UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Price Formation in Energy and Ancillary)

Services Markets Operated by Regional)Docket No. AD14-14-000

Transmission Organizations and)

Independent System Operators)

POST-TECHNICAL WORKSHOP COMMENTS OF

THE NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.

Pursuant to the Notice Inviting Post-Technical Workshop Comments (“Notice”) and the Notice Granting Extension of Time issued by the Federal Energy Regulatory Commission
(“Commission”) on January 16, 2015 and February 9, 2015, respectively, in the above-
referenced docket, the New York Independent System Operator, Inc. (“NYISO”) hereby submits its Comments in response to the questions posed by the Commission in the Notice. The NYISO shares the Commission’s vision for proper price formation in the wholesale energy and ancillary services markets it administers. The NYISO continually reviews its markets to identify
opportunities to improve long-term market efficiency by ensuring that market prices reflect, to the greatest extent practicable, the cost or value of each product.

I. COMMUNICATIONS AND CORRESPONDENCE

All communications and correspondence concerning these Post-Technical Workshop Comments should be served as follows:

Robert E. Fernandez, General Counsel

Raymond Stalter, Director, Regulatory Affairs Alex M. Schnell, Registered Corporate Counsel *Garrett E. Bissell, Senior Attorney

10 Krey Boulevard

Rensselaer, NY 12144
Tel: (518) 356-6107

Fax: (518) 356-8825

rfernandez@nyiso.com
rstalter@nyiso.com
aschnell@nyiso.com
gbissell@nyiso.com

*Person designated for receipt of service.

II. COMMENTS IN RESPONSE TO COMMISSION QUESTIONS

The NYISO provides the following responses to the questions articulated in the Notice:

1.Offer Caps

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?

NYISO Response:

Offer caps serve several important functions including protecting the marketplace against
the inadvertent submission of offers above the level of the cap and potential exercises of market
power that are otherwise not addressed by existing mitigation rules. Adjustments to the offer cap
level should be carefully evaluated to ensure that consumers will realize reliability and economic
benefits from any proposed change. Changes should be responsive to actual conditions.

The NYISO has not seen evidence of natural gas prices or other fuel prices that would

warrant a need for raising the current $1,000 per MWh offer cap that is applicable to Incremental
Energy and Minimum Generation Bids in New York.1 Last winter, natural gas prices rose to
unprecedented high levels in New York and elsewhere.2 Despite previously unseen gas prices,
no supply resource in New York submitted invoices to the NYISO showing it incurred costs in
excess of $1,000 per MWh or sought recovery of actual costs in excess of the $1,000 per MWh
offer cap.3

1 Capitalized terms not otherwise defined herein shall have the meaning specified in Section 1 of the NYISO Open Access Transmission Tariff (“OATT”) and Section 2 of the NYISO Market
Administration and Control Area Services Tariff (“Services Tariff”).

2 In response to the high natural gas prices and its concern that such prices could potentially reach
levels that would prevent certain supply resources from recouping their actual costs under the current
$1,000 per MWh offer cap, the NYISO requested a temporary waiver to allow it to consider Incremental
Energy and Minimum Generation Bids in excess of $1,000 per MWh and compensate Generators that
were able to demonstrate that they actually incurred variable costs in excess of $1,000 per MWh. The
NYISO requested that such temporary waiver apply from January 22, 2014 through February 28, 2014.
Docket No. ER14-1138-000, New York Independent System Operator, Inc., Petition for Temporary Tariff
Waivers, Request for Shortened Comment Period, and Request for Expedited Commission Action by
January 31, 2014 (January 22, 2014). In granting the NYISO’s temporary waiver request, the
Commission directed the NYISO to submit an informational filing by March 28, 2014 to, among other
matters, provide the total amount of energy that qualified to receive compensation for costs in excess of
$1,000 per MWh during period in which the temporary waiver was in effect. New York Independent
System Operator, Inc., 146 FERC ¶ 61,061 at P 24 (2014).

3 Docket No. ER14-1138-000, supra, Bid Restriction Waiver Informational Filing (March 28,

2014).

Notwithstanding the sustained cold weather conditions that have occurred this winter the
NYISO has not identified any natural gas or other fuel prices during winter 2014-2015 that
warrant increasing the current offer cap level. February 2015 was the coldest February on record
in New York City since 1885.4 Despite the sustained frigid conditions, the highest natural gas
prices experienced in New York City during winter 2014-2015 have been less than $60 per
MMBtu - approximately 50 percent lower than the highest prices experienced during last
winter.5

Although the NYISO has not seen evidence to date that would warrant any changes to the offer cap level in New York, the NYISO supports the coordinated inter-regional implementation of comparable offer caps in order to limit potential seams issues between neighboring regions, protect reliability, and avoid inefficient market outcomes. Offer caps must be discussed at an
inter-regional level in order for all interested parties to evaluate the potential for seams issues
and other impacts that could arise from having different offer caps apply in markets that have
access to an overlapping set of resources.

Electric markets in the Mid-Atlantic and Northeast compete for a common supply of
natural gas. Generators located in regions that are subject to lower offer caps could be denied
access to fuel. Enacting materially different offer caps in regions that depend on the same

4 Reuters, As New England Freezes, Natural Gas Stays Cheap (March 1, 2015) available at:
http://www.reuters.com/article/2015/03/02/energy-natgas-newengland-idUSL1N0W12U220150302.

5 Although the NYISO does not anticipate natural gas or other fuel costs will reach levels that

would result in supply resources incurring costs in excess of the currently effective $1,000 per MWh offer cap, the NYISO is willing to further consider with its stakeholders whether inclusion of a “backstop”
mechanism in its tariffs to provide suppliers with the assurance of cost-recovery in the event that
unprecedented fuel cost price spikes were to occur in the future is warranted. Utilization of any fixed offer cap level presents the potential, however remote, for variable costs to exceed the level of the cap. A “backstop” mechanism providing supply resources assurance of the ability to recover legitimate costs incurred may be helpful regardless of the level of the offer cap.

natural gas supply could require operator actions to avoid electric system reliability impacts during periods of cold weather and high gas prices. Inter-regional or national coordination to establish appropriate offer caps (or to modify existing offer caps) is essential to ensure that
generators in all electric markets enjoy equivalent access to fuel. If changes to offer caps are not coordinated, offer cap driven market outcomes could result in natural gas supply flowing to the supply resources in the region with the highest offer cap instead of directing scarce fuel supplies to the resources that can use the available fuel to serve load most efficiently.

2. Transparency

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. What steps could be taken to improve the quality of uplift
data required to be reported as part of the Electric Quarterly Reports?

NYISO Response:

The NYISO strives to provide a high degree of transparency regarding its market

outcomes, including uplift costs, while balancing the need to protect confidential information. The NYISO makes publicly available a host of information to assist Market Participants and the public in understanding the amount and underlying causes/categorization of uplift costs in New York’s wholesale energy markets.

The NYISO produces monthly operations performance metrics reports that contain detailed information on uplift costs in New York.6 The NYISO’s monthly operations performance metrics reports contain the following information:

• monthly total statewide uplift costs and the monthly rate (stated in $ per MWh)
associated therewith;

• the categorization of statewide uplift costs as balancing congestion residual costs, which
result from differences between the Day-Ahead and Real-Time markets, or make-whole
payments to supply resources;

• detailed breakdowns of the balancing congestion residual component to provide

categorization of such costs on a monthly and daily basis, including a root cause analysis to identify the underlying reason for the congestion residuals. Causes that are identified in the monthly report include unscheduled transmission outages, derates to the transfer
limits of internal or external interfaces and increases to unscheduled clockwise loopflow around Lake Erie; and

• additional detail and categorization of monthly and daily make-whole payments to supply
resources identifying the statewide and local allocation of such costs, as well as detailed
regional information regarding the Generators committed out-of-market pursuant to the
NYISO’s Day-Ahead Reliability Unit (“DARU”) and Supplemental Resource Evaluation
(“SRE”) commitment processes and the total hours each month during which such units
were committed pursuant to DARU and SRE procedures.

These reports are posted publicly for review on the NYISO’s website and are discussed with Market Participants during several monthly stakeholder meetings.7 Discussion during
stakeholder meetings is designed to provide all interested parties the opportunity to review the data available and ask questions to better understand market outcomes or trends that may be developing with respect to certain cost categories.

6 For example, the information included in its monthly operations performance metrics reports for January 2015 is posted on the NYISO’s website at the following location:

http://www.nyiso.com/public/webdocs/markets_operations/documents/Studies_and_Reports/Reports/Mo
nthly_Reports/2015/Board%20Monthly%20Report%20January%202015.pdf.

7 In addition to the NYISO’s monthly reports that serve as an aggregation of data throughout each
month, the NYISO posts information to its website on a daily basis to inform all interested parties of out-
of-market commitments of supply resources, including the type of commitment and the resource
committed.

In addition to the NYISO’s monthly reports, uplift costs, root causes and the impacts of
operator action thereon are reviewed in detail as part of the quarterly and annual reports prepared
by Potomac Economics, the NYISO’s external Market Monitoring Unit (“MMU”). The MMU’s
reports address statewide and regional uplift costs, including the impact out-of-market resource
commitments have on uplift costs. The reports include a detailed analysis of the causes of make-
whole guarantee payments to supply resources. The MMU includes recommendations on market
enhancements that may warrant consideration by the NYISO to improve market efficiency by

incorporating causes of uplift into the NYISO’s economic commitment and dispatch.

Over time, the NYISO has revised and enhanced its data reporting and the format in
which such information is presented based on feedback from interested parties and its own
internal review. Such enhancements are aimed at improving clarity and making data and
information more readily accessible and easily comprehensible. The NYISO continually seeks opportunities to enhance its information reporting to improve transparency and enhance
understanding of market outcomes by all interested parties, while maintaining the confidentiality of commercially sensitive information.

3. Pricing Fast-Start Resources

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. 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 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 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?

NYISO Response:

Pricing outcomes should, to the maximum extent practicable, align with the physical

dispatch that resources are instructed to follow. The hybrid pricing rules NYISO implemented in 2001 (“Hybrid Pricing”) are designed to align physical schedules with efficient pricing to the maximum extent possible.8

Relaxation of the minimum operating limits of fast-start, block-loaded resources for purposes of price setting can produce incongruous results when relaxation allows the ideal
pricing dispatch to diverge significantly from the physical dispatch.9 Divergence between the ideal and physical dispatches can result in distorted price signals to resources that are not blockloaded. This is particularly true of the price signals sent to flexible resources that are backed down to accommodate the dispatch of a block-loaded resource.

Block loaded resources would not ordinarily be included in price setting, absent special
treatment, because they cannot flexibly provide only the next incremental MW needed by the
system. The NYISO’s Hybrid Pricing addresses this limitation by relaxing the minimum
operating limits of certain fast-start, block-loaded resources in order to permit these resources to
be eligible to set price based on the incremental need that required a resource’s commitment.
The NYISO’s Hybrid Pricing also ensures that block-loaded resources are ineligible to set price

8 See New York Independent System Operator, Inc., 95 FERC ¶ 61,121 (2001). The NYISO’s

Hybrid Pricing applies to Real-Time Market pricing. For the purposes of the Day-Ahead Market, blockloaded resources are treated as flexible (i.e., treating the resource as if it could be dispatched at any level between zero and the resource’s maximum capability) and, thus, eligible to set pricing to the extent they are economically committed to serve load.

9 The physical dispatch accounts for the physical characteristics and operating parameters of supply resources.

in those intervals in which they are not economic to commit but are otherwise blocked on in
order to complete their minimum run time (which is typically one hour).10
The Hybrid Pricing rules also permit offline 10-minute start-up gas turbines that are not committed by the NYISO’s Real-Time Commitment (“RTC”) software, but are available for dispatch in real-time, to set prices under certain circumstances.11 Offline 10-minute gas turbines are eligible to set price in real-time when they are committed by RTD for all intervals of a given RTD run and are economic to serve load for at least the first three five-minute intervals of the RTD run at issue.12

By allowing block-loaded resources to be eligible to set price when they are economic to
serve load, the Hybrid Pricing rules improve pricing transparency and allow resources to be
compensated based on pricing that more accurately reflects the NYISO’s least-cost solution to
serve load. The pricing signals produced by the NYISO’s Hybrid Pricing provide appropriate
incentives to available resources, including: (i) incenting the scheduling of import transactions

10 The NYISO’s Real-Time Dispatch (“RTD”) system involves a multi-pass process. The first
pass treats committed block-loaded resources as blocked on at their applicable maximum capability. In
contrast, the second pass treats committed block-loaded resources that are still within their minimum run
time as flexible in order to determine whether such resources are economic to serve load. Block-loaded
resources that are determined to be economic to serve load in the second pass may be eligible to set prices
in the third pass. Block-loaded resources that are not found to be economic in the second pass are not

eligible to set price.

11 See Docket No. ER05-1123-000, New York Independent System Operator, Inc., Proposed Tariff
Revisions to Remedy Real-Time Market Price Volatility Attributable to Forecasting Uncertainties and
Request for Expedited Treatment (June 17, 2005); and New York Independent System Operator, Inc., 112
FERC ¶ 61,075 (2005). Resources eligible for consideration under such rules are offline generators that:

(i) are capable of starting with ten minutes; (ii) have satisfied any applicable minimum downtime

requirements; and (iii) have not otherwise been committed by RTC or RTD-Corrective Action Mode (“RTD-CAM”).

12 The RTD optimization looks ahead approximately 60 minutes on a five minute interval basis. In evaluating an eligible offline resource, RTD considers both the start-up and incremental energy costs of such resource to ensure the system conducts a sound commitment-related analysis. The Hybrid Pricing rules are designed to allow RTD to commit offline quick-start gas turbines for pricing purposes when
such commitment represents the least cost option to meet real-time system conditions.

when imports are less expensive than internal generation; and (ii) incenting price-responsive load
to reduce demand during high priced periods. By excluding block-loaded resources from price
setting when they must be kept on to complete their minimum run time but are no longer
economic to meet real-time load, the Hybrid Pricing rules appropriately reflect the existence of
excess, inflexible capacity on the system. During such periods, it is appropriate for prices to be
lowered, thereby discouraging additional imports and providing an appropriate price signal to
internal generation.

The NYISO does not see a need to extend its Hybrid Pricing to resources other than faststart block-loaded resources.13 The NYISO’s RTC uses a look-ahead functionality to optimize Energy, Regulation Service and Operating Reserves commitments over the next ten 15 minute increments (150 minutes). Such look-ahead capability allows RTC to determine when additional flexibility will be needed on the system and to commit resources or modify interchange
schedules to provide any needed flexibility.

Inclusion of start-up and no-load costs in prices could result in more explicitly

recognizing the costs a resource incurs to supply energy and potentially reduce uplift costs at times when LBMPs are inadequate to cover minimum generation and start-up costs. However, the NYISO is concerned that expanding the set of costs included in the energy component of the NYISO’s Locational Based Marginal Pricing (“LBMP”) to always include start-up and no-load costs could undermine market efficiency.

Embedding start-up costs in the interval in which a resource is started could produce

inaccurate price signals during such periods, especially when the resource that is starting up has a

13 The NYISO, however, continues to evaluate whether: (i) revisions to its current Hybrid Pricing rules are warranted in order to allow for increased price setting eligibility for fast-start block loaded
resources; and (ii) any such revisions, if further pursued, would result in more efficient pricing.

long start-up or minimum run time requirement. Resources with long start-up or minimum run time requirements may be started during off-peak hours in order to allow sufficient time for such resources to ramp up for peak hours. If units are ramping up or operating at minimum generation levels during off-peak hours and start-up costs are reflected in the energy component of LBMP during those hours, energy prices may be artificially inflated during off-peak hours.

During off-peak periods when a significant amount of resources may be operating at

minimum generation levels to be available to ramp up to serve peak loads later in the day,

LBMPs should be low to signal the availability of low-cost exports to neighboring regions and to discourage imports to New York (which could exacerbate system excess conditions). Inclusion of start-up and no-load costs in LBMPs during the period when resources with long start-up or minimum run time requirements are started could produce artificially high prices during the offpeak hours. Setting artificially high off-peak LBMPs could inaccurately portray system
conditions and incentivize inefficient market responses.14

Start-up costs also vary greatly among resources and are incurred intermittently. Inclusion of such costs in LBMP, therefore, could produce inconsistent price signals and undermine the ability of pricing to provide longer-term signals.

14 The NYISO’s Hybrid Pricing rules account for start-up costs of offline fast-start resources
when such resources are committed and economic to serve load in real-time. The Hybrid Pricing rules
apply to fast-start resources in the Real-Time Market. Such resources have short minimum run times and
the time period over which start-up costs should be allocated are readily discernible, thereby avoiding the
aforementioned problems associated with resources that have long minimum run time requirements.
Consideration of start-up costs for offline fast-start resources is consistent with the approach
recommended by Potomac Economics. See Docket No. AD14-14-000, Price Formation in Energy and
Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System
Operators, Post-Technical Workshop Comments of Potomac Economics, Ltd. at 9 (February 24, 2015)
(hereinafter referred to as the “Potomac Economics Price Formation Comments”).

4. Settlement Intervals

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?

NYISO Response:

Since its inception, the NYISO has utilized sub-hourly settlements in its Real-Time

Market.15 The use of sub-hourly settlements appropriately links compensation with performance thereby incenting resources to not deviate from their dispatch instructions. Incenting resources to conform to dispatch instructions improves system operations and reliability.

Sub-hourly settlements in the Real-Time Market incentivize conformance with NYISO-
issued dispatch instructions. The use of sub-hourly settlements also provides supply resources
the opportunity to receive full compensation for their performance and responding to real-time
prices. The NYISO’s sub-hourly real-time pricing accurately and transparently reflects the value
of providing specific services in response to actual system conditions. Compensation should,
therefore, appropriately reflect resource performance in response to such price signals.
Sub-hourly settlements also reduce the potential for over-compensation to suppliers as a result of providing services during an hour with very high prices in only a few intervals that
result in an artificially inflated average hourly price. Sub-hourly settlements do not provide

15 Real-Time Market settlements for Energy, Regulation Service and Operating Reserves are

consistent dispatch intervals used by RTD, which are generally five minutes, except during RTD-CAM
activation when intervals may be shorter or longer than five minutes depending on system conditions.

artificial incentives to over-supply when a few transient price spikes occur during a settlement hour, resulting in an artificially inflated average hourly price.

The use of sub-hourly settlements also provides incentives for investment in supply

technologies that can quickly respond to changes in real-time prices. Increased rapid response
capability increases flexibility and can provide reliability and economic benefits to the system.
Settlement intervals should align with pricing and scheduling intervals to provide the proper incentives to supply resources. The NYISO does not utilize sub-hourly settlements in its Day-Ahead Market because the NYISO has aligned day-ahead commitment scheduling and
settlement periodicity. Because the NYISO provides hourly commitment schedules in its Day-
Ahead Market, it likewise settles its Day-Ahead Market on an hourly basis.
To realize the potential benefits (if any) of sub-hourly settlements in its Day-Ahead
Market (such as the potential for improved day-ahead and real-time price convergence,
interchanges schedules, and more consistent resource self-scheduling) would require the NYISO
to implement day-ahead sub-hourly commitment scheduling as well. Implementing such
capability would require significant software changes. The NYISO has concerns that
implementing sub-hourly commitment scheduling in its Day-Ahead Market could significantly
increase the computational time necessary to produce and post Day-Ahead Market results.
Delayed posting of Day-Ahead Market results could have adverse impacts. For example, it
could reduce the time available for generators that receive day-ahead commitments to procure
the necessary fuel to meet such schedules.16 Such implications must be considered in any further
assessment of pursuing sub-hourly commitment scheduling in the Day-Ahead Market.

16 See Docket No. AD14-8-000 et al., Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations and Independent System Operators, Post-Technical Conference Report of the New York Independent System Operator, Inc. at 8-9 (February 18, 2015).

5. New Products to Incent 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 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? What are
the advantages and disadvantages to generators of bidding these configurations?

NYISO Response:

The NYISO’s market design includes various components that collectively ensure that
sufficient flexibility exists on its system. Market design features that ensure adequate flexibility
include: (i) a reliability pass in the NYISO’s Security Constrained Unit Commitment (“SCUC”)
software used for the Day-Ahead Market; (ii) look-ahead functionality in the NYISO’s RTC and
RTD systems; (iii) utilization of sub-hourly settlements in real-time; and (iv) procurement of
Operating Reserves day-ahead. The NYISO has not experienced a lack of sufficient flexibility
or fast start capability.

The NYISO’s SCUC includes a reliability pass to ensure that sufficient supply resources are committed day-ahead to meet forecasted load. The reliability pass commits any additional supply resources needed to make up any difference between the load bid into the Day-Ahead Market and the NYISO’s forecasted load requirements. This functionality has significantly reduced out-of-market actions taken in real-time.

The NYISO’s RTC and RTD systems incorporate look-ahead capabilities that help

ensure that sufficient flexibility exists to meet real-time system conditions. RTC optimizes

resource commitments over a 2.5 hour period utilizing 15 minute increments. This functionality allows the software to assess whether additional flexibility on the system will be required and
commit the resources necessary to provide such flexibility.17 RTD optimizes resource dispatch in five minute intervals over a period of approximately one hour. RTD’s forward looking
capability helps the software to recognize and dispatch resources in a manner consistent with
real-time system conditions.18

As explained in the response to Question No. 4, the NYISO’s use of sub-hourly

settlements helps to further ensure that sufficient flexibility exists on the system. The use of subhourly settlements provides incentives for investment in supply technologies that can quickly
respond to changes in real-time prices and obtain compensation based on such prices. Sub-
hourly settlements also incent resource performance and conformance with NYISO issued
dispatch instructions.19

The use of sub-hourly settlements minimizes the need for creating a separate ramping
product. Sub-hourly settlements provide incentives for resource flexibility and fast response
capability arising therefrom. The NYISO’s co-optimization of Energy and Ancillary Services
and the forward looking capabilities of RTC and RTD ensure that the system commits and

17 The use of 15 minute schedules produced by RTC, which includes schedules for interchange transactions with several neighboring regions, provides additional flexibility by allowing the system to respond more readily and adjust resource commitments (including external transaction schedules) based on real-time system conditions.

18 As described in the NYISO’s response to Question No. 3, RTD can commit offline fast-start resources if doing so would be economic to serve load during the optimization horizon.

19 Supply resources are further incented to bid flexibly because flexible-bid resources are eligible
for make-whole guarantee payments to ensure that such resources recoup their costs for providing energy.

dispatches adequate resources to meet the flexibility requirements of the system. The value of products is appropriately based on such commitment and dispatch decisions. These market design features obviate the need to engage in incremental commitments for certain capabilities, such as ramping and quick response capabilities.

The NYISO procures Operating Reserves in both its Day-Ahead and Real-Time Markets. By procuring Operating Reserves day-ahead, supply resources are incented to make fuel supply and other arrangements to ensure availability to meet their day-ahead commitments in real-time and be capable of responding to real-time system conditions.

The NYISO has worked with Market Participants to adjust its systems to provide

mechanisms to better facilitate efficient participation of combine-cycle natural gas resources in
the Real-Time Market.20 In 2009, the NYISO implemented revisions to its RTC software to
better accommodate the physical characteristics of combined-cycle gas turbines (“CCGTs”),
resulting in more efficient real-time dispatch of such resources.21 Specifically, RTC was
adjusted to allow CCGTs to utilize a two hour minimum run time, rather than the one hour
minimum run time typically evaluated by RTC. Use of a two hour minimum run time for some
CCGTs is appropriate to reduce wear and tear on equipment. Permitting a two hour minimum
run time allows the unit owner to more realistically price its energy offer, thereby allowing the
real-time dispatch software to better match the physical operating characteristics of CCGT
equipment with a unit’s economic value to the market. Prior to this revision, CCGTs desiring to
offer in the Real-Time Market were required to incorporate the costs of running for the required

20 See, e.g., Docket No. ER04-230-000 et al., New York Independent System Operator Inc.,
Eighteenth Quarterly Report by New York Independent System Operator, Inc. (May 28, 2009).

21 See Docket No. ER09-1596-000, New York Independent System Operator, Inc., Proposed Tariff Revisions to Address Real Time Modeling of Combined Cycle Units (August 17, 2009); and Docket No. ER09-1596-000, supra, Letter Order (September 24, 2009).

two-hour period into their offer for the first hour and then bid as a price taker for the second hour. This bidding construct distorted RTC’s evaluation of the economics of committing the resource because the resource appeared artificially uneconomic in the first hour.22

6. Operating Reserve Zones

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?

NYISO Response:

The NYISO utilizes operating reserve constraints that reflect reliability requirements and transmission constraints to meet N-1-1 transmission operations for two regions - East of CentralEast and Long Island. As further explained below, the NYISO has proposed the addition of a
new operating reserve region - southeastern New York (i.e., Load Zones G, H, I, J and K) - to address N-1-1 system needs.

The establishment and utilization of operating reserve zones is akin to locational pricing
of energy. Properly designed reserve zones, together with co-optimization of Energy and
Ancillary Services, can reflect reliability requirements, improve market outcomes, increase
market efficiency and better aligning pricing with the needs of the system and actions taken by
operators. The increased granularity associated with the utilization of reserve zones provides
signals to the market regarding the relative value of various reserve products across different
geographic regions. In the longer-term, operating reserve zones help to induce investment in
resources located within the areas where they are needed most from a system reliability

22 In proposing to implement this change, the NYISO estimated that such improved modeling of CCGTs could result in real-time energy production cost savings of at least $8 million per year.

perspective. Reserve zones also appropriately consider the implications of transmission

constraints that may limit the deliverability of reserves in one area to meet system needs in other
areas.

Triggers for consideration of whether to establish or reconfigure reserve zones should

include: (i) the presence and frequency of transmission constraints; (ii) the deliverability of

reserves held in a given location to the rest of the system; and (iii) assessment of operator actions
which may be specific to maintaining reliability in a particular zone or area.
The NYISO has identified a need to implement a new reserve region in New York.
Implementing a new reserve zone will improve market efficiency and better align the
procurement of operating reserves with the needs of the system and maintaining the reliable
operation thereof. As part of its Comprehensive Shortage Pricing project, the NYISO recently
filed for Commission approval to: (i) implement an additional reserve region encompassing
southeastern New York; (ii) revise its currently effective shortage pricing levels to better reflect
resource costs and ensure continued comparability with shortage pricing in neighboring regions;
and (iii) place limitations on the contribution of reserves held on Long Island to the rest of New
York in light of certain transmission constraints that limit the flow of energy off Long Island.23
Subject to Commission approval, the NYISO intends to implement these enhancements during
winter 2015-2016.

The NYISO continually reviews its markets to identify potential opportunities for
enhancement, as well as the need for potential adjustments over time that may result from
changes in system topology and the resource mix in New York. The MMU also provides

23 See Docket No. ER15-1061-000, New York Independent System Operator, Inc., Proposed Tariff Revisions to Ancillary Service Demand Curves and the Transmission Shortage Cost (February 18, 2015) (hereinafter referred to as the “Comprehensive Shortage Pricing Filing”).

quarterly and annual reviews of market outcomes and develops recommendations for certain market rule changes or enhancements based on its ongoing reviews. As demonstrated by the NYISO’s recent Comprehensive Shortage Pricing project filing, ongoing review by the NYISO and its MMU produce actionable market rule revisions and reforms that the NYISO pursues through its stakeholder shared governance process.24

7. Uplift Allocation

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?

NYISO Response:

The NYISO differentiates and categorizes uplift costs based on the underlying cause for
such costs.25 In doing so, the NYISO identifies whether such uplift costs are attributable to
actions by the NYISO to ensure statewide reliability or to address local reliability at the request
of a Transmission Owner. Such categorization is undertaken for the purpose of cost allocation.
The NYISO allocates uplift costs consistent with “beneficiaries pay” principles (i.e.,
those receiving the benefits of a given action ultimately bear its costs). Uplift payments to
ensure statewide reliability are allocated to all loads in the New York Control Area, while uplift
costs associated with local reliability issues are allocated only to the load within the transmission

24 Id.

25 As further described in its response to Question No. 2, the NYISO provides regular reporting to its Market Participants and the public to detail the categorization of various uplift costs.

district for which the local reliability actions were taken.26 Costs are allocated to the applicable loads proportionately on a load-ratio share basis, based on the actual real-time metered loads, during the hours in which such uplift costs are incurred.

8. Market and Modeling Enhancements

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 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?

NYISO Response:

The NYISO seeks to model as many constraints as practical in its market models. The NYISO modeling already includes certain N-1-1 constraints, including local N-1-1 thermal
requirements in New York City. The NYISO also models certain voltage constraints that can be solved by a defined set of resources.27

The NYISO reviews market outcomes to identify potential opportunities for modeling enhancements to improve market efficiency. Since 2008, the NYISO has conducted internal daily reviews of the prior day’s market outcomes. Such reviews include evaluation and
assessment of uplift costs to evaluate whether potential modeling changes are needed to more efficiently respond to causes of uplift.

26 The NYISO’s existing uplift allocation procedures are consistent with the recommendations of Potomac Economics in that the NYISO categorizes uplift costs based on the underlying cause and then
allocates costs accordingly based on cost causation principles. See Potomac Economics Price Formation Comments at 16-18.

27 Other voltage constraints that can be solved in multiple ways (e.g., implementation of local control actions on the lower voltage system that would alleviate the need to commit a resource) are not included in the NYISO’s market model.

The NYISO continually seeks to improve its modeling and, where warranted, incorporate additional constraints to be solved.28 In assessing whether to model additional constraints, the NYISO considers multiple factors, including:

• whether the NYISO can effective develop the constraint in its market model. For

example, if local control actions can be taken on the lower voltage system that would alleviate the need to commit a resource, it may not be appropriate or necessary for the NYISO to include such constraint in its commitment and dispatch models;

• if a particular constraint is non-thermal (e.g., voltage needs), whether the NYISO can

model such non-thermal constraint or develop an appropriate proxy thermal constraint;

• whether multiple supply resources can solve the constraint and, if not, whether modeling

such a constraint would give rise to market power concerns or the need for additional mitigation measures to effectively guard against such market power concerns;

•frequency with which the constraint at issue materializes; and

•the magnitude of uplift costs associated with the constraint at issue.

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. PJM has a similar proposal to increase day-ahead and real-time reserve requirements when
extreme weather is expected. In what circumstances can such practices improve efficiency of price formation?

NYISO Response:

Increasing overall reserve requirements to meet system needs and refinement of reserves
procurement through the establishment of reserve zones, where appropriate, can improve market
efficiency and reduce out-of-market actions and uplift costs associated therewith. The NYISO
prefers to procure a consistent amount of reserves each day, rather than procuring incremental

28 The NYISO also considers recommendations from the MMU. As a single example from a

multitude of modeling enhancements over the years, in 2012, in response to changes in resource mix and
system topology, the NYISO implemented additional modeling of certain 230 kV constraints in Load
Zone A in both the Day-Ahead and Real-Time Markets. The modeling enhancements were intended to
reduce uplift costs by minimizing out-of-market action by operators to secure the modeled transmission
constraints.

reserves only during defined periods or only in certain circumstances. Procuring a consistent

amount of reserves each day and including such procurement in the Day-Ahead Market solution produces a more efficient and lower cost of procurement over the long-term. Day-ahead
procurement relies on a larger pool of resources to provide the needed service, thereby providing opportunities to lower the cost of such procurement. Procuring additional reserves only under
conditions that are identified closer in time to the potential for an actual shortage to occur is
likely to produce a much smaller set of resources that can meet the reliability need and could
result in higher procurement costs.

If appropriately implemented, procuring additional reserves each day will result in their value being low during non-critical periods due to the large pool of resources available to
provide the service. During critical periods, when reserves are needed most and the likelihood of actual shortage conditions increases, the price of reserves should likewise increase, providing
efficient signals to the market.

Consistent procurement also provides appropriate price signals to ensure that the

capability to provide the required service will be available when it is needed most. Day-ahead
procurement encourages resources to make necessary fuel supply and other arrangements to
perform and be available in real-time in order to avoid the risk of buying out of their day-ahead
positions at potentially high real-time prices when their services are needed most. Incentivizing
resources to perform consistent with their day-ahead commitments reduces deviations between
day-ahead and real-time schedules and increases stability in real-time operations.

c. Do transmission constraint relaxation penalty factors improve the efficiency of
price formation? If so, should these penalty factors be allowed to set the energy
price if a transmission constraint is relaxed?

NYISO Response:

In 2007, the NYISO implemented a transmission shortage cost of $4,000 per MW to

resolve transmission constraints.29 As discussed in its response to Question No. 10, the NYISO plans to revise its current Transmission Shortage Cost later this year through implementation of its recently-approved graduated transmission demand curve.30 Implementation of a graduated transmission demand curve will further improve the efficiency of resolving transmission
constraints by reflecting an escalating cost associated with increasing levels of shortage in
securing the transmission system.

The use of transmission shortage costs (or relaxation penalty factors) improves market

efficiency. Transmission shortage costs reflect the cost of securing the transmission system. Use of transmission shortage costs also reduce the likelihood of inefficient dispatch in response to relieving a constraint and facilitate the ability of the commitment and dispatch software to
identify the most economic solution to resolve the constraint.

Relaxation of a transmission constraint without applying an appropriate shortage cost

produces energy prices that fail to accurately reflect system needs and costs. Relaxation without

29 See Docket no. ER07-720-000, New York Independent System Operator, Inc., Revisions to its
Market Administration and Control Area Services Tariff and its Open Access Transmission Tariff to
Apply an Upper Limit on Transmission Shortage Costs Reflected in Locational Based Marginal Prices
(April 5, 2007); New York Independent System Operator, Inc., 119 FERC ¶ 61,237 (2007); and Docket
No. ER07-720-000 et al., supra, Letter Order (January 11, 2008). Prior to 2007, the NYISO’s
commitment and dispatch software included a transmission shortage cost that represented a multiplier of
the highest energy supplier’s offer. The NYISO, however, determined that this prior transmission
shortage cost was too high and, at times, could result in inefficient dispatch solutions.

30 See Docket No. ER15-485-000, New York Independent System Operator, Inc., Proposed Tariff Amendments to Revise Transmission Shortage Costs (November 25, 2014); and Docket No. ER15-485-
000, supra, Letter Order (January 15, 2015).

applying a shortage cost may also produce artificially low prices during the intervals in which

the constraint is relaxed. The resulting artificially low prices may provide inaccurate signals that incent exports and reduce internal supply at a time when retention of supply may be critically important to maintaining system reliability.

Notably, however, setting transmission shortage costs at artificially high values could result in inefficient dispatch. Shortage cost values should be set consistent with the anticipated costs to meet transmission constraints. In establishing its $4,000 per MW transmission shortage cost value, as well as the pricing points for its recently-approved graduated transmission demand curve, the NYISO examined historic costs to resolve transmission constraints and set its
transmission shortage costs in line with the results of its analysis.31

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?

NYISO Response:

As further described in the response to subpart (a) of Question No. 8, the NYISO’s

commitment and dispatch models already include certain constraints that reflect N-1-1

contingencies. The response to subpart (a) of Question No. 8 also explains that the NYISO has existing processes in place by which it continually reviews market outcomes to determine whether modeling of additional constraints may be warranted and feasible.

31 See Docket no. ER07-720-000, supra, Revisions to its Market Administration and Control Area
Services Tariff and its Open Access Transmission Tariff to Apply an Upper Limit on Transmission
Shortage Costs Reflected in Locational Based Marginal Prices at 4-5 (April 5, 2007); and Docket No.
ER15-485-000, supra, Proposed Tariff Amendments to Revise Transmission Shortage Costs at 8-9
(November 25, 2014).

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?

NYISO Response:

Each RTO/ISO has its own load patterns, resource mix, set of system conditions and

reliability rules that must be satisfied, resulting in different reliability challenges, system needs
and operating constraints. What may be an appropriate response to a given need in one region
may not be workable or appropriate for another region. Each RTO/ISO must develop means to
address the reliability constraints it faces in a manner that appropriately accounts for its system
topology, resource portfolio and the options that may be available to meet system needs.

The NYISO has existing processes in place, including collaboration with Market

Participants through its stakeholder shared governance process, to continually review system needs and develop effective solutions.32

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 nonspinning 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?

NYISO Response:

As further described in its responses to Question Nos. 6 and 9, as part of its

Comprehensive Shortage Pricing project, the NYISO undertook a comprehensive review of

32 The NYISO’s Comprehensive Shortage Pricing project, as described in the responses to

Question Nos. 6 and 9, is a solution developed for addressing certain reliability constraints through the market using reserve products.

reserves constraints to address reliability needs. This effort highlighted the importance of

locational reserve requirements to ensure proper distribution of reserves across the system. The
development of new products may not always be necessary to address system needs. Instead,
modifications or improvements to an existing product, such as the NYISO’s creation of
additional reserve zones, may provide a more efficient means of addressing identified needs.
Additionally, as noted in its response to subpart (a) of Question No. 8, the NYISO
already manages certain local reliability requirements in its market solution. In such cases, the
NYISO has developed cost allocation methods to ensure that the costs for resolving local needs
are allocated only to load within the transmission district for which the local reliability actions
were taken.

9. Shortage Prices

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?

NYISO Response:

The NYISO uses “shortage pricing” to reflect the gradually increasing value of Operating
Reserves, Regulation Service and transmission security as the system becomes more constrained.
“Scarcity pricing” refers to the manner in which the NYISO seeks to ensure that real-time prices
reflect the value of demand response resources when called upon to maintain adequate reserve
levels. Consistency needs to be maintained between the NYISO’s shortage and scarcity pricing

mechanisms to ensure that shortage pricing accurately accounts for the scarcity pricing levels
that result from utilizing demand response resources to maintain reserves.
The NYISO implements shortage pricing in both its Day-Ahead and Real-Time Markets utilizing various demand curves for Operating Reserves (i.e., Operating Reserve Demand
Curves), Regulation Service (i.e., Regulation Service Demand Curve) and transmission security (i.e., Transmission Shortage Cost). These demand curves represent the escalating value of each product as the level of any shortage thereof increases. The NYISO has utilized demand curves for shortage pricing since 2005.33

Shortage pricing levels should be based on the expected costs associated with operator action that could be taken in real-time to maintain reliability and avoid shortage conditions.
Shortage pricing levels should consider the offer prices of resources that may be committed to resolve shortage conditions (including fast-start resources and demand response).34 Shortage pricing design should also include escalating prices as the level of a given shortage increases. Escalating prices allow the NYISO’s commitment and dispatch software to determine the most economic solutions to resolve different levels of product shortages.35 Escalating pricing also provides signals to incent greater flexibility on the system by rewarding resources that are
capable of responding to real-time system conditions.

33 See Docket No. ER04-230-000, New York Independent System Operator, Inc., Tariff Revisions Reflecting Implementation of Enhanced Real-Time Scheduling Software (November 26, 2003); and New York State Independent System Operator, Inc., 106 FERC ¶ 61,111 (2004).

34 As part of its recently-filed Comprehensive Shortage Pricing project, the NYISO proposed to revise its shortage pricing levels to better reflect recent incremental energy and start-up cost bids of
generators in New York that are eligible to provide 30-minute reserves. See Comprehensive Shortage
Pricing Filing at 7.

35 The use of escalating prices provides greater leeway in making dispatch decisions allowing for tradeoffs between committing resources to provide Energy or Ancillary Services, as well as permitting
shortages of lesser value (and thus less expensive) reserves if necessary to maintain higher value (and thus more expensive) reserves.

The establishment of appropriate shortage pricing levels should be coordinated to ensure
comparability between neighboring regions. Comparability of shortage pricing between
neighboring regions helps ensure that when the region as a whole is in shortage conditions,
energy is not flowing out of one region and to a neighboring region as a result of higher shortage
prices being assigned to reflect similar or less critical shortage conditions in the neighboring
area.

The NYISO’s shortage pricing applies in both the Day-Ahead and Real-Time Markets. Implementing the same rules in both markets: (i) improves price convergence; (ii) provides
supply resources the same incentives to provide Ancillary Services in each market; and (iii) provides supply resources that are committed to provide reserves day-ahead appropriate
incentives to be prepared to meet their day-ahead commitments in order to avoid the potential of having to buy-out of their obligation at high shortage pricing levels in real-time.

10. Transient Shortage Events

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?

NYISO Response:

All shortages regardless of the length of time that they persist should be priced. The duration of shortages should, to the extent practicable, be considered in establishing the
appropriate price.

Transient shortage events are indicative of actual system conditions and needs. It is
important to price such events and recognize the actual costs associated with the underlying

shortage. Pricing transient shortages provides incentives to supply resources that have the

capability to respond to short-duration events to be available. Incenting the availability of fast response resources provides additional flexibility to the system, thereby improving the ability of the system to respond to real-time conditions.

The NYISO seeks to properly balance pricing with event duration through the use of

escalating prices for shortages and sub-hourly settlement intervals. The use of escalating prices results in smaller magnitude shortage events being priced at lower levels than larger magnitude shortages, while simultaneously ensuring that the pricing of shortage conditions properly reflects the value to the system of going short each product type. Shortages of higher value products and services, such as spinning reserves, Regulation Service and transmission security, are priced
higher than other lower value products and services, such as 30-minute reserves.
Relatively short duration events likely do not require the same magnitude of pricing as longer duration events. The NYISO continually reviews its shortage pricing rules and market outcomes to identify opportunities for enhancements.36

Treatment of transient shortage events need not be consistent across all RTO/ISO

markets. Each RTO/ISO has its system conditions and reliability rules that must be complied

with or addressed. Each RTO/ISO faces different system needs and operating constraints within

36 For example, the NYISO noted that the use of escalating prices for increasing levels of

transmission shortage under its recently-approved graduated transmission demand curve “serve[s] as a proxy for dealing with transient transmission shortage conditions and represent[s] a step forward in addressing such conditions. See Docket No. ER15-485-000, supra, Proposed Tariff Amendments to Revise Transmission Shortage Costs at 7 (November 25, 2014).

its region. A transient shortage event pricing solution that may be reasonable and appropriate in one region may not be workable or appropriate for another region.37

11. Interchange Uncertainty

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?

NYISO Response:

More frequent cross-border (interchange) transaction scheduling, economic evaluation of interchange offers/bids and Coordinated Transaction Scheduling (“CTS”) each significantly
reduce interchange uncertainty.38 Market participants using CTS submit a single CTS Interface Bid to indicate their desire to simultaneously buy Energy in one RTO/ISO and sell Energy into the other participating RTO/ISO based on the forecasted price difference between the two
markets at the relevant location. CTS provides market participants a more precise method of arbitraging price differences between markets.

Instead of submitting a strike price, CTS Interface Bids specify a minimum predicted

price difference between the two markets for the RTOs/ISOs to use in deciding whether or not to
schedule a CTS Interface Bid. Schedules are based on the price differences projected by the
participating RTOs/ISOs. At the NYISO/PJM border, the NYISO incorporates PJM’s forecasted

37 Although the actual manner for addressing transient shortage events need not be uniform across all RTO/ISO markets, all RTOs/ISOs should provide equal transparency regarding the methodology
employed for addressing transient shortage events.

38 NYISO and PJM implemented CTS on November 4, 2014. The NYISO and ISO-NE intend to implement CTS later in 2015.

prices into the NYISO’s RTC optimization and economically evaluates bids and offers to determine cross-border Transaction schedules each quarter-hour.39

CTS reduces uncertainty and improves scheduling efficiency by: (i) allowing

Transmission Customers to offer different MW quantities at different prices for each 15-minute interval within an hour; (ii) reducing counter-intuitive inter-regional schedules by explicitly
incorporating projected price differences between Control Areas into scheduling decisions; and (iii) establishing intra-hour schedules 15 minutes closer to actual, real-time operations. The
scheduling process, repeated every 15 minutes, more efficiently utilizes available transfer
capability whenever economic transactions are proposed to move power from the lower cost
Control Area to the higher cost Control Area. Establishing intra-hour schedules closer to the
actual 15 minute scheduling interval also improves the accuracy of cross-border scheduling
decisions because those decisions reflect updated system conditions. Finally, submitting a CTS Interface Bid protects the Transmission Customer from the financial risk of obtaining
inconsistent transmission schedules because CTS Interface Bids are jointly scheduled and
coordinated between the participating RTOs/ISOs.40

The NYISO utilizes its RTC system to economically evaluate and schedule interchange bids and produce transaction schedules on a 15 minute basis. Economic evaluation and

39 Every 15 minutes, the NYISO runs a multi-period optimization covering the next 2.5 hours in 15-minute intervals. PJM provides the NYISO the forecasted LMPs from its Intermediate Term Security Constrained Economic Dispatch (“IT SCED”) application prior to each RTC run, as an input into the
NYISO optimization.

40 The NYISO estimates that the combined enhancements to real-time scheduling with PJM
produced in excess of $1.5 million in production cost savings for the two regions between November
2014 and January 2015. See NYISO, Broader Regional Markets Metrics Report at 3 (January 2015)
available at:

http://www.nyiso.com/public/webdocs/markets_operations/committees/bic_miwg/meeting_materials/201
5-02-26/Monthly%20Report%20for%20MIWG%20-Jan%202015.pdf.

scheduling of interchange between the NYISO and its neighbors has resulted in improved

transparency and predictability with respect to interchange transactions. The coordinated

dispatch of CTS transactions also ensures that interchange schedules are developed in a manner consistent with the needs of each region and the bids submitted by market participants. Such coordinated dispatch through a single clearing engine significantly reduces interchange
uncertainty with respect to the interfaces utilizing CTS.

The ability of CTS to reduce interchange uncertainty and efficiently schedule interchange
between neighboring regions is significantly influenced by the participating RTOs’/ISOs’ ability
to accurately forecast future system needs and provide price signals that accurately reflect
forecasted needs. The ability of market participants to respond appropriately to price signals
between regions is dependent on their ability to understand how forecasted prices and
settlements are calculated. Transparency as to the price formation concepts and methodologies
on each side of an interface is necessary for market participants to accurately predict and
efficiently react to prices. Because market participants react to price signals, it is important to
ensure that prices are efficient from the outset. If market participants are responding to
inefficient price signals, the resulting interchange schedule is likely to produce inefficient results.

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?

NYISO Response:

Mechanisms that allow supply resources to reflect changes in their cost to produce energy
over the course of the operating day are an important capability that enhances price formation in

RTO/ISO markets. The ability to submit costs on a granular basis across the operating day has taken on enhanced importance due to the growing dependence on natural gas as a primary fuel source for electricity generation.

The NYISO has permitted hourly changes to real-time offers since 1999. In 2010, the
NYISO implemented increasing bids in real-time (“IBRT”) functionality to allow resources that are committed in the Day-Ahead Market to increase their real-time offers for day-ahead
committed incremental energy.41 The IBRT functionality permits day-ahead committed units to reflect changes, such as increases in fuel cost, to their cost to produce energy in real-time,
thereby allowing: (i) suppliers an opportunity to manage the risk of unexpected fuel cost
increases; and (ii) the NYISO’s real-time commitment and dispatch software to evaluate such
changes in cost and reflect such unexpected circumstances in real-time prices. Establishing realtime prices on the basis of the most accurate fuel cost information allows real-time prices to
more accurately reflect the value of energy to the system.

The NYISO’s near-term priorities for Energy and Ancillary Services market

enhancements are primarily encompassed by its Fuel Assurance Initiative. The Fuel Assurance
Initiative is aimed at identifying ways to further protect reliability by improving the incentives
for generator performance, unit availability and fuel availability in light of New York’s growing
dependence on natural gas for electricity production. In addition to the NYISO’s recently-filed
Comprehensive Shortage Pricing project that is referred to in the response to Question Nos. 6
and 9, the Fuel Assurance Initiative includes: (i) the NYISO’s Comprehensive Scarcity Pricing
project, which is aimed at revising the NYISO’s current scarcity pricing rules that apply when

41 See Docket No. ER10-1977-000 et al., New York Independent System Operator, Inc., Proposed Tariff Clarifications Regarding Real-Time Energy Offers (July 26, 2010); and New York Independent System Operator, Inc., 132 FERC ¶ 61,271 (2010).

demand response resources are activated from an ex-post to an ex-ante pricing process; and (ii)
evaluation of improvements to the fuel price assumptions included in supply resources’ day-
ahead reference levels. These initiatives are further described in the recent report submitted by
the NYISO regarding its efforts to address fuel assurance issues.42 As explained in its response
to Question No. 3, the NYISO is also undertaking a comprehensive review of its Hybrid Pricing
rules to determine whether further enhancements to increase price setting eligibility for fast-start
block-loaded resources are warranted. The NYISO intends to pursue these initiatives with its
stakeholders and expects to file any necessary tariff revisions relating thereto over the next
several years.

42 See Docket No. AD14-8-000 et al., Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations and Independent System Operators, Post-Technical Conference Report of the New York Independent System Operator, Inc. (February 18, 2015).

III.CONCLUSION

As further described herein, the NYISO supports the Commission’s vision for proper

price formation and increased transparency in wholesale energy and ancillary services markets.
The NYISO has designed it markets in a manner that is consistent with this vision and
continually reviews its markets to identify opportunities for enhancements to improve market
efficiency and transparency of market outcomes. NYISO respectfully requests that the
Commission consider these comments in determining what, if any, actions should be taken in
this proceeding.

Dated: March 6, 2015

Respectfully submitted,

/s/ Garrett E. Bissell
Garrett E. Bissell
Senior Attorney

New York Independent System Operator, Inc.

10 Krey Blvd.

Rensselaer, New York 12144 (518) 356-6107

gbissell@nyiso.com