Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators

Federal RegisterJun 30, 2016

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is revising its regulations to address certain practices that fail to compensate resources at prices that reflect the value of the service resources provide to the system, thereby distorting price signals, and in certain instances, creating a disincentive for resources to respond to dispatch signals. We require that each regional transmission organization and independent system operator align settlement and dispatch intervals by: Settling energy transactions in its real-time markets at the same time interval it dispatches energy; settling operating reserves transactions in its real-time markets at the same time interval it prices operating reserves; and settling intertie transactions in the same time interval it schedules intertie transactions. We also require that each regional transmission organization and independent system operator trigger shortage pricing for any interval in which a shortage of energy or operating reserves is indicated during the pricing of resources for that interval. Adopting these reforms will align prices with resource dispatch instructions and operating needs, providing appropriate incentives for resource performance.

DATES:

This rule will become effective September 13, 2016.

FOR FURTHER INFORMATION CONTACT:

Stanley Wolf (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6841,

Stanley.Wolf@ferc.gov

Pamela Quinlan (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6179,

Pamela.Quinlan@ferc.gov

Alicia Cobb (Legal Information), Office of the General Counsel—Energy Markets, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8501,

Alicia.Cobb@ferc.gov

SUPPLEMENTARY INFORMATION:

Order No. 825

Final Rule

Table of Contents

Paragraph No.

I. Introduction

II. Background

III. Discussion

A. Settlement Interval Reform

1. Need for Reform

2. Settlement Interval Reform for Energy Transactions and Operating Reserves

a. Proposal

i. Energy Transactions

ii. Operating Reserves

b. Current Practices in the RTOs/ISOs

i. Energy Transactions

ii. Operating Reserves

c. Comments on the Proposed Settlement Interval Reform

i. Comments From the RTOs/ISOs

ii. Comments by Market Monitors

iii. Comments Supporting the Proposed Settlement Interval Reform

iv. Comments Opposed to the Proposed Settlement Interval Reform

d. Commission Determination

i. Energy Transactions

ii. Operating Reserves

3. Interties

a. Commission Request for Comments

i. Comments by RTOs/ISOs

ii. Comments by Market Monitors

iii. Comments in Support of Applying Settlement Reform to Interties

iv. Comments Opposed To Applying Settlement Reform to Interties

b. Commission Determination

4. Demand Response Resources

a. Comments

b. Commission Determination

5. Load

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

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),

that each regional transmission organization (RTO) and independent system operator (ISO) align settlement and dispatch

intervals by: (1) Settling energy transactions in its real-time markets at the same time interval it dispatches energy;

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

As mentioned in the Notice of Proposed Rulemaking, the Commission sometimes uses the term “dispatch” as shorthand when describing how RTOs/ISOs acquire and price energy and operating reserves. With respect to operating reserves, the Commission uses dispatch to describe the intervals at which they are acquired and priced.

See Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators,

80 FR 58,393 (Sept. 29, 2015), FERC Stats. & Regs. ¶ 32,710, at P 1 (2015) (NOPR).

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

and (3) settling intertie transactions

in the same time interval it schedules intertie transactions (settlement interval requirements). We also require, pursuant to section 206 of the FPA, that each RTO/ISO establish a mechanism to trigger shortage pricing for any interval in which a shortage of energy or operating reserves is indicated during the pricing of resources for that interval (shortage pricing requirement).

Operating reserves refer to certain ancillary services procured in the wholesale market, although they are often defined differently in each RTO/ISO. Operating reserves typically include: (a) Regulating Reserve, used to account for very short-term deviations between supply and demand (

e.g.,

4 to 6 seconds); (b) Spinning, or Synchronous Reserve, which is capacity held in reserve and synchronized to the grid and able to respond within a relatively short amount of time (

e.g.,

within 10 minutes), to be used in case of a contingency, such as the loss of a generator; and (c) Non-Spinning Reserve, capacity that is not synchronized to the grid and which can take longer to respond (

e.g.,

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

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

Docket No. AD14-14-000, at 3 n.7 (Oct. 2014),

http://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricing-rto-iso-markets.pdf

(Shortage Pricing Paper).

Intertie transactions are transactions across RTO/ISO borders, including imports, exports and wheel-through transactions.

2. Some current RTO/ISO settlement practices fail to reflect the value of providing a given service, thereby distorting price signals and failing to provide appropriate signals for resources to respond to the actual operating needs of the market. One such practice occurs when RTOs/ISOs dispatch resources every five minutes but perform settlements based on an hourly integrated price, or when RTOs/ISOs schedule intertie transactions every fifteen minutes, but perform settlements on an hourly integrated price. This misalignment between dispatch and settlement intervals distorts the price signals sent to resources and fails to reflect the actual value of resources responding to operating needs because compensation will be based on average output and average prices across an hour, rather than output and prices during the periods of greatest need within a particular hour.

3. We also find that a second problem occurs if there is a mismatch between the time when a system experiences a shortage of energy and operating reserves and the time when prices reflect the shortage condition. This can be particularly problematic when, for example, an RTO's/ISO's market rules require a shortage to last a minimum time period before triggering shortage pricing. In this instance, short-term prices fail to reflect system conditions and potential reliability costs, as well as the value of both internal and external market resources responding to a dispatch signal. In addition, inaccurate price signals are provided to market participants if shortage pricing is still in effect after the shortage has been resolved.

4. To address these problems associated with differing dispatch intervals and settlement intervals, as well as with shortage pricing triggers, we are setting forth the settlement interval requirements and the shortage pricing requirement in this Final Rule.

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.

We are not at this time proposing to change the price paid by any RTO/ISO when shortage pricing is triggered.

5. As set forth in the NOPR, we reiterate the goals of price formation are to: (1) Maximize market surplus for consumer and suppliers; (2) provide correct incentives for market participants to follow commitment and dispatch instructions, make efficient investments in facilities and equipment, and maintain reliability; (3) provide transparency so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system; and, (4) ensure that all suppliers have an opportunity to recover their costs.

See

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

6. As noted in the NOPR, the reforms adopted in this Final Rule advance at least two of the Commission's goals

with respect to price formation. First, the proposed reforms will help provide correct incentives for market participants to follow commitment and dispatch instructions,

to make efficient investments in facilities and equipment, and to maintain reliability. Specifically, requiring RTOs/ISOs to align the settlement and dispatch intervals will more accurately reward resources that are providing energy and ancillary services in periods of the greatest need and will discourage provision of energy and ancillary services immediately following periods of system stress. Doing so will enhance the incentive to follow an RTO's/ISO's dispatch signal and thus help maintain system reliability. This reform will also reward resources that can flexibly respond to system needs, thus creating an incentive for resources to make efficient investments in facilities and equipment. Similarly, implementing shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs will provide an incentive for resources to ensure that they are available to respond to high prices, which should help alleviate shortages and avoid shortage pricing during subsequent dispatch intervals. This reform would also ensure that resources operating during a shortage are compensated for the value of the service that they provide, regardless of whether the shortage is short-lived.

The Commission notes that the reforms proposed herein would further augment existing mechanisms in each RTO/ISO market that provide incentives to follow dispatch instructions, such as penalties for excessive or deficient energy and the allocation of commitment and dispatch costs to deviations from energy dispatch targets.

See, e.g.,

MISO, FERC Electric Tariff, 40.3.3(a) (36.0.0) (allocating Revenue Sufficiency Guarantee costs to, inter alia, resources providing excessive or deficient energy), 40.3.4 (33.0.0) (charges for excessive or deficient energy deployment).

7. Second, the proposed reforms will also help provide transparency and certainty so that market participants understand how compensation and prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system. Requiring settlement intervals to match dispatch intervals will make resource compensation more transparent by, among other things, increasing the proportion of resource payment provided through payments of energy and operating reserves rather than uplift. Further, requiring RTOs/ISOs to trigger shortage pricing for an interval in which a shortage of energy or operating reserves is indicated during the pricing of resources for that interval will ensure that prices transparently reflect the operational constraints of reliably operating the system. This increased transparency, in turn, better informs decisions to build or maintain resources and enhances consumers' ability to hedge. The benefits summarized above and discussed in detail below would ultimately help to ensure just and reasonable rates.

8. As discussed below, we require each RTO/ISO to submit a compliance filing with the tariff changes needed to implement this Final Rule within 120 days of the Final Rule's effective date. We will allow a further 12 months from the compliance filing date for the tariff changes implementing reforms to settlement intervals to be effective, and 120 days from that same compliance filing date for the tariff changes implementing shortage pricing reforms to be effective.

The Commission has followed a similar approach with the timelines for compliance and implementation in the past.

See, e.g., Frequency Regulation Compensation in the Organized Wholesale Power Markets,

Order No. 755, FERC Stats. & Regs. ¶ 31,324, at P 201 (2011),

reh'g denied,

Order No. 755-A, 138 FERC ¶ 61,123 (2012).

II. Background

9. The Commission has addressed price formation in organized markets on prior occasions. For example, in Order No. 719, the Commission addressed shortage pricing

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.”

The Commission required such rules out of concern that inappropriate price signals during an operating reserve shortage would provide an insufficient incentive for market participants to take appropriate actions.

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).

Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194.

10. In June 2014, the Commission initiated a proceeding, in Docket No. AD14-14-000, to evaluate issues regarding price formation in the energy and ancillary services markets operated by RTOs/ISOs (price formation proceeding). In the notice initiating that proceeding, the Commission stated that there may be opportunities for the RTOs/ISOs to improve the energy and ancillary services price formation process. As set forth in the notice, locational marginal prices (LMP) and market-clearing prices used in energy and ancillary services markets ideally “would reflect the true marginal cost of production, taking into account all physical system constraints, and these prices would fully compensate all resources for the variable cost of providing service.”

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.

The Commission also released staff reports on these topics. In one of those reports, issued in October 2014, staff analyzed shortage pricing issues.

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

Id.

at 1, 3-4.

See

Shortage Pricing Paper.

11. In its January 2015 Notice Inviting Comments, the Commission requested comments on questions that arose from the price formation technical workshops.

In response, among other price formation issues, commenters addressed settlement intervals and shortage pricing.

Notice Inviting Post-Technical Workshop Comments, Docket No. AD14-14-000 (Jan. 16, 2015).

12. On September 17, 2015, the Commission issued a NOPR proposing to require that each RTO/ISO: (1) Settle energy transactions in its real-time markets at the same time interval it dispatches and prices energy, and settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves; and (2) trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs.

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.

Additionally, the Commission sought comment on whether to require that RTOs/ISOs settle real-time operating reserves transactions at the same interval as real-time energy dispatch and settlement intervals or whether a settlement interval that differs from an RTO's/ISO's real-time energy dispatch interval would be appropriate for some operating reserves transactions.

Finally, the Commission sought comment on the implementation schedule and the costs of implementation.

A list of commenters and the abbreviated names used for them in this Final Rule appears in the Appendix.

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

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

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

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

III. Discussion

A. Settlement Interval Reform

1. Need for Reform

13. In the NOPR,

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.

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

14. Commenters generally agree with the Commission's preliminary finding regarding the settlement interval proposal. For example, EPSA states that “[w]hen real-time settlements for generation or dispatchable demand are calculated based on hourly prices that are the simple average of sub-hourly prices resulting from the actual dispatch, there is a distortion to the real-time price signal impacting both reliability and efficiency.”

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.”

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.”

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.”

EPSA Comments, Pope Aff. at 2-3.

Potomac Economics Comments at 4.

Potomac Economics Comments at 4-5.

ELCON Comments at 2.

15. In some instances, commenters assert that the Commission should not affirm its preliminary finding on the settlement interval proposal. APPA and NRECA assert that Commission approval of any five-minute settlement implementation process should require vetting and approval by the RTOs'/ISOs' stakeholders.

Direct Energy asserts that the Commission should solicit further information from the RTOs/ISOs before determining whether or not to direct settlement interval reforms.

APPA and NRECA Comments at 4.

Direct Energy Comments at 6.

16. Based on analysis of the record, we adopt our preliminary findings, and, as described in detail below, conclude that certain RTO/ISO settlement practices are not just and reasonable and are unduly discriminatory and preferential. Accordingly, we direct each RTO/ISO to align its settlement and dispatch intervals by settling energy transactions in its real-time markets at the same time interval it dispatches energy, settling operating reserves transactions in its real-time markets at the same time interval it prices operating reserves, and settling intertie transactions in the same time interval it schedules intertie transactions, as discussed further herein.

2. Settlement Interval Reform for Energy Transactions and Operating Reserves

a. Proposal

i. Energy Transactions

17. In the NOPR, the Commission proposed to require that each RTO/ISO settle energy transactions in its real-time markets at the same time interval it dispatches energy. The Commission preliminarily found the use of hourly integrated prices for real-time settlement may have the unintended effect of distorting price signals, and, in certain instances, contributing to market participants' failing to respond appropriately to operating needs.

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.

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

18. To remedy any potentially unjust and unreasonable rates caused by the use of hourly integrated prices for real-time settlement, the Commission proposed in the NOPR to require that each RTO/ISO settle energy transactions in its real-time markets at the same time interval it dispatches energy.

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.

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.

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

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.”

Although the Commission noted that dispatch and pricing of energy and operating reserves are closely linked through co-optimization in the real-time market, it also noted that certain RTOs/ISOs acquire operating reserves on a different time interval than they dispatch energy.

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.

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.

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

b. Current Practices in the RTOs/ISOs

i. Energy Transactions

22. The following table describes how each RTO/ISO currently dispatches and settles real-time energy transactions:

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

Real-time dispatch

(minutes)

Real-time

settlement

CAISO

5 minute.

ISO-NE

hourly average.

MISO

hourly average.

NYISO

5 minute.

PJM

hourly average.

SPP

5 minute.

ii. Operating Reserves

23. The RTOs/ISOs

vary in how they settle and treat operating reserves. For example, CAISO represents that it settles its operating reserve transactions on fifteen-minute intervals and dispatches energy on five-minute intervals.

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.

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).

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).

CAISO Comments at 8.

24. The PJM Market Monitor explains that the synchronized and regulation reserves markets in PJM clear hourly but already incorporate five-minute LMP data for calculating opportunity costs. The PJM Market Monitor states that the offer price in PJM's synchronized reserve market includes both the direct short-run marginal cost of providing synchronized reserves, which does not vary every five minutes, and the opportunity cost of providing synchronized reserves, which does vary with five-minute LMPs. The PJM Market Monitor explains that PJM currently updates the opportunity cost every five minutes using five-minute LMP data for the Tier 2 synchronized reserve market and recalculates the market clearing price every five minutes, with settlement based on the average of the five-minute clearing price.

PJM Market Monitor Comments at 8.

25. The PJM Market Monitor explains that, in PJM's regulation market, the offer price includes both the direct short-run marginal cost of providing regulation, which does not vary every five minutes, and the opportunity cost of providing regulation, which varies with five-minute LMPs. The PJM Market Monitor adds that PJM currently updates the opportunity cost every five minutes using five-minute LMP data for the regulation market and recalculates the clearing price every five minutes, with settlement based on the average of five-minute clearing prices. The PJM Market Monitor also notes that PJM purchases other forms of operating reserves on a cost basis, including Tier 1 synchronized reserves, non-synchronized reserves, and day-ahead scheduling reserves.

PJM Market Monitor Comments at 8.

26. NYISO explains that it uses five-minute intervals to settle its real-time markets for energy, regulation service, and operating reserves.

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.

SPP prices and settles operating reserve products in its real-time market on a dispatch interval, or five minute, basis.

NYISO Comments at 2-3.

ISO-NE Comments at 2-3.

SPP Market Protocols, Sections 4.5.4 and 4.5.9.

c. Comments on the Proposed Settlement Interval Reform

27. Twenty-seven of the thirty commenters providing input on this issue generally support the NOPR's proposed settlement interval reform.

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.

Others point to additional benefits.

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.

Inertia Power and DC Energy Comments at 2; Potomac Economics Comments at 1; Westar Comments at 1; PSEG Comments at 3.

i. Comments From the RTOs/ISOs

28. The ISO/RTO Council supports the Commission's goals of aligning prices with resource dispatch instructions and operating needs and specifically supports the settlement interval proposal for energy transactions. The ISO/RTO Council states that the proposed settlement interval reform will make resource compensation more transparent by increasing the proportion of payments to resources through the price paid for energy as opposed to uplift.

ISO/RTO Council Comments at 2.

29. In separate comments, NYISO, ISO-NE., MISO, and PJM support the settlement interval proposal for both energy and operating reserve transactions. Likewise, in separate comments, CAISO supports the settlement interval proposal for energy transactions, but does not support requiring RTOs/ISOs to settle all real-time operating reserves transactions at the same interval as real-time energy dispatch and settlement intervals.

30. CAISO states that the settlement interval proposal would improve market efficiency, and that accurate price signals provide market participants with incentives to develop needed capabilities and to offer those capabilities into the market.

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.

CAISO Comments at 7.

31. However, CAISO does not support requiring RTOs/ISOs to settle all real-time operating reserves transactions at the same interval as real-time energy dispatch and settlement intervals.

Instead, CAISO asserts that it is appropriate to maintain its current fifteen-minute procurement and settlement interval for operating reserves transactions, which differs from the five-minute real-time energy dispatch interval. CAISO explains that its current settlement methodology aligns ancillary services commitment with internal generation commitment and intertie transactions scheduling so that the market accurately reflects the overall amount of supply resources available to provide energy and ancillary services.

CAISO Comments at 17-18.

32. NYISO supports the settlement interval proposal and asserts that its use of five-minute intervals to settle its real-time markets for energy, regulation service, and operating reserves, has provided significant incentives for resources to follow dispatch instructions and opportunities for supply resources to obtain full payment for their performance based on actual system conditions.

NYISO Comments at 2-3.

33. ISO-NE contends that settling on sub-hourly or five-minute intervals would help to improve price signals and resource compensation.

ISO-NE states that five-minute settlements will help improve price formation by ensuring that compensation for real-time performance sends more accurate market signals of power system conditions when energy is provided.

ISO-NE supports the settlement interval proposal for operating reserve transactions. It asserts that settling all real-time operating reserves transactions at the same interval as real-time energy dispatch and settlement intervals would assist in aligning dispatch following incentives in markets that simultaneously co-optimize energy and reserve dispatch in real-time. ISO-NE states it intends to implement five-minute settlement of real-time operating reserves in connection with implementing five-minute settlement of real-time energy transactions, which is a current discussion among ISO-NE stakeholders.

ISO-NE Comments at 2.

ISO-NE Comments at 2-3.

34. MISO asserts that the inconsistency between dispatch and settlements may produce financial outcomes that do not align with the guiding principles of co-optimized (energy and ancillary services) security constrained economic dispatch.

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.

MISO Comments at 2.

MISO Comments at 7-8.

35. PJM states that ancillary services, including operating reserves, should settle on the same interval as energy because they are co-optimized. PJM argues that not doing so could yield discrepancies between the prices used to settle each product and could therefore undo enhancements made since implementation of Order No. 719, reduce market efficiencies, disrupt operations, and hinder proper price formation.

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.

PJM Comments at 9.

PJM Comments at 2.

ii. Comments by Market Monitors

36. The PJM Market Monitor agrees that it would be appropriate to implement five-minute pricing for the reasons stated in the NOPR, and that implementing five-minute settlements will contribute significantly to reducing uplift payments in PJM, an ongoing goal in the PJM region.

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.

PJM Market Monitor Comments at 2, 4.

PJM Market Monitor Comments at 8-9.

37. Potomac Economics, which serves as the market monitor for ISO-NE., MISO, and NYISO, argues that hourly settlements encourage resources not to follow dispatch instructions or to decrease their flexibility by restricting dispatch ranges and offering slower ramp rates, and states that MISO pays uplift to alleviate these issues. Potomac Economics cites its 2014 MISO State of the Market Report to show how five-minute settlements would change total payments to resources compared to current hourly settlements. This analysis showed that fossil-fueled resources in 2014 received settlements that were $35 million less than they would have received if the settlement were based on five-minute prices and output, and that only one-fifth of this lost value was paid via uplift. In contrast, Potomac Economics represents that non-fossil resources were paid on net in hourly revenues slightly above what they would have received with five-minute settlements. Potomac Economics asserts that five-minute settlement provides greater compensation to fossil resources, more accurately representing the flexibility fossil resources provide to the system. In contrast, Potomac Economics argues that hourly settlement overvalues wind resources because such resources cannot ramp up in response to higher prices, are negatively correlated with load and contribute to higher congestion at higher output levels.

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.

Potomac Economics Comments at 6.

Potomac Economics Comments at 1.

38. The SPP Market Monitor agrees with the Commission's preliminary finding that aligning settlement and dispatch intervals would make resource compensation more transparent by increasing the proportion of resource payments made through energy and operating reserve payments instead of uplift.

The SPP Market Monitor states that aligning dispatch and settlement intervals in neighboring markets would enhance price signals at seams and enhance market efficiency.

SPP Market Monitor Comments at 2.

SPP Market Monitor Comments at 2-3.

iii. Comments Supporting the Proposed Settlement Interval Reform

39. Many commenters expressly support the NOPR's settlement interval proposal, citing many of the benefits that were outlined in the NOPR.

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.

They also assert that the settlement interval proposal will properly compensate resources for the service they provide and will more fully recognize the value of flexible or fast-ramping resources.

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.

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.

Inertia Power and DC Energy Comments at 2; Westar Comments at 1, 3; EEI Comments at 6-7; Exelon Comments at 4-5.

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.

See

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

40. More specifically, Exelon asserts that the settlement interval proposal will support ongoing market improvements, such as ISO-NE's performance incentive mechanism, effective in June 2018, that will pay resources bonuses or impose penalties based on performance during operating reserve shortages that last five minutes or longer. Exelon argues that ISO-NE's market must settle at five-minute intervals to implement this mechanism completely.

Exelon Comments at 5.

41. According to EDP Renewables, greater participation of fast ramping renewable resources will also enhance resource adequacy, produce cost savings for consumers, and improve grid resilience.

EDP Renewables Comments at 3.

42. Some commenters also argue that the settlement interval proposal will reduce market inefficiencies and lead to greater investment. PSEG asserts that the proposed reforms correct market flaws that have caused inefficiencies in both price signals and resource dispatch decisions.

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.

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.

PSEG Comments at 3.

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

EDP Renewables Comments at 2.

43. EPSA argues that implementing sub-hourly settlement intervals is needed to obtain the full benefits of other price formation reforms to improve the accuracy with which real-time prices communicate the time-dependent and location-dependent value of incremental energy and ancillary services.

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

44. TAPS does not oppose the settlement interval proposal, as long as it does not impose an undue burden on load serving entities.

TAPS Comments at 4.

45. EPSA supports the settlement interval proposal for operating reserves. It argues that real-time operating reserves should be co-optimized in the dispatch and settled with energy for every hourly sub-interval (generally five minutes) to ensure that resources are compensated for following RTO/ISO instructions and are indifferent to providing either energy or operating reserves during periods of high energy or operating reserves prices.

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.

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.

EPSA Comments, Pope Aff. at 11.

EPSA Comments, Pope Aff. at 12-13.

46. Dominion supports the settlement interval proposal for operating reserves. However, Dominion argues that only specific reserve products should settle at the same interval that they are priced and that other types of settlement provisions, such as make-whole payments, should not.

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.

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.

Dominion Comments at 3.

47. PSEG supports applying the proposed settlement intervals to both real-time energy transactions and real-time operating reserves. PSEG explains that given the linkage between energy transactions and reserve services, settling those products on different intervals would introduce dislocations, and incent resource actions that could disrupt these co-optimization objectives, essentially undermining the Commission's objectives in the NOPR.

PSEG Comments at 4-5.

48. The New Jersey Board concurs with the PJM Market Monitor that no changes should be made in PJM's synchronized reserve and regulation markets given that the opportunity cost component in these ancillary services markets, which is the only cost component subject to five-minute changes in LMP, already accounts for the five-minute interval changes.

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.

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.

New Jersey Board Comments at 4.

Duke Comments at 5.

EEI Comments at 9-10 & n.16.

iv. Comments Opposed to the Proposed Settlement Interval Reform

49. Several commenters oppose the settlement interval proposal. Direct Energy states that the Commission should solicit information from RTOs/ISOs to determine whether existing generation resources are able to respond effectively to five-minute price signals before determining whether any settlement interval reform is warranted.

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. 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.

Direct Energy Comments at 6.

Direct Energy Comments at 3-5.

50. Duke, APPA and NRECA, and Concerned Cooperatives argue that the Commission should refrain from requiring a one-size-fits-all approach.

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.

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.

Additionally, Concerned Cooperatives disagree with the Commission's conclusion that reforming the settlement intervals will result in more efficient use of generating resources.

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

Duke Comments at 4; APPA and NRECA Comments at 3; Concerned Cooperatives Comments at 1.

Duke Comments at 4-5.

51. Concerned Cooperatives argue that the benefits of moving to five-minute settlements will not offset the cost. They state that the Potomac Economics report cited in the NOPR shows that switching to matching intervals would force MISO market participants to expend millions of dollars on upgrades and operation and maintenance (O&M) costs, without realizing lower rates. Instead, those participants would face an annual increase of approximately $28 million, after netting the estimated $6.6 million system benefit from the increased payments to generators of about $35 million dollars.

Concerned Cooperatives Comments at 10 (citing Potomac Economics, 2014 State of the Market Report for the MISO Electricity Markets, at 43-44, Figure 19 (2015)).

52. Concerned Cooperatives further argue that the Commission relies solely upon a letter filed in Docket No. AD14-14-000

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.

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.

Concerned Cooperatives represent that 90 to 95 percent of their transactions take place in the day-ahead market, which settles on an hourly basis, and that adopting five-minute settlement intervals in the real-time market does not help Concerned Cooperatives hedge prices.

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.

Concerned Cooperatives Comments at 11 (citing Comments of Wärtsilä North America, Inc., Docket No. AD14-14-000, at 1-2 (Mar. 6, 2015)).

Concerned Cooperatives Comments at 11.

Concerned Cooperatives Comments at 12.

d. Commission Determination

i. Energy Transactions

53. We adopt the NOPR proposal to require that each RTO/ISO settle energy transactions in its real-time markets at the same time interval it dispatches energy, as discussed below.

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.

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 34.

54. As discussed below, providing the correct incentives for market participants to follow commitment and dispatch instructions, make efficient investments in facilities and equipment, maintain reliability, and increase transparency is fundamental to proper formation of energy prices, helping to ensure just and reasonable rates, terms and conditions of service.

55. One important element of ensuring reliable grid operations is resources following dispatch instructions. The requirement that each RTO/ISO settle energy transactions at the same interval it dispatches energy sends accurate market signals of power system conditions, thus encouraging resources to follow commitment and dispatch instructions, a point noted by ISO-NE.

ISO-NE Comments at 2.

56. The settlement interval requirement for energy transactions also provides an incentive to make efficient investments in facilities and equipment.

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.

More flexible resources will help system operators address transient system conditions. We find that greater participation of these more flexible resources should generally enhance resource adequacy because it allows the participation of diverse resources and improves reliability, as noted by EDP Renewables.

EPSA Comments, Pope Aff. at 4.

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.

EDP Renewables Comments at 2-3.

57. The settlement interval requirement for energy transactions should help in maintaining reliability because resources will have a greater incentive to follow dispatch instructions, as noted by Exelon.

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.

Exelon Comments at 4-5.

CAISO Comments at 7.

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 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.

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.

Reducing out-of-market uplift payments can be beneficial to RTOs'/ISOs' market participants because, among other reasons, charges to market participants for uplift are often volatile. As a result, market participants may build risk premiums into their resource bids in the real-time energy market to shield them from the uncertainty associated with unexpected uplift charges.

See

Staff Analysis of Uplift in RTO and ISO Markets, Docket No. AD14-14-000, at 18 (Aug. 2014),

http://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf

. In addition, making system conditions and compensation more transparent through market prices will make that price apparent to all available resources and thus encourage them to fully participate in the market, which is likely to reduce generation costs incurred by load.

100

In addition to greater transparency, reducing uplift is a goal generally. For example, “[t]he implementation of five minute settlements would contribute significantly to the reduction of uplift payments, which is an ongoing goal of PJM, of the Market Monitor and of PJM members.” PJM Market Monitor Comments at 4.

59. Taken together, the benefits we expect as a result of this settlement reform will ensure that rates are just and reasonable and not unduly discriminatory or preferential.

60. We are not persuaded by the arguments opposing the settlement interval proposal. Underlying much of the opposition is the assumption that many resources cannot take advantage of five-minute settlement intervals because they are not flexible enough to respond to five-minute dispatch. For example, Direct Energy argues that RTOs/ISOs should report the types of resources able to effectively modify their output to respond to five-minute price signals.

101

The concern Direct Energy identifies is, in fact, one of the objectives of this reform. Specifically, resources that are not able to respond quickly enough to address acute system needs should not receive the same level of compensation as those resources that are able to flexibly respond.

102

Further, we note that all RTOs/ISOs have a combination of resources, some of which can respond within five minutes and some that cannot, and that knowing the exact percentages of resources available to respond to prices is not determinative of whether the reforms adopted here will prove beneficial. Instead, we believe it is important to ensure settlement practices do not distort existing five-minute pricing signals.

101

Direct Energy Comments at 6.

102

This rule does not require resources to be dispatched more quickly than they are now, but it does increase the incentive for those resources that can and do respond quickly.

61. We are not persuaded by Concerned Cooperatives' argument that the settlement interval proposal should be rejected because market participants, such as Concerned Cooperatives, funding the reform do not have a large fraction of their positions in the real-time market and therefore will not benefit significantly from it.

103

We find that aligning prices and settlement intervals will enhance the operation of markets by ensuring resources respond to actual system condition regardless of the percentage of resources that clear in the day-ahead market.

103

Concerned Cooperatives Comments at 11.

62. We also disagree with Concerned Cooperatives' statement that the Commission relied upon a single document to support its finding without additional analysis.

104

Commenters supporting the reform have provided sound economic analysis and examples demonstrating the value of the proposed settlement reform.

105

Though Concerned Cooperatives state that many market participants would not benefit from the reform even though they would be responsible for funding it,

106

we believe that many market participants are likely to benefit from the reform through improved economic incentives to respond to system needs. Potomac Economics' analysis of fossil-fueled and non-fossil-fueled resources

107

demonstrates that settlement reform will incentivize generator flexibility, improve generators' dispatch performance, and increase investments in more flexible resources.

104

Concerned Cooperatives Comments at 11.

105

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

See also

Supplemental Comments of Direct Energy (filed Mar. 4, 2016).

151

EEI Comments at 8-9.

102. PJM, however, states that it is advantageous to apply the proposed rule to load, and proposes to settle load on the same interval as dispatch intervals by using a combination of state-estimator and telemetry data for each settlement interval.

152

PJM states that it thus does not foresee changes being required for market participants' metering.

153

152

PJM Comments at 5.

153

PJM Comments at 5.

103. Mr. Centolella states that advancing load settlements to reflect the actual interval demand of each load serving entity's customers could remove an important barrier to developing the next generation of responsive demand. Mr. Centolella also encourages the Commission to work with states to optimize collecting customer data, and to evaluate how to support efficient price formation related to the load data used in wholesale settlements.

154

Mr. Centolella Comments at 4-6.

b. Commission Determination

104. We clarify that the Commission did not propose to apply the settlement interval proposal to load. We also clarify that adoption of the settlement interval requirements are not intended to change how load is metered. The Commission's basis for requiring changes to the settlement interval focused exclusively on supply resources rather than load. As a result, we have no record to require any changes to the settlement interval for load. However, we are not prohibiting settling load on a five-minute basis, and will evaluate any such proposals on a case-by-case basis in separate proceedings submitted pursuant to section 205 of the FPA.

B. Shortage Pricing Reform

1. Need for Reform

105. In the NOPR, the Commission stated that shortage prices send a short-term price signal to provide an incentive for the performance of existing resources and help to maintain reliability. The Commission noted that some RTOs/ISOs currently restrict the use of shortage pricing to certain causes of shortages, or some RTOs/ISOs require a shortage to exist for a minimum amount of time before triggering shortage pricing.

155

The Commission further noted that not invoking shortage pricing when there is a shortage (regardless of the duration or cause of that shortage) distorts price signals that are designed to elicit increased supply and to compensate resources for the value of the services they provide when the system needs energy or operating reserves. Because these price signals fail to reflect adequately the value that a resource provides to the system, the Commission preliminarily found in the NOPR that the resulting price is not just and reasonable.

156

155

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 46.

156

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 47.

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

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 48 (citing Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 192).

107. Commenters generally support the rationale provided by the Commission in support of the need for reform. For example, as discussed below, MISO, NYISO and ISO-NE all support the need for reform, and CAISO supports the conceptual need, but requests further clarifications. EEI and EPSA also support the Commission's shortage pricing proposal. Conversely, SPP and PJM, in joint comments, oppose implementing shortage pricing in all dispatch intervals, and request revisions if the Commission adopts its proposed reforms.

108. Based on analysis of the record, we adopt our preliminary findings and conclude that existing shortage pricing triggers that do not invoke shortage pricing when there is a shortage (regardless of duration or cause) are unjust and unreasonable and are unduly discriminatory and preferential. Thus, there is a need to reform the use of shortage pricing in RTO/ISO markets, as discussed further herein.

2. NOPR Proposal

109. In order to remedy the potentially unjust and unreasonable rates caused by restrictions on shortage pricing, the Commission proposed to require that RTOs/ISOs institute mechanisms that trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs.

3. Comments on the Proposed Shortage Pricing Reform

a. Comments by RTOs/ISOs

110. MISO states that it supports shortage pricing reform and maintains that MISO's current practices are already consistent with the Commission's proposal. Specifically, MISO states its operating reserve demand curve is used in the five-minute dispatch interval and triggers shortage pricing in any five-minute interval in which operating reserve requirements cannot be fully satisfied, regardless of duration or causation.

158

MISO also states that its recent implementation of extended locational marginal pricing (ELMP) considers offline fast-start resources in its price setting algorithm to more accurately reflect the cost of the next MW to meet demand during scarcity conditions.

159

MISO notes that if no economic offline fast-start resources are eligible, it will rely upon the operating reserve demand curve values for shortage pricing. MISO states that it is already compliant with the proposed rule on shortage pricing.

160

158

MISO Comments at 10.

159

See

MISO, Extended Locational Marginal Pricing, Docket No. ER12-668-000 (filed Dec. 22, 2011).

160

MISO Comments at 11-12.

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

ISO-NE Comments at 3.

112. NYISO supports the shortage pricing proposal, and states that it uses demand curves to price all reserve shortages, regardless of their duration. NYISO adds that it currently implements shortage pricing in its day-ahead and real-time markets using various demand curves for operating reserves, regulating reserves, and transmission security, where the demand curves represent the escalating value of each product as the level of any shortage increases.

162

NYISO also states that it does not interpret the NOPR to be addressing the use of offline resources in real-time pricing or to be implying that practices, such as the NYISO's “Hybrid Pricing” rules,

163

are inconsistent with the NOPR.

164

162

NYISO Comments at 6.

163

NYISO's Hybrid Pricing rules were adopted in 2001.

See New York Indep. Sys. Operator, Inc.,

95 FERC ¶ 61,121 (2001). The Hybrid Pricing rules apply to Real-Time Market pricing and relax the minimum operating limits of certain fast-start, block-loaded resources in order to permit them to be eligible to set price based on the incremental need that required their commitment.

164

NYISO Comments at 7.

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

CAISO Comments at 20.

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

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.

115. PJM and SPP filed joint comments opposing triggering shortage pricing in any dispatch interval in which a shortage of energy or operating reserves occurs. First, PJM and SPP state that they support shortage pricing only when “a shortage of a particular product exists that presents reliability concerns.”

168

PJM and SPP argue that applying shortage prices to shortage events that do not cause reliability concerns allows price increases even when such events are transitory, do not pose reliability concerns, and cannot be addressed due to limitations on resource response. PJM and SPP maintain that applying shortage pricing to some transient shortages will give inaccurate prices and could potentially degrade system reliability, and may also result in market pricing and operations that are contrary to the Commission's stated goals.

169

168

PJM and SPP Comments at 1.

169

PJM and SPP Comments at 1-2.

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

PJM and SPP Comments at 2-3.

117. PJM and SPP argue that allowing transient periods of shortage to trigger shortage pricing could overstate the severity of the operating condition and result in prices that do not accurately reflect operating conditions on the system, or last long enough to allow market participants responding to them to take meaningful action. In fact, PJM and SPP assert that responses may occur after the relevant interval has passed, which could be counterproductive operationally and economically. PJM and SPP pose two examples to illustrate this point. As the first example, they posit: PJM carrying the required amount of reserves when a market seller of a generation resource lowers the resource's economic maximum capability, for a brief time (ten minutes or less), causing PJM to have less reserves than its requirement. Currently, PJM can recover these reserves by re-executing its dispatch engine and re-dispatching its system; but under the shortage pricing reform, this could invoke shortage pricing, which would then attract more suppliers than needed and create disincentives for resources to back down once the event was over. In another example, they posit: PJM has scheduled a resource with a ten-minute start-up time to come online to provide energy so that another resource may be reduced to provide reserves; but if the resource scheduled to come online actually takes twenty minutes instead of ten, shortage pricing would be triggered under the shortage pricing proposal, and the second resource, instead of having its output reduced to provide reserves would now need to continue to provide energy, thus potentially leaving PJM short on reserves for a brief period.

171

PJM and SPP Comments at 4.

118. PJM and SPP introduce another hypothetical scenario from the SPP region. PJM and SPP state that SPP can temporarily use operating reserves to meet energy requirements during transient periods when system conditions do not present reliability concerns. PJM and SPP argue that while this may technically compromise the operating reserve requirement, the condition is transient and is recovered in less than ten minutes. According to PJM and SPP, this is not an operating reserve shortage, but rather a transient reallocation of capacity to manage temporary energy needs caused by the operational characteristics of resources. PJM and SPP further state that the examples described above do not present emergency conditions or

reliability concerns that would justify shortage pricing.

172

PJM and SPP Comments at 5-6.

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

PJM and SPP Comments at 7.

120. PJM and SPP further assert that a universal shortage pricing rule requiring shortage pricing even for transient circumstances would require the implementation of operating reserve demand curves that distinguish prices relative to varying degrees of shortage. PJM and SPP explain further that in PJM's case, the current operating reserve demand curves are a step function, which would need to be changed, and in SPP's case it would likely consider the implementation of a pricing gradient demand curve based on different degrees of shortages and their impact on reliability, rather than steep step curves.

174

PJM and SPP Comments at 8.

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

175

Potomac Economics Comments at 9.

176

Potomac Economics Comments at 7.

177

Potomac Economics Comments at 7.

122. Potomac Economics states that transitory shortages typically occur when the system is ramp-constrained, and that these are true shortages, because if a large contingency occurs during this period (

e.g.,

a generator tripping off-line), the RTO/ISO will not have the ability to replace the capacity because its other generators are already ramping as quickly as possible. Potomac Economics states that the Commission's proposal will lead to resources offering faster ramp rates, offering wider dispatch ranges and not self-scheduling resources, and offering shorter start times for natural gas turbines. Potomac Economics states that the proposal also has important long-term implications as it provides efficient incentives for participants to build more flexible, fast-ramping generating resources, and to make maintenance decisions on existing resources to increase their flexibility.

178

Potomac Economics Comments at 8.

123. Potomac Economics also states that allowing offline resources to set real-time energy and ancillary services prices can be efficient, but there are also conditions under which the use of these resources can artificially lower energy prices and obscure shortages.

179

Potomac Economics explains that if an RTO's/ISO's pricing model allows infeasible or uneconomic units to set prices, the offline units represent an artificial increase in real-time supply that will depress real-time prices. Further, Potomac Economics explains that the artificial increase in real-time supply can have a large effect when the system is experiencing an operating reserve or transmission shortage, which is ultimately not priced as a shortage because an offline unit has set the price.

180

179

Potomac Economics Comments at 9.

180

Potomac Economics Comments at 10.

124. Potomac Economics recommends that the Commission require RTOs/ISOs to demonstrate that their real-time pricing models do not allow offline units to set prices in a manner that undermines its real-time shortage pricing. Potomac Economics believes that this can be demonstrated by the RTO/ISO describing how and when offline units set real-time prices and showing that when offline units have set price historically that they are generally committed and dispatched as well. Potomac Economics further asserts that if the RTOs/ISOs cannot demonstrate this in their compliance filing, then they may need to make changes to their pricing models to ensure that they satisfy the Commission's price formation goals.

181

Potomac Economics Comments at 9-11.

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

182

PJM Market Monitor Comments at 9.

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

183

The SPP Market Monitor requests that the Commission address the ramp-constrained operating reserve shortage pricing issue in the Final Rule.

184

183

SPP Market Monitor Comments at 4 (citing SPP Tariff, Attachment AE 5.1.2.1 and 8.3.4.2).

184

SPP Market Monitor Comments at 4-6.

c. Comments Supporting the Shortage Pricing Reform

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

can respond to short duration shortages, and provide revenues to resources that reflect the value of the service provided.

185

In addition, several commenters, including EPSA and Westar, support the shortage pricing proposal and state that it should apply to all shortages, regardless of duration.

186

185

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

186

EPSA Comments at 9; EPSA Comments, Pope Aff. at 15; Golden Spread Initial Comments at 6; PJM Power Providers Comments at 4; Powerex Comments at 6; EDP Renewables Comments at 5-6; Entergy Nuclear Power Marketing Comments at 2; Exelon Comments at 6; PSEG Comments at 13; Westar Comments at 5; NEI Comments at 14; CEA Comments at 4; NGSA Comments at 5.

128. Several commenters support the Commission's shortage pricing proposal, arguing that market clearing prices should reflect shortage or emergency situations so that generators are provided transparent price signals that reflect the market conditions.

187

EPSA and Westar note that reflecting a shortage price signal during transient shortage events will result in a price signal that incents resources to respond to real-time system constraints based on a price that reflects the value of loss of load even if the event is less than ten minutes in duration.

188

Further, Westar states that if the “steepness” of regulation and operating reserve demand scarcity pricing curves is a concern then an RTO/ISO should create separate operating reserve scarcity demand curves for transitory periods versus periods lasting longer than ten minutes.

189

187

EEI Comments at 10; EPSA Comments at 9; PJM Power Providers Comments at 4; Westar Comments at 5; NEI Comments at 14.

188

EPSA Comments at 9; Westar Comments at 5.

189

Westar Comments at 5.

129. Some commenters state that the shortage pricing proposal will provide an incentive for existing resources to offer their supply and to be available if shortages occur and will provide an incentive for incremental investments to enable existing or new generation or dispatchable demand to respond to shortages, regardless of duration.

190

Further, CEA states that without appropriate compensation prices invariably become distorted insofar as they do not reflect the increased value of that resource with utmost accuracy and granularity.

191

In addition, NGSA comments that the proposal will encourage investments by generators that allow them to more reliably perform, leading to greater regional fuel assurance.

192

190

EPSA Comments, Pope Aff. at 15; NEI Comments at 14; CEA Comments at 4; NGSA Comments at 5.

191

CEA Comments at 4.

192

NGSA Comments at 5.

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

193

ANGA Comments at 5.

131. Powerex supports the Commission's proposal to require RTOs/ISOs to apply shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs.

194

Powerex contends that shortage pricing mechanisms tied to real-time conditions provide revenues to generators and demand side resources that provide energy and reserves when needed, which is an advantage over the capacity markets long-term focus on load growth and reliability.

195

194

Powerex Comments at 6.

195

Powerex Comments at 8.

132. EDP Renewables states that the Commission's shortage pricing proposal would result in more accurate price signals than under existing market rules, and therefore would encourage greater investment in new production and storage technologies with the ability to respond quickly to shortages.

196

Similarly, ESA asserts that the shortage pricing reform will improve the ability for a resource to be compensated based on the value of the service the resource provides.

197

ESA maintains that, for energy storage resources to help ensure grid reliability, an economic incentive must exist to incorporate those resources onto the grid.

198

196

EDP Renewables Comments at 5-6.

197

ESA Comments at 4.

198

ESA Comments at 4.

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

199

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

134. PSEG states that it supports the shortage pricing proposal, that the proposal would address concerns about transparency, and that it would accomplish Order No. 719's objective of enhancing market efficiency by establishing a price that reflects the value of the loss of load and encourage resources to respond to shortage events.

200

PSEG further states that the absence of shortage pricing in the appropriate intervals is inefficient within individual RTOs/ISOs as well as between them, and it can frustrate the objectives of Coordinated Transaction Scheduling, which is currently being deployed by several RTOs/ISOs.

201

200

PSEG Comments at 13.

201

PSEG Comments at 14.

135. Golden Spread supports the Commission's proposed shortage pricing reform and argues that even the smallest amount of operating reserve and energy shortage should be reflected in scarcity pricing.

202

Golden Spread states that it has invested hundreds of millions of dollars in a fleet of new quick-start, fast-ramping generation resources in anticipation of the proper working of efficient marginal cost-based energy markets. Golden Spread states that to the extent these resources are not fully compensated because shortage pricing is masked, the value of these assets to Golden Spread's members and their consumers is diminished.

203

202

Golden Spread Reply Comments at 4.

203

Golden Spread Reply Comments at 7.

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

accurate price signals, akin to the shortage pricing proposal.

204

DTE Comments at 5.

d. Comments Recommending Changes to the Shortage Pricing Reform

137. Several commenters propose changes to the shortage pricing reform, or identify implementation issues in specific RTOs/ISOs.

138. Golden Spread, for example, states that the current SPP rules allow the temporary use of operating reserves to meet energy requirements during transient periods without invoking shortage pricing; in other words, SPP's rules encourage “price manipulation” undermining the transparency needed to incentivize longer term economic and reliable solutions.

205

Golden Spread Reply Comments at 5.

139. Golden Spread identifies examples of issues with certain SPP processes that it argues need to be addressed to comply with this reform and provides the following recommendations to resolve them: (1) Relax constraints to allow economic dispatch to solve when there is a resource capacity constraint, global power balance constraint, resource ramp constraint or operating constraint;

206

(2) prevent insufficient ramping capability to be subject to scarcity pricing;

207

(3) include fast-start technologies in a Reliability Unit Commitment action to avoid scarcity events, which then eliminates scarcity prices;

208

and (4) use of the concept of “head-room” to not factor much-needed ramping capacity in the LMP, which is reducing transparency and creating large uplifts.

209

206

Golden Spread Comments at 8.

207

Golden Spread Comments at 7-8.

208

Golden Spread Comments at 9-10.

209

Golden Spread Comments at 10.

140. ELCON states that the shortage pricing proposal should be adopted only if the Commission promotes the development of technology-neutral fast-ramp products paid to provide the specific shortage service, and for which compensation would not inflate real-time LMPs.

210

ELCON asserts that it conditionally supports the provision on shortage price triggers when applied to technology-neutral fast-ramping products—products it states could be provided by demand response, energy storage technologies, or generation—but not to real-time shortage pricing in which every resource dispatched or called by the system operator during a dispatch interval is paid the same price.

211

210

ELCON Comments at 2.

211

ELCON Comments at 3-6.

e. Comments Opposed to the Proposed Shortage Pricing Reform

141. Several commenters oppose the shortage pricing proposal. Several commenters argue that while the NOPR does not address the price level of the shortage pricing, to the extent that RTOs/ISOs do change shortage pricing triggers, the RTOs/ISOs should also evaluate whether shortage pricing levels remain just and reasonable.

212

For example, Concerned Cooperatives and APPA and NRECA argue that the NOPR will raise prices for consumers, but the Commission fails to quantify the cost impact of the shortage pricing proposal on consumers or the potential benefits to the market and consumers.

213

Concerned Cooperatives add that any changes to the shortage pricing triggers in the RTO/ISO markets must be cost-justified on the basis of quantifiable improvements in market efficiencies and cost reductions. Furthermore, Concerned Cooperatives argue that the Commission's shortage pricing will raise prices for consumers and increase revenues to incumbent generators.

214

212

APPA and NRECA Comments at 12; TAPS Comments at 14-15; Concerned Cooperatives Comments at 13.

213

Concerned Cooperatives Comments at 13-14; APPA and NRECA Comments at 6.

214

Concerned Cooperatives Comments at 13.

142. APPA and NRECA assert that it is important to understand how various resource types would respond to price signals created by the shortage pricing proposal. Specifically, they assert that the NOPR did not discuss whether a five-minute shortage pricing event would produce a sufficient response or only reflect a transient shortage resolvable without resorting to shortage pricing.

215

APPA and NRECA reference PJM representative Adam Keech's comment at the October 28, 2014 workshop on scarcity and shortage pricing, justifying PJM's current minimum duration of 30 minutes prior to triggering shortage pricing, and assert that the shortage pricing proposal runs the risk of rewarding generators that are already online just because another generator has not fully ramped up yet.

216

APPA and NRECA state that the NOPR neither discussed the degree to which the RTOs/ISOs are already in compliance with the proposal, the extent to which implementation would impact the frequency of shortage pricing events or impact prices, nor did it require RTOs/ISOs to undertake this analysis.

217

APPA and NRECA state that shortage pricing was triggered relatively infrequently in PJM and MISO, but more frequently in NYISO.

218

215

APPA and NRECA Comments at 6-7.

216

APPA and NRECA Comments at 7.

217

APPA and NRECA Comments at 9.

218

APPA and NRECA Comments at 9-10.

143. APPA and NRECA question the extent to which shortage pricing would improve short-term system efficiency. They comment that existing variations among RTOs/ISOs in shortage pricing approaches create an opportunity to analyze the efficacy of more frequent shortage events. They request that the Commission direct the RTOs/ISOs to provide evidence or examine whether the theoretical benefits of the shortage pricing proposal can be validated with actual resource decisions. APPA and NRECA caution that, without such analysis, entities, such as generators already online that cannot easily ramp up or down or financial marketers, could benefit financially without contributing to system efficiency.

219

Concerned Cooperatives also note that the Commission's rationale that prices must rise to reflect the true value of generation offered during operational shortages for the market to function properly fails to consider that only half of the market,

i.e.,

generators, may be able to respond to the price signal in real-time.

220

219

APPA and NRECA Comments at 10-11.

220

Concerned Cooperatives Comments at 14.

144. On the topic of long-term incentives, several commenters assert that no evidence exists that price signals as volatile and transient as shortage prices would be the basis for capital investments, whether to improve flexibility, whether to delay or avoid retirements, and especially not for the construction of new resources. APPA and NRECA assert that, even with a slight uptick in merchant plant construction compared to prior years, 95 percent of new construction was built under contract in 2014, and 98 percent of new construction was built under contract in 2013.

221

Further, Concerned Cooperatives argue that the evidence presented at the technical conferences preceding the NOPR demonstrate that short-term price signals from shortage pricing do not result in the long-term resource investment contemplated in the NOPR.

222

221

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

222

Concerned Cooperatives Comments at 15-16.

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

223

Moreover, APPA and

NRECA encourage the Commission to examine alternative methods of achieving its stated goal of incentivizing the availability of resources during periods of shortage, such as separately priced ramping products. APPA and NRECA urge the Commission to also examine whether such methods might achieve this goal at a lower cost to consumers.

224

Concerned Cooperatives further argue that the Commission's proposal is simply a transfer of wealth from consumers to generators without value to consumers, because, as the Commission admitted in the NOPR, some shortage events are so short that suppliers cannot react to the price signal.

225

223

Concerned Cooperatives Comments at 22-24.

224

APPA and NRECA Comments at 12.

225

Concerned Cooperatives Comments at 15-16.

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

226

ODEC Comments at 6.

147. APPA and NRECA also express concern that more frequent shortage pricing creates incentives to exercise market power and game market rules due to the potential for higher energy and operating reserve prices. They assert that if the proposal moves forward, each RTO/ISO should be required to reevaluate its market power mitigation rules and propose new or additional mitigation measures if necessary.

227

In addition, Concerned Cooperatives also argue that revising RTO/ISO tariffs to invoke shortage pricing more frequently is likely to increase opportunities for exploitation of consumers, but that the NOPR does not propose to require RTOs/ISOs to include in their compliance filings an analysis of needed reforms to ensure that consumers remain protected against the exercise of market power.

228

227

APPA and NRECA Comments at 15-16.

228

Concerned Cooperatives Comments at 15.

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

229

Concerned Cooperatives Comments at 24-25.

149. The New Jersey Board urges the Commission to allow PJM to retain its current shortage pricing mechanism—a thirty-minute look-ahead dispatch algorithm that identifies reserve shortages as only those lasting a minimum of thirty minutes. The New Jersey Board agrees with PJM that five-minute shortfalls are not necessarily symptomatic of system stress, but are merely transient shortfalls that can be quickly addressed through system re-dispatch.

150. More broadly, TAPS argues that any price signal during transient scarcity events is meaningless because resources cannot respond in time to the higher prices.

230

In addition, Direct Energy says that targeting transient shortages will create control issues and increase uplift, and the application of RTO/ISO shortage penalty factors to these transient situations will likely lead to higher prices than would otherwise be produced, creating unjust and unreasonable rates for generation compensation.

231

230

TAPS Comments at 7-13.

231

Direct Energy Comments at 10-11.

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

232

Direct Energy Comments at 10-11.

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

233

Direct Energy Comments at 11-13.

153. Concerned Cooperatives and APPA and NRECA argue that the NOPR does not account for differences among the RTOs/ISOs, maintaining that shortage pricing issues should be resolved through individual stakeholder processes.

234

Alternatively, Concerned Cooperatives request that the Commission not implement shortage pricing reform until an RTO/ISO demonstrates that it has eliminated the conditions that cause “artificial” shortages (those arising from mathematical modeling when no actual operational shortage exists), adopts rules preventing shortage pricing from being applied during artificial shortages, and adopts rules ensuring that shortage price levels are reduced during artificial shortages to reflect that these are not real shortages.

235

234

APPA and NRECA Comments at 5; Concerned Cooperatives Comments at 18.

235

Concerned Cooperatives Comments at 18.

154. Concerned Cooperatives also note that the NOPR fails to provide a comparison of the market design in RTO/ISO-administered markets that trigger shortage pricing for a shortage event of any duration and those that use longer duration events as the trigger.

236

Concerned Cooperatives argue that, before imposing a uniform rule, the Commission should determine whether these different shortage pricing rules have resulted in incremental resource development, improved generator response to shortage conditions, and/or reduced the need for uplift charges. Concerned Cooperatives state that in some cases, uplift payments may be the most cost-effective solution for consumers.

237

236

Concerned Cooperatives Comments at 26.

237

Concerned Cooperatives Comments at 26.

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

need for other reforms. Concerned Cooperatives note that several RTOs/ISOs already have rules providing adequate incentives for resource performance and investment, such as PJM's Reliability Pricing Model, ISO-NE's Forward Capacity Market, or MISO's ELMP.

238

Concerned Cooperatives assert that the Commission provides no evidence that more frequent triggering of shortage pricing is necessary to ensure resource adequacy or improve resource performance and flexibility when RTOs/ISOs use other market tools to achieve the same objectives set forth in the NOPR.

238

Concerned Cooperatives Comments at 18-21.

156. The New Jersey Board, APPA and NRECA and ODEC all acknowledge PJM's Capacity Performance Program

239

and argue to varying degrees that shortage pricing need not be considered here given this PJM reform or that the Commission should consider whether there would be overlap between this PJM reform and the shortage pricing proposal.

240

Furthermore, APPA and NRECA state that another factor in determining whether the shortage pricing proposal would improve market efficiency and benefit consumers is the extent to which there is an overlap between this proposal and other RTO/ISO market rules.

241

APPA and NRECA also point out that, in some RTOs/ISOs such as NYISO, scarcity pricing is an additional and separate revenue stream that can balance reliance on capacity market revenues.

242

Further, ODEC suggests that, instead of requiring an expansion of scarcity pricing to transient time periods, the Commission require PJM to consider the need to reduce, if not eliminate, scarcity pricing in light of the new Capacity Performance construct.

243

239

See PJM Interconnection, L.L.C.,

151 FERC ¶ 61,208 (2015).

240

New Jersey Board Comments 4-6; APPA and NRECA Comments at 14.

241

APPA and NRECA Comments at 13.

242

APPA and NRECA Comments at 14-15.

243

ODEC Comments at 8.

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

244

Concerned Cooperatives Comments at 25.

158. PG&E urges the Commission to examine transient shortages and their attendant price spikes, and resolve modeling issues that are causing these shortages. PG&E understands that shortage pricing might be appropriate to the extent that such pricing provides a meaningful price signal to resources. However, PG&E argues that most price spikes in the CAISO over the past five years have been so short that they have not provided a meaningful opportunity for resources to respond.

245

For example, PG&E states that from 2012 through 2014, the CAISO five-minute market saw positive price spikes (>$250/MWh) in approximately 0.75 percent of the intervals. PG&E argues that transitory price spikes do not contribute to market efficiency, but result in increased market costs, and they give false signals to virtual participants, which can distort day-ahead awards and prices. PG&E also asserts that these transitory price spikes have contributed to price divergence between day-ahead and real-time and have resulted in significant uplift costs.

246

245

PG&E Comments at 1-2.

246

PG&E Comments at 1-2.

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

247

PG&E Comments at 2.

160. Dominion states that it is concerned that some shortages are merely transient in nature due to slight differences in modeling and the ramping of generation, and may not warrant sending a shortage price signal to the market. Dominion argues that issues regarding transient shortages should be addressed prior to implementation of the proposed reforms.

248

Dominion states that the Commission should require RTOs/ISOs to specifically explain how the RTOs/ISOs will address this issue as part of their compliance filings. Further, Dominion asserts that the modification of shortage pricing triggers to better correlate to dispatch intervals should coincide with implementation of the Commission's proposal to align settlement intervals with dispatch intervals. Dominion argues that this will align a resource's timely response to shortage pricing with payment for its response.

249

248

Dominion Comments at 4-5.

249

Dominion Comments at 5.

4. Commission Determination

161. For the reasons discussed below, we adopt the NOPR shortage pricing proposal and modify the regulatory text to clarify that shortage pricing is required only when a shortage of energy or operating reserves is indicated by the RTO's/ISO's software.

162. Specifically, we require each RTO/ISO to trigger shortage pricing for any interval in which a shortage of energy or operating reserves is indicated during the pricing of resources for that interval. As stated in the NOPR, the shortage pricing requirement should “ensure that a resource is compensated based on a price that reflects the value of the service the resource provides.”

250

This rationale applies to any shortage “regardless of the duration or cause of [the] shortage.”

251

It thus would apply to “transient shortages.” Several commenters specifically agreed with this analysis.

252

Under this requirement, whenever a shortage of energy or operating reserves is indicated in an RTO's/ISO's pricing run software for a particular pricing interval, shortage pricing should be invoked even if during that period resources are ramping up to a particular level they are likely to reach in a few minutes.

250

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 52.

251

NOPR, FERC Stats. & Regs. ¶ 32,710 at P 47;