3580 Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices 

1The tailrace/forebay would be a small 

constructed inlet from the Pacific Ocean. Flows 

from the turbines would discharge into the tailrace/ 

forebay. Return flows for filling of the storage tanks 

would be pumped from the tailrace/forebay. 

Dated: January 15, 2015. 

Kimberly D. Bose, 

Secretary. 

[FR Doc. 2015–01043 Filed 1–22–15; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

[Project No. 14640–000] 

South Maui Pumped Storage, LLC; 

Notice of Preliminary Permit 

Application Accepted for Filing and 

Soliciting Comments, Motions To 

Intervene, and Competing Applications 

On October 20, 2014, South Maui 

Pumped Storage, LLC, filed an 

application for a preliminary permit, 

pursuant to section 4(f) of the Federal 

Power Act (FPA), proposing to study the 

feasibility of the South Maui Pumped 

Storage Project (South Maui Project or 

project) to be located on the Pacific 

Ocean, in unincorporated Maui County, 

Hawaii. The sole purpose of a 

preliminary permit, if issued, is to grant 

the permit holder priority to file a 

license application during the permit 

term. A preliminary permit does not 

authorize the permit holder to perform 

any land-disturbing activities or 

otherwise enter upon lands or waters 

owned by others without the owners’ 

express permission. 

The proposed project would consist of 

the following new features: (1) Four 

400-foot-long, 200-foot-wide, 50-foothigh oval concrete storage tanks; (2) a 

12,000-foot-long, 4.5-foot-diameter 

buried steel penstock; (3) a 150-footlong, 68-foot-wide concrete 

powerhouse; (4) two 15 megawatt (MW) 

Pelton turbine/generators; (5) three 10 

MW multi-stage variable speed pumps; 

(6) an approximately 400-foot-wide, 

450-foot-long tailrace/forebay; 1 (7) a 

12,000-foot-long, 4.5-foot-diameter 

buried steel supply pipeline; (8) two 28- 

kilovolt transmission lines totaling 

8,000 feet long, interconnecting with the 

existing Sempra Gas and Power-owned 

Auwahi wind turbine transmission line; 

(9) a 5.6-mile-long paved access road; 

and (10) appurtenant facilities. The 

estimated annual generation of the 

South Maui Project would be 5.2 

gigawatt-hours. 

Applicant Contact: Mr. Bart O’Keefe, 

United Power Corporation, P.O. Box 

1916, Discovery Bay, California 94505; 

phone: (510) 634–1550. 

FERC Contact: Sean O’Neill; phone: 

(202) 502–6462. 

Deadline for filing comments, motions 

to intervene, competing applications 

(without notices of intent), or notices of 

intent to file competing applications: 60 

days from the issuance of this notice. 

Competing applications and notices of 

intent must meet the requirements of 18 

CFR 4.36. 

The Commission strongly encourages 

electronic filing. Please file comments, 

motions to intervene, notices of intent, 

and competing applications using the 

Commission’s eFiling system at http://

www.ferc.gov/docs-filing/efiling.asp. 

Commenters can submit brief comments 

up to 6,000 characters, without prior 

registration, using the eComment system 

at http://www.ferc.gov/docs-filing/

ecomment.asp. You must include your 

name and contact information at the end 

of your comments. For assistance, 

please contact FERC Online Support at 

FERCOnlineSupport@ferc.gov, (866) 

208–3676 (toll free), or (202) 502–8659 

(TTY). In lieu of electronic filing, please 

send a paper copy to: Secretary, Federal 

Energy Regulatory Commission, 888 

First Street NE., Washington, DC 20426. 

The first page of any filing should 

include docket number P–14640–000. 

More information about this project, 

including a copy of the application, can 

be viewed or printed on the ‘‘eLibrary’’ 

link of Commission’s Web site at 

http://www.ferc.gov/docs-filing/

elibrary.asp. Enter the docket number 

(P–14640) in the docket number field to 

access the document. For assistance, 

contact FERC Online Support. 

Dated: January 16, 2015. 

Kimberly D. Bose, 

Secretary. 

[FR Doc. 2015–01140 Filed 1–22–15; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

[Docket No. AD14–14–000] 

Price Formation in Energy and 

Ancillary Services Markets Operated 

by Regional Transmission 

Organizations and Independent 

System Operators; Notice Inviting 

Post-Technical Workshop Comments 

On September 8, October 28, and 

December 9, 2014, the Federal Energy 

Regulatory Commission (Commission) 

staff conducted a series of technical 

workshops to evaluate issues regarding 

price formation in the energy and 

ancillary services markets operated by 

Regional Transmission Organizations 

(RTOs) and Independent System 

Operators (ISOs) (RTOs/ISOs). 

All interested persons are invited to 

file post-technical workshop comments 

on any or all of the questions listed in 

the attachment to this Notice. We 

emphasize that commenters need not 

answer all of the questions. Commenters 

should organize responses consistent 

with the structure of the attached 

questions and take care to identify to 

which RTO/ISO the comment applies. 

Commenters are also invited to 

reference material previously filed in 

this docket, including technical 

workshop transcripts. These comments 

must be filed with the Commission no 

later than 5:00 p.m. Eastern Standard 

Time on February 19, 2015. 

For more information about this 

Notice, please contact: 

Mary Wierzbicki (Technical 

Information), Office of Energy Policy 

and Information, Federal Energy 

Regulatory Commission, 888 First 

Street NE., Washington, DC 20426, 

(202) 502–6337, mary.wierzbicki@

ferc.gov. 

Joshua Kirstein (Legal Information), 

Federal Energy Regulatory 

Commission, 888 First Street NE., 

Washington, DC 20426, (202) 502– 

8519, joshua.kirstein@ferc.gov. 

Dated: January 16, 2015. 

Kimberly D. Bose, 

Secretary. 

Post-Technical Conference Questions 

for Comment 

The goals of proper price formation 

are to: Maximize market surplus for 

consumers and suppliers; provide 

correct incentives for parties to follow 

commitment and dispatch instructions, 

make efficient investments in facilities 

and equipment, and maintain reliability; 

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 ensure that all suppliers 

have an opportunity to recover their 

costs. With proper price formation, the 

RTO/ISO would ideally not need to 

commit any additional resources 

beyond those resources scheduled 

economically through the market 

processes, and load would reduce 

consumption in response to price 

signals such that market prices would 

reflect the value of electricity 

consumption without the need to curtail 

load administratively. 


tkelley on DSK3SPTVN1PROD with NOTICES
Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices 3581 

1Although the discussion herein focuses on RTO/ 

ISO markets, similar technical and operational 

limitations impact the efficient commitment of 

resources by electric utilities operating in other 

market structures, such as vertically integrated 

utilities. 

2Other efforts, like Staff’s annual meeting with 

RTO/ISO operations staff and the annual market 

software conference, are intended to make progress 

on these longer term issues. See http://

www.ferc.gov/industries/electric/indus-act/marketplanning.asp. 

3See, e.g., Operator Actions Workshop, Docket 

No. AD14–14–000, Tr. 180:8–183:4 (Dec. 9, 2014); 

Uplift Workshop, Docket No. AD14–14–000, Tr. 

168:1–16 (Sept. 8, 2014). For this purpose we are 

defining uplift credits as payments made to 

resources whose commitment and dispatch by an 

RTO/ISO result in a shortfall between the resource’s 

offer and the revenue earned through market 

clearing prices. 

4FERC, Staff Analysis of Uplift in RTO and ISO 

Markets, Docket No. AD14–14–000, at 21–28 (Aug. 

2014), available at http://www.ferc.gov/legal/staffreports/2014/08-13-14-uplift.pdf. 

5FERC, Price Formation in Organized Wholesale 

Electricity Markets: Staff Analysis of OperatorInitiated Commitments in RTO and ISO Markets, 

Docket No. AD14–14–000, at 28–30 (Dec. 2014), 

available at http://www.ferc.gov/legal/staff-reports/ 

2014/AD14-14-operator-actions.pdf. 

6 Id. 

7Operator Actions Workshop, Docket No. AD14– 

14–000, Tr. 282:9–25 (Dec. 9, 2014). 

In reality, RTO/ISO energy and 

ancillary services market outcomes are 

impacted by a number of technical and 

operational considerations.1 At three 

workshops on price formation—Uplift 

Workshop, held September 8, 2014 

(Uplift Workshop); Shortage Pricing, 

Offer Price Mitigation, and Offer Price 

Caps Workshop, held October 28, 2014 

(Shortage Pricing/Mitigation Workshop); 

and Operator Actions Workshop, held 

December 9, 2014 (Operator Actions 

Workshop)—panelists described 

software limitations, operational 

uncertainty, and limited flexibility of 

resources as challenges to achieving 

efficient price formation. These 

limitations are to some extent inherent 

in the complexity of the electric system 

and the tools available today to 

maintain reliable operations, and are 

unlikely to be addressed fully for the 

foreseeable future.2

Notwithstanding the foregoing 

technical limitations and operational 

realities, the Commission believes there 

may be opportunities for RTOs/ISOs to 

improve the energy and ancillary 

service price formation process. 

Based on discussions during the three 

price formation workshops, Staff 

developed the following questions to 

better understand the ways in which to 

improve price formation in RTOs/ISOs. 

When responding to the questions 

below, please also comment on any 

relevant differences among RTOs/ISOs, 

the time needed to implement any 

potential solutions, and impediments to 

implementing any potential solutions. 

1. Offer Caps 

High natural gas prices during the 

winter of 2013–2014, as discussed at the 

price formation workshops, indicated 

that the current generic $1,000/MWh 

cap on energy offers (‘‘offer cap’’) might 

be insufficient to allow natural gas-fired 

generators to recover their costs when 

natural gas prices spike during 

constrained winter periods. 

a. Should the $1,000/MWh offer cap 

be modified? 

i. If the offer cap is modified, what 

form should the offer cap take? For 

instance, should a modified cap be set 

at a level greater than the current 

$1,000/MWh cap and apply even if a 

resource has costs greater than the new 

cap or should the offer cap be replaced 

with a structure that allows offers at the 

higher of marginal cost or the existing 

$1,000/MWh cap? Should it be a fixed 

cap or a floating cap that varies with the 

price of fuel (e.g., natural gas)? If a 

modified cap were set as a fixed offer 

cap, what should the new offer cap be? 

What should be the basis for 

determining the fixed offer cap? 

ii. If the offer cap should not be 

modified or set such that marginal costs 

could be greater than $1000/MWh, how 

should the Commission ensure that 

suppliers with costs greater than the cap 

have the opportunity to recover those 

costs? 

iii. Do the real-time and day-ahead 

market clearing processes allow 

sufficient time to verify the cost-basis of 

the marginal resources that exceed the 

offer cap? Does the settlement process 

allow sufficient time to verify costs of 

resources that receive uplift associated 

with offers that exceed the offer cap? 

b. What are the advantages and 

disadvantages of having offer caps be set 

at the same level across all RTOs/ISOs? 

Would different offer caps across the 

RTOs/ISOs exacerbate interface pricing 

issues at RTO/ISO borders? If so, how? 

Would an offer cap that takes the form 

of the higher of marginal cost or $1,000/ 

MWh create the same issues as setting 

different offer caps across RTOs/ISOs? 

c. What impact would adjusting the 

offer cap have on other aspects of RTO/ 

ISO price formation (e.g., mitigation 

rules or shortage pricing rules)? Would 

other market rule changes be necessary 

if offer cap levels were adjusted? Do 

other challenges associated with 

modifying offer cap rules exist? If so, 

what are they? If offer cap rules are 

adjusted, how quickly could RTOs/ISOs 

incorporate adjusted offer cap rules into 

their software and the market clearing 

process? 

d. Should the same offer cap that 

applies to generation also apply to load 

bids? What are the advantages and 

disadvantages of applying an offer cap 

to load bids? 

2. Transparency 

At the Uplift and Operator Actions 

Workshops, some panelists addressed 

issues concerning insufficient 

transparency of uplift and operator 

actions.3 Improved transparency could 

inform resource entry and exit and 

market rule discussions; improved 

transparency could also improve market 

understanding, predictability, and 

confidence. 

a. What should RTOs/ISOs do to 

improve transparency of uplift credits 

and charges, unit commitment, and 

other operator actions? Please comment 

on the type of information that would be 

useful, why it is necessary, whether it 

should be shared with specific resources 

or available to all, the timing of its 

release, and whether it is feasible to 

release the information in real-time. 

b. What types of information should 

not be shared publicly? Why? What are 

the concerns with commercially 

sensitive information? 

c. Commission Staff’s August 2014 

report on uplift noted several issues 

with the consistency and granularity of 

uplift data provided as part of the 

Electric Quarterly Reports.4 What steps 

could be taken to improve the quality of 

uplift data required to be reported as 

part of the Electric Quarterly Reports? 

3. Pricing Fast-Start Resources 

Commission Staff’s December 2014 

paper about operator-initiated 

commitments discussed how RTOs/

ISOs relax the minimum operating level 

of resources to make certain blockloaded fast-start resources appear 

dispatchable to the pricing software, 

and thus eligible to set the market 

clearing price as the marginal resource.5

The paper also discussed how some 

RTOs/ISOs have modified the locational 

marginal price (LMP) framework to 

include start-up and no-load costs of 

certain fast start resources (e.g., New 

York Independent System Operator, 

Inc.’s (NYISO’s) Hybrid Pricing).6

a. During the Operator Actions 

Workshop, panelists explained that 

relaxing resource minimum operating 

limits can lead to incentive and 

operational issues such as overgeneration.7 What tradeoffs are involved 

with relaxing the minimum operating 

limits of block-loaded resources to zero 

for purposes of price setting? Should 

relaxing the minimum operating level 

be limited to block-loaded fast-start 


tkelley on DSK3SPTVN1PROD with NOTICES
3582 Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices 

8See Operator Actions Workshop, Docket No. 

AD14–14–000, Tr. 253:23–254:2 (Dec. 9, 2014); 

Scarcity and Shortage Pricing, Offer Mitigation and 

Offer Price Caps Workshop, Docket No. AD14–14– 

000, Tr. 52:21–22, 53:11–16, 54:10–17 (Oct. 28, 

2014). 

9Operator Actions Workshop, Docket No. AD14– 

14–000, Tr. 149:7–11; 151:3–6; 291:6–8 (Dec. 9, 

2014). 

10See id. at 291:9–22. 

11See, e.g., Cal. Indep. Sys. Operator Corp., 132 

FERC ¶ 61,087, order on compliance filing, 132 

FERC ¶ 61,273 (2010). 

12Scarcity and Shortage Pricing, Offer Mitigation 

and Offer Caps Workshop, Docket No. AD14–14– 

000, Tr.21:16–21 (Oct. 28, 2014). 

13 Id. at 133:6–15. 

14See, e.g., Uplift Workshop, Docket No. AD14– 

14–000, Tr. 49:7–11 (Sept. 8, 2014); Operator 

Actions Workshop, Docket No. AD14–14–000, Tr. 

16:5–18 (Dec. 9, 2014). 

15See, e.g., Uplift Workshop, Docket No. AD14– 

14–000, Tr. 192:12–18 (Sept. 8, 2014); Operator 

Actions Workshop, Docket No. AD14–14–000, Tr. 

21:7–23 (Dec. 9, 2014). 

16An N–1–1 contingency constraint is a 

constraint to ensure that following any single 

contingency (N–1), the system can withstand any 

other contingency (N–1–1). 

resources, or should relaxation be 

available to a larger set of resources? 

b. What are the merits of expanding 

the set of costs included in the energy 

component of LMP (i.e., start-up and noload costs)? What factors should be 

considered when expanding the set of 

costs included in the energy component 

of LMP? If the start-up and no-load costs 

of block-loaded fast-start resources are 

included in the LMP, how should they 

be included? For example, should startup costs only be included during 

intervals when the resource starts up? 

c. Should off-line resources be eligible 

to set the LMP? If so, should start-up 

and no-load costs be included in the 

price, or just incremental energy costs? 

4. Settlement Intervals 

Panelists at the Shortage Pricing/

Mitigation and Operator Actions 

Workshops generally supported subhourly, rather than hourly, settlement 

intervals as providing better incentives 

for resources to perform during shortage 

events and to make investments to 

enhance resource flexibility.8

a. What are the advantages and 

disadvantages of moving to sub-hourly 

settlements for the real-time market as 

they relate to price signals, market 

efficiency, and operations? 

b. What metering and RTO/ISO 

software changes would be needed to 

change settlement intervals from hourly 

to sub-hourly for the real-time market, 

and how long would these changes take 

to implement? Are there significant 

costs to RTOs/ISOs, and to market 

participants, of such changes? Are there 

any other impediments to adjusting 

settlement intervals? 

c. What are the advantages and 

disadvantages of changing from hourly 

to sub-hourly settlements in the dayahead market? 

5. New Products To Incent Flexibility 

Flexible resources that are capable of 

ramping up and down and/or starting 

up quickly provide value to the electric 

system. Panelists at the Operator 

Actions Workshop said that market 

designs which reward flexibility may 

stimulate investment in flexible 

capacity and provide resources more 

incentive to submit flexible offers.9 One 

panelist at the Operator Actions 

Workshop commented that existing 

market rules can create disincentives for 

resources to submit supply offers that 

reflect the full flexibility (for example, 

ramp rate, minimum run time, 

minimum operating level, maximum 

operating level, minimum down time) of 

their resources.10 In addition, panelists 

at the workshops discussed the need for 

locational reserve products to better 

reflect local needs for flexibility. 

a. How do RTOs/ISOs currently 

ensure that they will have sufficient 

flexibility during real-time? Specifically, 

to what extent are residual unit 

commitments used to acquire 

anticipated needed flexibility? 

b. How are flexible resources 

compensated for the value that they 

provide to the system? Does that 

compensation reflect the value? Why or 

why not? If compensation to flexible 

resources does not reflect their value, 

how should RTOs/ISOs compensate 

flexible resources for the service they 

provide? 

c. What are the tradeoffs between 

sending a price signal through a shortduration shortage event versus 

establishing a ramping product that is 

priced separately? 

d. What are the tradeoffs among 

procuring flexibility through unit 

commitments (e.g., headroom 

requirements) rather than through the 

ten-minute reserve products or through 

ramp products? 

e. Does allowing combined-cycle 

natural gas resources to submit different 

offers for different configurations 

facilitate more efficient price 

formation? 11 What are the advantages 

and disadvantages to generators of 

bidding these configurations? 

6. Operating Reserve Zones 

A lack of sufficiently granular reserve 

zones could be muting efficient price 

signals. At the Shortage Pricing/

Mitigation workshop, the NYISO 

panelist noted that NYISO is 

considering establishing a new reserve 

zone 12 and the PJM Interconnection, 

L.L.C. (PJM) external market monitor 

indicated that he believed PJM’s 

shortage pricing rules were not 

sufficiently locational. For instance, last 

year PJM experienced shortages in the 

American Transmission System, Inc. 

(ATSI) footprint that did not trigger 

shortage pricing because the ATSI zone 

is not a reserve zone.13

a. How does the establishment, 

elimination or reconfiguration of reserve 

zones affect price formation? What 

should the triggers be? From experience, 

do the RTOs/ISOs have the appropriate 

reserve zones defined? Are additional, 

fewer, or different reserve zones 

needed? 

b. Are processes in place for adding, 

removing, or changing reserve zones 

adequate for efficient price formation? 

7. Uplift Allocation 

Uplift allocation rules might impact 

resource participation decisions in 

RTO/ISO markets. For example, uplift 

allocation rules might incent 

participation in day-ahead markets or 

drive decisions on how to use financial 

products. 

a. Do uplift allocation rules reflect 

cost causation or mute potential 

investment signals? If so, how? 

b. What philosophy should govern 

uplift allocation? Do any of the RTOs/ 

ISOs have a best practice? What is it and 

why is it a best practice? 

c. Should uplift allocation categories 

reflect the reasons for committing a unit 

and incurring uplift? Would disclosing 

these reasons through publicly available 

data improve uplift transparency and 

provide information to facilitate 

modifications of the allocation of uplift 

costs? 

8. Market and Modeling Enhancements 

At the Uplift and Operator Actions 

Workshops, panelists highlighted 

various drivers of persistent, 

concentrated uplift and operator 

actions, including constraints that are 

not incorporated into market models.14

Panelists also noted that certain 

constraints are difficult to model 

accurately or to incorporate into both 

the day-ahead and real-time market 

models.15 These include local voltage 

constraints and reliability constraints 

such as N–1–1 contingency 

constraints.16

a. Assuming that RTOs/ISOs should 

improve their market models to better 

reflect the cost of honoring reliability 

constraints in energy and ancillary 

services market clearing prices, what 

types of constraints should RTOs/ISOs 

include in their market models, and 


tkelley on DSK3SPTVN1PROD with NOTICES
Federal Register / Vol. 80, No. 15 / Friday, January 23, 2015 / Notices 3583 

17 ISO–NE., Transmittal Letter, Docket No. ER13– 

1736–000 at 10 (filed June 20, 2013). 

18PJM Tariff Filing, Docket No. ER15–643–000 

(filed December 17, 2014). 

19Transmission constraint penalty factors are 

parameters within the market model that place a 

cost, known as a penalty factor, on a transmission 

constraint. These parameters allow the model to 

‘‘relax’’ the transmission constraint for a short time 

at a cost equal to the penalty factor, allowing flow 

over a given transmission element to exceed its 

normal limit. 

20See, e.g., Scarcity and Shortage Pricing, Offer 

Mitigation and Offer Price Caps Workshop, Docket 

No. AD14–14–000, Tr. 20:1–21:7 (Oct. 28, 2014). 

21 Id. at 38:19–51:8. 

22 Id. at 40:19–24; 41:7–10; 44:16–23; 46:1–6. 

23 Id. at 48:5–12. 

24 Id. at 47:7–11. 

25See, e.g., the experience of Midcontinent 

System Operator, Inc. and PJM on July 6, 2012 as 

discussed in FERC, Price Formation in Organized 

Wholesale Electricity Markets: Staff Analysis of 

Shortage Pricing, Docket No. AD14–14–000, at 21– 

22 (Oct. 2014), available at http://www.ferc.gov/

legal/staff-reports/2014/AD14-14-pricing-rto-isomarkets.pdf. 

what types of constraints should be 

handled by manual commitments? Of 

those reliability constraints that should 

be in the market models, which 

reliability constraints should RTOs/ISOs 

prioritize? 

b. In 2013, ISO New England Inc. 

(ISO–NE) increased its replacement 

reserve requirement to ‘‘reduce the need 

to schedule additional resources above 

the load and reserve requirements’’ in 

its Reserve Adequacy Analysis.17 PJM 

has a similar proposal to increase dayahead and real-time reserve 

requirements when extreme weather is 

expected.18 In what circumstances can 

such practices improve efficiency of 

price formation? 

c. Do transmission constraint 

relaxation penalty factors improve the 

efficiency of price formation? 19 If so, 

should these penalty factors be allowed 

to set the energy price if a transmission 

constraint is relaxed? 

d. Are there any new constraints that 

represent other physical characteristics 

of the system (with corresponding 

penalty factors), such as N–1–1 

reliability constraints, that could be 

included in the model to improve the 

efficiency of price formation? If so, what 

types of constraints should be included 

and how should the penalty factors be 

determined? 

e. Should RTOs/ISOs create new 

products that procure the capacity 

necessary to address reliability 

constraints that cannot be captured in 

market models? If so, what should these 

products look like, and what process 

should RTOs/ISOs use to design these 

products? 

f. In some cases, creating new 

products to satisfy system needs (e.g., 

ramp capability, local reliability 

product, or additional reserves to 

account for operational uncertainty) 

may amount to procuring a level of 

spinning or non-spinning reserves above 

the mandatory reliability requirement. If 

the ‘‘new product’’ can be satisfied by 

an existing ancillary service product 

(e.g., ten minute reserves), is it 

necessary to create a new and separate 

product with its own price and cooptimization? Rather than developing a 

new product, could RTOs/ISOs change 

the cost allocation of any additional 

ancillary services procured above the 

mandatory reliability requirement? 

9. Shortage Prices 

In the questions below, the term 

‘‘shortage pricing’’ refers generically to 

any pricing action taken in response to 

a shortage event. Not all RTOs/ISOs use 

this phrase in the same way.20 In 

responding to the questions below, 

please define terms and distinguish 

between ‘‘shortage pricing’’ and 

‘‘scarcity pricing,’’ if such a distinction 

is intended. 

a. What principles should be used to 

establish shortage price levels? Should 

there be one price for any shortage or a 

set of escalating prices for greater levels 

of shortage? Is it important to have 

shortage price levels consistent across 

adjacent RTOs/ISOs to avoid seams 

issues? 

b. What are the advantages and 

disadvantages of implementing shortage 

pricing in the day-ahead market as well 

as in the real-time market? If shortage 

pricing is established only in the realtime market but not in the day-ahead 

market, are other policies needed to 

facilitate price convergence between the 

day-ahead and real-time markets during 

periods of shortage? If so, what are these 

other policies? If not, why not? 

10. Transient Shortage Events 

At the Shortage Pricing/Mitigation 

Workshop, panelists stated different 

positions regarding pricing transient, or 

short-duration, shortage events.21

Transient shortage events are shortage 

events that last only a short time, 

perhaps as short as one or two fiveminute dispatch intervals.22 For 

instance, PJM’s market clearing process 

will not invoke shortage pricing if it can 

resolve the shortage within a certain 

time.23 However, even transient 

shortage events need a price signal to 

provide incentives to develop 

capabilities to respond to the shortage.24

a. Should there be a minimum 

duration for a shortage event before it 

triggers shortage pricing? Why or why 

not? How would one determine that 

minimum time, and how does it relate 

to the settlement interval? 

b. Do RTO/ISO rules regarding 

transient shortage events result in 

appropriate price signals? Why or why 

not? To the extent possible, please 

provide empirical evidence supporting 

your answer. 

c. Should treatment of transient 

shortages be consistent across all RTOs/ 

ISOs? Why or why not? 

11. Interchange Uncertainty 

Due to the lag between price signals 

and interchange scheduling for import 

and export transactions, trade between 

RTOs/ISOs can result in volatile prices 

and variable system conditions because 

the ability of importers to schedule 

flows across the seam can lag behind 

actual system needs, creating 

uncertainty in interchange and 

contributing to operational issues.25

Several RTOs/ISOs have instituted new 

rules, such as NYISO’s and PJM’s 

Coordinated Transaction Scheduling 

(CTS), which attempt to better 

coordinate interchange schedules and 

price signals in order to improve interRTO/ISO flows. 

a. What can the RTOs/ISOs do to 

reduce interchange uncertainty? Does 

CTS help to reduce the uncertainty in 

interchange created by the lag between 

price posting and interchange 

schedules? Does the ability to reduce 

uncertainty depend on whether all 

interchange spread bids are 

incorporated into the RTO/ISO dispatch 

model (as proposed for the CTS 

implementation between NYISO and 

ISO–NE) rather than simply allowing 

interchange spread bids on a voluntary 

basis (as proposed for the CTS 

implementation between NYISO and 

PJM)? Are there other steps that should 

be taken to reduce interchange 

uncertainty? 

b. What information do market 

participants need to better respond to 

interchange price signals? 

12. Next Steps 

a. Are there other price formation 

issues that, if addressed, would improve 

energy and ancillary services price 

formation in RTO/ISO markets? What 

are they? 

b. What are the highest-priority price 

formation issues to address? Is the 

priority of issues different in different 

RTO/ISO markets? If so, what are the 

priorities for each RTO/ISO and are the 

RTOs/ISOs currently addressing those 

issues sufficiently? 

[FR Doc. 2015–01139 Filed 1–22–15; 8:45 am] 

BILLING CODE 6717–01–P 


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