Document ID: FERC-2015-0083-0001
Agency: ferc
Document Type: Notice
Title: Post-Technical Workshops
Posted Date: 2015-01-23T05:00Z

[Federal Register Volume 80, Number 15 (Friday, January 23, 2015)]
[Notices]
[Pages 3580-3583]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2015-01139]

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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.

[[Page 3581]]

    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\
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    \1\ Although 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.
    \2\ Other 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/market-planning.asp.
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    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.
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    \3\ See, 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.
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    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?
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    \4\ FERC, 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/staff-reports/2014/08-13-14-uplift.pdf.
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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 block-loaded 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\
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    \5\ FERC, Price Formation in Organized Wholesale Electricity 
Markets: Staff Analysis of Operator-Initiated 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.
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    a. During the Operator Actions Workshop, panelists explained that 
relaxing resource minimum operating limits can lead to incentive and 
operational issues such as over-generation.\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

[[Page 3582]]

resources, or should relaxation be available to a larger set of 
resources?
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    \7\ Operator Actions Workshop, Docket No. AD14-14-000, Tr. 
282:9-25 (Dec. 9, 2014).
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    b. What are the merits of expanding the set of costs included in 
the energy component of LMP (i.e., start-up and no-load 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 start-up 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 sub-hourly, 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\
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    \8\ See 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).
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    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 day-ahead 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.
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    \9\ Operator Actions Workshop, Docket No. AD14-14-000, Tr. 
149:7-11; 151:3-6; 291:6-8 (Dec. 9, 2014).
    \10\ See id. at 291:9-22.
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    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 
short-duration 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?
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    \11\ See, e.g., Cal. Indep. Sys. Operator Corp., 132 FERC ] 
61,087, order on compliance filing, 132 FERC ] 61,273 (2010).
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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\
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    \12\ Scarcity 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.
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    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\
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    \14\ See, 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).
    \15\ See, 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).
    \16\ An 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).
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    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

[[Page 3583]]

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 day-ahead 
and real-time reserve requirements when extreme weather is 
expected.\18\ In what circumstances can such practices improve 
efficiency of price formation?
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    \17\ ISO-NE., Transmittal Letter, Docket No. ER13-1736-000 at 10 
(filed June 20, 2013).
    \18\ PJM Tariff Filing, Docket No. ER15-643-000 (filed December 
17, 2014).
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    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?
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    \19\ Transmission 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.
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    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 co-optimization? 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.
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    \20\ See, 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).
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    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 real-time 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 five-minute 
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\
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    \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.
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    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 inter-RTO/ISO flows.
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    \25\ See, 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-iso-markets.pdf.
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    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