature.311 

f. Costs

201. In the NOPR, the Commission noted that while adopting the proposed reforms 

might provide significant benefits, implementing and modifying settlement systems can 

be complex and costly.312 Various commenters provided settlement implementation cost 

estimates: PJM ($3 to $5.6 million),313 Ameren ($3 million, plus an additional 

$13 to $20 million if the settlement interval proposal is applied to load),314 Duke 

($1 to $3.25 million, plus an additional $4 million if the settlement interval proposal is 

applied to load),315 and Concerned Cooperatives ($1.5 to $2 million capital costs and 

$300,000 to $600,000 annual costs).316

 

311 PJM Comments at 10; EEI Comments at 10-11; DTE Comments at 6; 

EPSA Comments at 8; PSEG Comments at 15-16; Inertia Power and DC Energy 

Comments at 8-9.

312 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 60.

313 PJM Comments at 3-4. 

314 Ameren Comments at 5-6.

315 Duke Comments at 6. 

316 Concerned Cooperatives Comments at 9. 
Docket No. RM15-24-000 - 111 -

202. While the NOPR did not propose that a cost-benefit analysis must be performed in 

conjunction with the proposed reforms, some commenters discuss whether a formal costbenefit analysis is necessary prior to implementation of the proposals. APPA and

NRECA, Concerned Cooperatives, Ameren, and IPL claim that a cost-benefit analysis is 

necessary before implementation.

317

 IPL asserts this analysis will prove that market 

benefits will be small in comparison to the costs of implementation.318 Conversely, 

EPSA and the PJM Market Monitor state that they should not be required to do a 

cost-benefit analysis (specifically in reference to sub-hourly pricing) because it would be 

too difficult to accurately measure or approximate the potential long-term benefits.319

203. Some commenters opine on how they perceive the costs relate to the benefits of 

the proposed reforms. Duke expresses concerns that the costs of aligning dispatch and 

settlement intervals will exceed the benefits. Duke acknowledges that the potential 

impact of these reforms is not currently knowable, given that MISO and PJM have not 

proposed new market rules and system changes.320 However, Duke states that if 

RTOs/ISOs determine that costs associated with the proposed reform will not exceed the 

benefits, stakeholder discussions could involve software system changes and relevant 

 

317 APPA and NRECA Comments at 4-5; Concerned Cooperatives Comments 

at 12; Ameren Comments at 4; IPL Comments at 2.

318 IPL Comments at 2.

319 EPSA Comments, Pope Aff. at 13-14; PJM Market Monitor Comments at 2-3.

320 Duke Comments at 6.
Docket No. RM15-24-000 - 112 -

costs and impacts on market participants.321 In contrast, Inertia Power states that, 

although the long-term benefits are not quantifiable, the direct savings to consumers and 

market participants will warrant the costs. Inertia Power suggests that the Commission 

should consider the “immeasurable cost of muted price signals” when comparing costs to 

benefits.

322

3. Commission Determination

204. Because the reforms required in this Final Rule are targeted and specific, we 

believe RTOs/ISOs will have sufficient time to develop and file tariff changes to adopt 

these limited reforms, contrary to the concerns of commenters such as Concerned 

Cooperatives and TAPS. In the NOPR, the Commission recognized that implementation 

of the settlement reform could take up to a year after the compliance filings were 

submitted.323 With regard to shortage pricing, any revisions an RTO/ISO may propose to 

shortage pricing levels (which are not required by this Final Rule) must be filed under 

section 205 and could be submitted prior to the actual implementation of the shortage 

pricing provisions of this Final Rule, thereby permitting stakeholders and the RTO/ISO 

additional time to work through the implementation details. 

205. Of the entities required to submit a compliance filing, PJM, MISO, and ISO-NE 

either support the compliance deadline or believe that they can meet the compliance 

 

321 Duke Comments at 5.

322 Inertia Power Comments at 7.

323 NOPR, FERC Stats. & Regs. ¶ 32,710 at P 55.
Docket No. RM15-24-000 - 113 -

deadline once a Final Rule is published in the Federal Register. Further, neither SPP nor 

NYISO submitted comments opposing the compliance deadline. CAISO expressed 

concern about its ability to submit a compliance filing within 120 days of the effective 

date of this Final Rule. We believe that, with the various clarifications provided in this 

Final Rule, CAISO should be able to submit a compliance filing within four months of 

the effective date of the Final Rule. Accordingly, we adopt the proposal in the NOPR 

and require each RTO/ISO to submit, within 120 days of the effective date of this Final 

Rule, a compliance filing that includes tariff changes that adopt the requirements in this 

Final Rule, or demonstrates how the RTO/ISO already complies. We will allow a further 

12 months from the compliance filing date for the tariff changes implementing reforms to 

settlement intervals to be effective, and 120 days from that same compliance filing date 

for the tariff changes implementing shortage pricing reforms to be effective.

324

206. As previously noted, comments on the implementation schedule focused on

two areas: (1) whether the Commission provided enough time to implement the

settlement reform proposal; and (2) whether the Commission should extend 

implementation of the shortage pricing reform proposal to allow for simultaneous 

implementation of shortage pricing with settlement reform. Based upon the comments 

received, we retain the current implementation schedule, but will consider requests for 

 

324 The Commission has followed a similar approach with the timelines for 

compliance and implementation in the past. See, e.g., Order No. 755, FERC Stats. & 

Regs. ¶ 31,324 at P 201, reh’g denied, Order No. 755-A, 138 FERC ¶ 61,123.
Docket No. RM15-24-000 - 114 -

extensions of time to extend the implementation dates when the RTOs/ISOs submit their 

compliance filings. The RTOs/ISOs will have had 120 days as they prepare their 

compliance filings to assess the feasibility of implementing the reforms set forth in this 

Final Rule. It is premature at this time to extend the implementation timelines when 

affected parties are only just starting to analyze what actions they must take in order to 

implement the requirements of the Final Rule. 

207. Moreover, when the RTOs/ISOs submit their respective compliance filings, we 

will consider whether it is appropriate to permit the RTO/ISO to synchronize 

implementation of shortage pricing with the settlement interval based upon the facts 

presented at that time. We expect that any RTO/ISO seeking to synchronize shortage 

pricing with the settlement interval will set forth compelling reasons as to why it is 

necessary based upon the unique nature of the RTO/ISO. 

208. We will not dictate how RTOs/ISOs must implement the reforms set forth in the 

Final Rule from a technical perspective. Nevertheless, we recommend that wherever 

possible, the RTO/ISO should consider using existing metering equipment and current 

data collection processes, such as the process currently being explored by PJM.

325

209. With regard to the comments concerning the costs of implementing the NOPR 

proposals, we find that some of these costs appear to be overstated, taken as a whole. For 

example, PJM’s use of its state estimator and telemetry may reduce, if not eliminate, the 

 

325 PJM Comments at 3.
Docket No. RM15-24-000 - 115 -

need for new five-minute revenue quality meters; and it is unclear, in the case of the 

Concerned Cooperatives, why costs equal to several more full-time employees would 

need to be incurred on an annual basis as a result of the NOPR reform. In any event, we 

find that the value of the benefits of more accurate pricing under the proposed rule 

described in the NOPR, as recognized by the vast majority of commenters in this 

proceeding, and the net present value of the future increases in market surplus, although 

difficult to quantify with precision, are likely to outweigh any one-time implementation 

costs.

210. We reject the proposal to require RTOs/ISOs to conduct a cost-benefit analysis 

before implementing the settlement reform.326 The Commission has not previously 

conducted such analyses when it has considered whether to require various market 

reforms.

327

 Also, since many of the expected benefits will occur in the long-run due to 

changes in marginal investments and enhancements resulting from other price formation 

reforms, there is limited ability to quantify the short-run benefits before adopting these 

reforms.

328

 We agree with the PJM Market Monitor’s assertion that, while the costs of 

 

326 APPA and NRECA Comments at 4.

327 Cf. Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 179 (“For instance, 

although we believe that cost-benefit analyses can be useful in analyzing new projects, 

we are unconvinced that the Commission should mandate cost-benefit analyses in all 

circumstances where an RTO or ISO engages in a major initiative”). 

328 EPSA Comments, Pope Aff. at 13-14.
Docket No. RM15-24-000 - 116 -

implementation may be approximated, calculating the efficiency benefits of 

implementing five-minute settlements is effectively impossible.329

D. Requests Beyond the Scope of this Proceeding

1. Comments

211. Commenters raised issues that are not discussed above and that are outside of the 

scope of this rulemaking. EPSA states that the Commission and RTOs/ISOs must move 

expeditiously on the reforms proposed in the NOPR as well as others identified in the 

price formation proceeding that encourage economically efficient decisions about 

resource entry and exit.

330

212. PJM Power Providers and Exelon urge the Commission to focus on reducing uplift 

and remedying its causes as well as market power mitigation, operator actions, and other 

issues.

331

 PJM Power Providers, Exelon, EPSA, and NGSA also encourage Commission 

action on reforming the energy offer cap.332

213. ELCON, Westar, TAPS, and Inertia Power and DC Energy recognize the 

interconnected nature of the issues in the price formation proceeding. ELCON urges the 

Commission to consolidate any additional price formation proposals into a single 

 

329 PJM Market Monitor Comments at 2-3.

330 EPSA Comments at 11.

331 PJM Power Providers Comments at 7; Exelon Comments at 8.

332 PJM Power Providers Comments at 6; EPSA Comments at 13-15; 

Exelon Comments at 8-9; NGSA Comments at 6 (citing NGSA Comments, Docket 

No. ER15-623-000 (filed Jan. 20, 2015)).
Docket No. RM15-24-000 - 117 -

NOPR.333 Westar states that the Commission should consider the NOPR in conjunction 

with other items identified in the price formation proceedings.

334

 TAPS states that 

RTOs/ISOs should have the flexibility to comply with all price formation rulemakings in 

a way that coordinates implementation and reduces the possibility of overlapping 

modifications of software and hardware.335 Inertia Power and DC Energy asks the 

Commission to be mindful of other system benefits that may result from the required 

software and hardware upgrades in the RTO/ISOs.336

214. EEI and EPSA reiterate their prior comments regarding common principles that 

should guide the discussion of price formation: (1) dispatch-based pricing; (2) efficient 

commitment that will provide accurate day-ahead and real-time price signals; and 

(3) transparency with regard to out-of-market actions and payments.337 EEI further states 

that the Commission should consider issues related to improving the transparency of 

LMPs by addressing the treatment of start-up and no-load costs, and operator actions that 

result in out-of-market payments.338

 

333 ELCON Comments at 7.

334 Westar Comments at 2-3.

335 TAPS Comments at 6.

336 Inertia Power and DC Energy Comments at 8.

337 EEI Comments at 4-5 (citing EEI Comments, Docket No. AD14-14-000, at 2 

(filed Mar. 6, 2015)); EPSA Comments at 12 and Att. B.

338 EEI Comments at 6.
Docket No. RM15-24-000 - 118 -

215. Westar requests that the Commission encourage RTOs/ISOs to clarify what costs 

may constitute marginal costs.339 Additionally, XO Energy lists many benefits of a 

day-ahead transmission product, and recommends the implementation of such a product 

across all RTOs/ISOs.340 

216. Financial Marketers Coalition and XO Energy assert that while the NOPR 

addresses settlement intervals for generation (supply), similar reforms are needed for the 

intervals in which load is forecasted, bid and settled in order to eliminate the mismatch 

between generation and load.

341

 

217. Entergy Nuclear Power Marketing and NEI state that although the reforms 

proposed in the NOPR will improve price formation for resources operating in real-time, 

they will not improve the outlook for baseload resources such as nuclear plants typically 

fully committed in the day-ahead market.342

218. NEI recommends various changes to price formation to better ensure that the 

market clearing price reflects all of the costs associated with reliably providing service to 

the market.

343

 

339 Westar Comments at 3. 

340 XO Energy Comments at 2-3 (citing MISO, Virtual Spread Bid Proposal 

Stakeholder Workshop, at 10 (Nov. 18, 2013)).

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

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

343 NEI Comments at 15-16.
Docket No. RM15-24-000 - 119 -

219. With respect to other issues, DTE requests clarification from the Commission that 

market participants will not have to change the manner in which they currently net 

purchases and sales for purposes of FERC Form No. 1.344 The SPP Market Monitor 

raises look-ahead modeling concerns.

345

 Powerex has concerns regarding steps CAISO 

takes to minimize the occurrence of shortages (as opposed to when shortage pricing 

occurs)346and Public Interest Organizations have a concern regarding possible barriers to 

the participation of demand response in RTO/ISO markets.

347

220. Referencing the NOPR’s discussion of the role that look-ahead tools can play in 

mitigating seemingly artificial shortages, the SPP Market Monitor also requests the 

Commission clarify that look-ahead models incorporate administrative pricing in their 

least cost evaluation before choosing unit commitments to relieve shortages.348

221. Powerex argues that further Commission action is necessary to ensure that 

RTOs/ISOs refrain from using more general tariff provisions and non-tariff protocols, 

including out-of-market procurement and other operator interventions, to prevent 

 

344 DTE Comments at 6.

345 PSEG Comments at 14; SPP Market Monitor at 4-7; Westar Comments at 3.

346 Powerex Comments at 9-13.

347 Public Interest Organizations Comments at 4-5.

348 SPP Market Monitor Comments at 7.
Docket No. RM15-24-000 - 120 -

shortage pricing from being triggered or otherwise prevent scarcity from being reflected 

in market prices.349 

222. Dominion questions if the proposed settlement reforms require further 

consideration of the interactions between the day-ahead and real-time markets. 

Specifically, Dominion suggests that changes may be necessary to how the RTOs/ISOs 

calculate generator deviations in the real-time market from their day-ahead schedules.350 

223. ESA requests that the Commission consider five-minute scheduling once it 

implements five-minute intervals to better access the greater operational flexibility of 

fast-ramping resources like energy storage.351

224. Powerex requests that the Commission require each RTO/ISO to: (1) identify all 

out-of-market actions or procurement tools that it uses, or is authorized to use, to manage 

its system; and (2) propose tariff amendments to ensure that these actions are 

appropriately reflected in prices or, alternatively, demonstrate that its existing tariff 

provisions already achieve such a result.352 

225. Appian Way states that the instant proposals encompassed by this NOPR are 

insufficient to ensure proper shortage pricing. Appian Way adds that some RTOs/ISOs 

will continue to have defective pricing unless and until the Commission requires them to 

 

349 Powerex Comments at 9.

350 Dominion Comments at 3-4. 

351 ESA Comments at 4-5. 

352 Powerex Comments at 12-13.
Docket No. RM15-24-000 - 121 -

establish pricing rules that ensure prices rise to scarcity levels when shortage conditions 

occur that require the RTO/ISO to call demand response in order to serve load.353

226. Inertia Power and DC Energy state that when operating reserves and other 

ancillary services are priced “out of market,” it prevents the triggering of shortage pricing 

and circumvents the intent of the NOPR.354

227. Potomac Economics states that the Commission’s focus on shortage pricing should 

extend to transmission shortages.355 

228. Public Interest Organizations state that if the Commission carries out the shortage 

pricing proposal as set forth in the NOPR, it should simultaneously ensure that demandside resources can respond to those prices to reduce the potential for unjust and 

unreasonable rates.356 

229. Mr. Lively maintains that shortages should be viewed as a continuum, not as a 

shortage versus non-shortage issue. Mr. Lively cites a paper he wrote that discusses 

using Area Control Error (ACE) in a pricing mechanism to adjust the nominal price of 

electricity to determine a settlement price.357

 

353 Appian Way Comments at 2.

354 Inertia Power Comments at 5-6.

355 Potomac Economics Comments at 11.

356 Public Interest Organizations Comments at 3-5.

357 Mr. Lively Comments at 3-4 (filed Nov. 23, 2015). 
Docket No. RM15-24-000 - 122 -

2. Commission Determination

230. We appreciate the concerns raised by numerous commenters requesting that the 

Commission undertake various initiatives, as set forth above. However, we find that the 

requested initiatives go beyond the scope of this rulemaking. Many of the issues raised 

by commenters may be relevant in other price formation proceedings,358 but they go 

beyond the limited issues in this proceeding, which deals only with the settlement interval 

proposal and the trigger for shortage pricing. Accordingly, we will not address those 

issues here. 

IV. Information Collection Statement

231. The Paperwork Reduction Act (PRA)359 requires each federal agency to seek and 

obtain Office of Management and Budget (OMB) approval before undertaking a 

collection of information directed to ten or more persons or contained in a rule of general 

applicability. OMB’s regulations,360 in turn, require approval of certain information 

collection requirements imposed by agency rules. Upon approval of a collection(s) of 

information, OMB will assign an OMB control number and an expiration date. 

 

358 See, e.g., Offer Caps in Markets Operated by Regional Transmission 

Organizations and Independent System Operators, Notice of Proposed Rulemaking, 

81 Fed. Reg. 5591 (Feb. 4, 2016), FERC Stats. & Regs. ¶ 32,714 (2016), 

Price Formation in Energy and Ancillary Services Markets Operated by Regional 

Transmission Organizations and Independent System Operators, 153 FERC ¶ 61,221 

(2015). 

359 44 U.S.C. §§ 3501-3520 (2012).

360 5 C.F.R. § 1320 (2015).
Docket No. RM15-24-000 - 123 -

Respondents subject to the filing requirements of a rule will not be penalized for failing 

to respond to these collection(s) of information unless the collection(s) of information 

display a valid OMB control number. 

232. In this Final Rule, we are amending the Commission’s regulations to improve the 

operation of organized wholesale electric power markets operated by RTOs and ISOs. 

We require that each RTO/ISO align settlement and dispatch intervals by: (1) settling 

energy transactions in its real-time markets at the same time interval it dispatches energy; 

(2) settling operating reserves transactions in its real-time markets at the same time 

interval it prices operating reserves; and (3) settling intertie transactions in the same time 

interval it schedules intertie transactions. We also require that each RTO/ISO trigger 

shortage pricing for any interval that prices both energy and operating reserves in which a 

shortage of energy or operating reserves is indicated during the pricing of resources for 

that interval. The reforms required in this Final Rule require a one-time tariff filing due

120 days after the effective date of this Final Rule. With regard to those RTOs/ISOs that 

believe that they already comply with the reforms required here, they can demonstrate 

their compliance in their compliance filing. The Commission will submit the proposed 

reporting requirements to OMB for its review and approval under section 3507(d) of the 

Paperwork Reduction Act.361 

 

361 44 U.S.C. § 3507(d).
Docket No. RM15-24-000 - 124 -

233. Although the Commission stated in the NOPR that it expects the adoption of the 

reforms proposed to provide significant benefits,362 the Commission solicited comments 

on the accuracy of provided burden and cost estimates set forth in the NOPR and any 

suggested methods for minimizing the respondents’ burdens, including the use of 

automated information techniques. Specifically, the Commission sought detailed 

comments on the potential cost and time necessary to implement aspects of the reforms 

proposed in the NOPR, including (1) hardware, software, and business processes 

changes; (2) increased data storage and validation; (3) changes to market participant 

metering or other equipment; and (4) processes for RTOs/ISOs to vet proposed changes 

amongst their stakeholders. The Commission also sought comment on whether changes 

in settlement systems would disrupt existing contractual relationships and, if so, what 

burdens this might impose and how the Commission should address any potential issues 

resulting from such disruption. 

234. The Commission received responses regarding the costs of implementing the 

reforms described in the NOPR;

363 however we find that those costs do not fall under the 

definition of “burden” as defined by OMB’s regulations.364 Therefore, an analysis of 

those costs is not relevant to our analysis under the PRA.

 

363 See supra PP 201-203.

364 “Burden” is defined as “the total time, effort, or financial resources expended 

by persons to generate, maintain, retain, or disclose or provide information to or for a 

Federal Agency, including... (ii) Developing, acquiring, installing, and utilizing 

(continued...)
Docket No. RM15-24-000 - 125 -

Burden Estimate and Information Collection Costs: We believe that the burden estimates 

below are representative of the average burden on respondents. The estimated burden 

and cost365 for the requirements contained in this Final Rule follow.366

 

technology and systems for the purpose of collecting, validating, and verifying 

information; (iii) Developing, acquiring, installing, and utilizing technology and systems 

for the purpose of processing and maintaining information; (iv) Developing, acquiring, 

installing, and utilizing technology and systems for the purpose of disclosing and 

providing information....” 5 C.F.R. § 1320.3(b)(1) (2015). We respond to comments 

regarding other costs not related to “burden” (such as hardware and software) in PP 209-

210 above.

365 The estimated hourly cost (salary plus benefits) provided in this section are 

based on the salary figures for May 2015 posted by the Bureau of Labor Statistics for the 

Utilities sector (available at http://www.bls.gov/oes/current/naics2_22.htm#00-0000) and 

scaled to reflect benefits using the relative importance of employer costs in employee 

compensation from December 2015 (released March 10, 2016 and available at 

http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates for salary plus 

benefits are:

 Legal (code 23-0000), $128.94 

 Computer and Mathematical (code 15-0000), $60.54 

 Information Security Analyst (code 15-1122), $57.99

 Accountant and Auditor (code 13-2011), $53.78

 Information and Record Clerk (code 43-4199), $37.69

 Electrical Engineer (code 17-2071), $64.20 

 Economist (code 19-3011), $74.43

 Computer and Information Systems Manager (code 11-3021), $91.63

 Management (code 11-0000), $88.94

The average hourly cost (salary plus benefits), weighting all of these skill sets 

evenly, is $73.13. For the calculations here, the Commission rounds it to $73 per hour.

366 The RTOs/ISOs (CAISO, ISO-NE, MISO, NYISO, PJM, and SPP) are required 

to comply with the reforms in this Final Rule. Three RTOs/ISOs (ISO-NE, MISO, and 

PJM) currently do not align real-time settlement with dispatch intervals and thus likely 

would be burdened more by that aspect of the reforms in this Final Rule. 
Docket No. RM15-24-000 - 126 -

FERC 516D,367 as 

implemented in 

Final Rule in RM15-

24-000

Number of 

Respondents

Annual 

Number of 

Responses 

per 

Respondent

Total 

Number of 

Responses

Average 

Burden 

Hours & 

Cost per 

Response

Annual 

Burden 

Hours & 

Total 

Annual 

Cost

(1) (2) (1)×(2)=(3) (4) (3)×(4)=(5)

Tariff filings onetime in Year 1, for 

RTOs/ISOs that 

currently align realtime settlement with 

dispatch intervals

3 RTOs or 

ISOs 1 3

80 hrs; 

$5,840

240 hrs;

$17,520

Tariff filings onetime in Year 1, for 

RTOs/ISOs that do 

not currently align 

real-time settlement 

with dispatch 

intervals

3 RTOs or 

ISOs 1 3

160 hrs; 

$11,680

480 hrs;

$35,040

TOTAL (one-time in 

Year 1)368

6 6

720 hrs.; 

$52,560

 

367 The information collection requirements and related burden for the NOPR in 

Docket No. RM15-24 were submitted to OMB under FERC-516 (Electric Rate Schedules 

and Tariff Filings, OMB Control No. 1902-0096). Currently, there is an unrelated 

package (in Docket No. PL15-3) pending OMB review under FERC-516. Because only 

one item per OMB Control No. can be pending OMB review at a time, the reporting 

requirements in the Final Rule in RM15-24 are being submitted to OMB for review under 

FERC-516D (a temporary ‘placeholder’ collection number, OMB Control No. to be 

determined). Long-term, the staff expects to transfer administratively the requirements 

and burden of this final rule to FERC-516 (OMB Control No. 1902-0096) from 

FERC-516D. 

368 The burden costs (one-time in Year 1) consist of filing proposed tariff changes 

to the Commission within four months of the effective date of the Final Rule. 
Docket No. RM15-24-000 - 127 -

Title: FERC-516D, Electric Rate Schedules and Tariff Filings in Docket RM15-24.

Action: A new information collection.

OMB Control No. To Be Determined.

Respondents for this Rulemaking: RTOs and ISOs.

Frequency of Information: One-time during Year one.

Necessity of Information: The Federal Energy Regulatory Commission implements this 

rule to improve competitive wholesale electric markets in the RTO and ISO regions. 

Internal Review: The Commission has reviewed the changes and has determined that 

such changes are necessary. These requirements conform to the Commission’s need for 

efficient information collection, communication, and management within the energy 

industry. The Commission has specific, objective support for the burden estimates 

associated with the information collection requirements.

235. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 

Comments concerning the collection of information and the associated burden estimate(s) 

may also be sent to the Office of Information and Regulatory Affairs, 

Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503 

[Attention: Desk Officer for the Federal Energy Regulatory Commission]. Due to 
Docket No. RM15-24-000 - 128 -

security concerns, comments should be sent electronically to the following e-mail 

address: oira_submission@omb.eop.gov. Comments submitted to OMB should refer to 

FERC-516D and OMB Control No. To Be Determined.

V. Environmental Analysis

236. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.369 We conclude that neither an Environmental Assessment 

nor an Environmental Impact Statement is required for this Final Rule under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale of electric 

energy subject to the Commission’s jurisdiction, plus the classification, practices, 

contracts and regulations that affect rates, charges, classifications, and services.370

VI. Regulatory Flexibility Act

237. The Regulatory Flexibility Act of 1980 (RFA)371 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

 

369 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, 52 Fed. Reg. 47,897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations 

Preambles 1986-1990 ¶ 30,783 (1987).

370 18 C.F.R. § 380.4(a)(15) (2015). 

371 5 U.S.C. §§ 601-612 (2012).
Docket No. RM15-24-000 - 129 -

of small entities. The RFA does not mandate any particular outcome in a rulemaking. It 

only requires consideration of alternatives that are less burdensome to small entities and 

an agency explanation of why alternatives were rejected.

238. This rule applies to six RTOs/ISOs (all of which are transmission organizations). 

The three RTOs/ISOs that do not currently align real-time settlement with dispatch 

intervals will have to incur a one-time cost to upgrade their hardware and software. 

These enhancements will be needed to allow the RTOs/ISOs to process settlement 

data on a more granular level. That one-time cost (spread over Years 1 and 2) for 

hardware and software for each of those three RTOs/ISOs is estimated to be an average 

of $3 million (a total of $9 million for those three RTOs/ISOs). The average estimated 

burden cost (one-time in Year 1) to each of the RTOs/ISOs is $8,760 (total of $52,560 for 

all six RTOs/ISOs). Therefore the estimated total cost (burden, hardware, and software) 

over Years 1 and 2 for all six RTOs/ISOs is $9,052,560. 

239. The RTOs/ISOs, however, are not small entities, as defined by the RFA.372 This is 

because the relevant threshold between small and large entities is 500 employees and the 

Commission understands that each RTO/ISO has more than 500 employees. 

 

372 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. The 

Small Business Administration’s regulations at 13 C.F.R. § 121.201 (2015) define the 

threshold for a small Electric Bulk Power Transmission and Control entity (NAICS code 

221121) to be 500 employees. See 5 U.S.C. § 601(3) (2012) (citing to section 3 of the 

Small Business Act, 15 U.S.C. § 632 (2012)).
Docket No. RM15-24-000 - 130 -

Furthermore, because of their pivotal roles in wholesale electric power markets in their 

regions, none of the RTOs/ISOs meet the last criterion of the two-part RFA definition of 

a small entity: “not dominant in its field of operation.” As a result, we certify that the 

reforms required by this Final Rule would not have a significant economic impact on a 

substantial number of small entities.

VII. Document Availability

240. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

241. From FERC’s Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field.

242. User assistance is available for eLibrary and the FERC’s website 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. E-mail the Public Reference Room at

public.referenceroom@ferc.gov.
Docket No. RM15-24-000 - 131 -

VIII. Effective Date and Congressional Notification

243. These regulations are effective 75 days from the date the rule is published in the 

Federal Register. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule 

is not a “major rule” as defined in section 351 of the Small Business Regulatory 

Enforcement Fairness Act of 1996.

List of subjects in 18 C.F.R. Part 35 

Electric power rates; Electric utilities; Reporting and record-keeping requirements

By the Commission.

( S E A L )

Kimberly D. Bose,

Secretary.
Docket No. RM15-24-000 - 132 -

In consideration of the foregoing, the Commission proposes to amend Part 35, 

Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352.

2. Amend § 35.28 as follows:

(a) Paragraph (g)(1)(iv)(A) is revised.

(b) Add a new paragraph (g)(1)(vi).

§ 35.28 Non-discriminatory open access transmission tariff

* * * * *

(g) Tariffs and operations of Commission-approved independent system 

operators and regional transmission organizations. * * *

(1) Demand response and pricing.* * * *

(iv) Price Formation during periods of operating reserve 

shortage. (A) Each Commission-approved independent system operator and regional 

transmission organization must modify its market rules to allow the market-clearing price 

during periods of operating reserve shortage to reach a level that rebalances supply and 

demand so as to maintain reliability while providing sufficient provisions for mitigating 

market power. Each Commission-approved independent system operator and regional 

transmission organization must trigger shortage pricing for any interval in which a 

shortage of energy or operating reserves is indicated during the pricing of resources for 

that interval. * * * *

(vi) Settlement intervals. Each Commission-approved independent 

system operator and regional transmission organization must settle energy transactions in 

its real-time markets at the same time interval it dispatches energy, must settle operating 

reserves transactions in its real-time markets at the same time interval it prices operating 

reserves, and must settle intertie transactions at the same time interval it schedules intertie 

transactions.
Docket No. RM15-24-000 - 133 -

Note: The following appendix will not be published in the Federal Register.

APPENDIX: List of Commenters

The following is a list of the entities that filed comments in this proceeding, along with 

the short name/acronym used in this Final Rule. Unless otherwise noted, all comments 

were submitted on November 30, 2015.

Comments

Short Name/Acronym Commenter

AEMA Advanced Energy Management 

Alliance

Ameren Ameren Services Company (on behalf 

of Ameren Illinois Company and 

Union Electric Company)

ANGA America’s Natural Gas Alliance

APPA and NRECA American Public Power Association 

and National Rural Electric 

Cooperative Association

Appian Way Appian Way Energy Partners

CAISO California Independent System 

Operator Corporation

CEA Canadian Electricity Association

Concerned Cooperatives Hoosier Energy Rural Electric 

Cooperative, Inc., Kansas Electric 

Power Cooperative, Inc., and North 

Carolina Electric Membership 

Corporation

Delaware Commission Delaware Public Service Commission

Direct Energy Direct Energy Business, LLC and 

Direct Energy Business Marketing, 

LLC
Docket No. RM15-24-000 - 134 -

Dominion Dominion Resources Services, Inc.

DTE DTE Electric Company

Duke Duke Energy Corporation, Duke 

Energy Progress, LLC, Duke Energy 

Carolinas, LLC, Duke Energy 

Kentucky, Inc., Duke Energy Indiana, 

Inc., and Duke Energy Ohio, Inc.

EDP Renewables EDP Renewables North America LLC

EEI Edison Electric Institute

ELCON Electricity Consumers Resource 

Council

ESA Energy Storage Association

EPSA Electric Power Supply Association

Entergy Nuclear Power Marketing Entergy Nuclear Power Marketing, 

LLC

Exelon Exelon Corporation

Financial Marketers Coalition Financial Marketers Coalition

Golden Spread Golden Spread Electric Cooperative, 

Inc.

Inertia Power and DC Energy Inertia Power, LP and DC Energy, 

LLC

IPL Indianapolis Power & Light Company

ISO/RTO Council ISO/RTO Council

ISO-NE ISO New England Inc.

Mr. Lively Mark B. Lively, Utility Economic 

Engineers

MISO Midcontinent Independent System 

Operator, Inc.
Docket No. RM15-24-000 - 135 -

NEPOOL New England Power Pool Participants 

Committee

NEI Nuclear Energy Institute

New Jersey Board New Jersey Board of Public Utilities

NGSA Natural Gas Supply Association

NYISO New York Independent System 

Operator, Inc.

ODEC Old Dominion Electric Cooperative

Mr. Centolella Paul Centolella and Associates, 

L.L.C.

PG&E Pacific Gas & Electric Company

PJM PJM Interconnection, L.L.C.

PJM Market Monitor Monitoring Analytics, LLC, 

Independent Market Monitor for PJM

PJM Power Providers PJM Power Providers Group

Potomac Economics Potomac Economics, Ltd.

Powerex Powerex Corp.

PSEG PSEG Companies (Public Service 

Electric and Gas Company, PSEG 

Power LLC, and PSEG Energy 

Resources & Trade LLC)

Public Interest Organizations Acadia Center, Americans for a Clean 

Energy Grid, Climate + Energy 

Project, Great Plains Institute, Natural 

Resources Defense Council, Sierra 

Club, Sustainable FERC Project, 

Union of Concerned Scientists, and 

Wind on the Wires

SCE Southern California Edison Company
Docket No. RM15-24-000 - 136 -

SPP Southwest Power Pool, Inc.

SPP Market Monitor Southwest Power Pool, Inc. 

Independent Market Monitoring Unit

TAPS Transmission Access Policy Study 

Group

Westar Westar Energy, Inc.

XO Energy XO Energy, LLC

Reply or Supplemental Comments

Short 

Name/Acronym Commenter Date Submitted

Golden Spread Golden Spread Electric 

Cooperative, Inc.

December 14, 2015

Direct Energy Direct Energy Business, 

LLC and Direct Energy 

Business Marketing, LLC

March 4, 2016

Late Comments

Short 

Name/Acronym

Commenter Date Submitted

New Jersey Board New Jersey Board of Public 

Utilities 

December 3, 2015