THE NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.

In accordance with the Federal Energy Regulatory Commission’s (“Commission’s”)
November 20, 2015 Order Directing Reports (“Order”) and consistent with the Commission’s
January 27, 2016 Notice of Extension of Time issued, in the above-referenced docket, the New
York Independent System Operator, Inc. (“NYISO”) hereby submits its Report responding to the
Commission’s questions. 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 this Report should be served as
follows:

Robert E. Fernandez, General Counsel

Raymond Stalter, Director, Regulatory Affairs *Alex M. Schnell, Assistant General Counsel/
Registered Corporate Counsel

Garrett E. Bissell, Senior Attorney

10 Krey Boulevard

Rensselaer, NY 12144

Tel: (518) 356-6000
Fax: (518) 356-8825

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

*Person designated for receipt of service.

II. REPORT IN RESPONSE TO COMMISSION QUESTIONS

The NYISO provides the following responses to the topics the Commission instructed it to address in this Report:

A.Pricing of Fast Start Resources

Commission Questions

1. Generally, the fast-start pricing logic consists of a dispatch run and a pricing run that
relaxes the minimum operating limit of block-loaded fast-start resources such that
these resources can set the LMP.

a. Please explain during what period fast-start pricing logic is applied to block-
loaded fast-start resources. For example, does fast-start pricing logic apply
during a resource’s initial commitment period or during its actual run time?

b. Please explain the order in which the various fast-start pricing logic processes
are executed. Specifically, are the dispatch run and pricing run executed
separately or integrated into one process?

c. Some RTOs/ISOs relax the minimum operating limit of a resource only in the
pricing run, but some RTOs/ISOs currently also relax the minimum operating
limit in the dispatch run. Does the fast-start pricing logic relax the minimum
operating limit of a resource in the dispatch run, the pricing run, or both?
Please explain why the RTO/ISO chose the specific approach.

d. When a fast-start resource sets the LMP under the RTO’s/ISO’s fast-start
pricing logic, how does the RTO/ISO ensure that the minimum operating
limits of block-loaded fast-start resources are satisfied in dispatch?

NYISO Response

Block-loaded fast-start resources provide 10-minute and 30-minute non-synchronous reserves. These resources must either be (1) off, or (2) on and running at their upper operating limit (UOL) in order to provide energy. In other words, when a block-loaded resource is on, the minimum generation for the resource is equal to its UOL.

Day-Ahead commitments and hourly schedules are determined by the Security

Constrained Unit Commitment (SCUC) to meet bid and forecasted load. Real-Time

Commitment (RTC) software makes the commitment decision for resources in real-time every

15 minutes to meet forecasted load. Real-Time Dispatch (RTD) runs every 5-minutes and

dispatches resources to meet actual and forecasted load, and sets prices.

Offline GT pricing and hybrid GT pricing are two methods used in RTD to set

appropriate prices. These two approaches allow RTD to develop prices using actual generator
costs to address constraints that only require a portion of a block-loaded unit’s capability to
solve.

Hybrid Pricing

In RTD, RTC and SCUC the cost of the next MW (while co-optimizing Energy,

Operating Reserves, and Frequency Regulation) is used to establish the LBMP. The first ideal pass and second ideal pass are used to determine prices, while the physical pass, which follows the two ideal passes, is used to determine schedules in RTD. The physical pass does not utilize data output from the first and second ideal passes. The two ideal passes are required to
accommodate the NYISO’s hybrid GT pricing logic, while offline GT pricing is applied in all three passes. Final prices are established in the second ideal pass.

When block-loaded GTs are committed, dispatching these units to their maximum output, as their operational characteristics require, may displace more economic dispatchable units. The hybrid GT pricing logic allows online block-loaded units to be modeled as dispatchable to
determine prices when their operation is needed to meet load, when the commitment displaces higher cost units, or to satisfy reserve requirements.

The physical pass determines the dispatch signal that is sent to all resources while

respecting “physical” parameters, such as minimum generation MW, submitted to the ISO by
Market Participants via their offers. For all committed GTs that are physically block-loaded,
output is fixed at their upper operating limit within the physical pass. GTs only receive
schedules from the physical pass, and do not receive any schedule produced by the first or
second ideal passes.

The first ideal pass of hybrid GT pricing logic determines how each online block-loaded GT will be modeled in the second ideal pass of the hybrid GT pricing logic. Block loaded GTs that have been previously committed can be modeled as fully dispatchable from zero MW to the GT’s UOL, or as block loaded at the GT’s UOL.

Committed block-loaded GTs that are within their minimum run time are modeled as

dispatchable from zero to their UOL in the first ideal pass. These GTs are eligible to set price in the second ideal pass if they are economic and dispatched to produce energy within the first ideal pass. Conversely, any committed block loaded GT that is within its minimum run time and is
not economic during the first ideal pass is not eligible to set price in the second ideal pass.
Committed block-loaded GTs that are outside of their minimum run time are always eligible to set price within the second ideal pass. This approach is reasonable because RTC will turn off
such resources if they are not economic.

The second ideal pass is used to establish prices. Depending on the outcome of the first
ideal pass, GTs will either be modeled as blocked loaded at the GT’s UOL, or fully dispatchable
from zero to the GT’s UOL. If the GT is economically dispatched in the first ideal pass then the
GT will be modeled as dispatchable in the second ideal pass from zero to the unit’s UOL.
Conversely, if such a GT is dispatched to zero during the first ideal pass, then the GT is blocked

loaded at its UOL and is seen by the dispatch as a must-take resource which can never be marginal or set price.

Large differences between the physical dispatch schedules and ideal dispatch prices may introduce lost opportunities for more dispatchable resources when prices indicate that the
dispatchable resource should be scheduled at a different output than results from the physical
dispatch. This misalignment between prices and schedules can create unintended incentives for some dispatchable resources to stop following ISO dispatch instructions. The hybrid GT pricing logic avoids large differences between the schedules and prices produced from the physical pass and prices resulting from the second ideal pass by modeling some block loaded GTs as flexible, with prices from the second ideal pass being used for settlements. Modeling some block loaded GTs as flexible in the second ideal pass alleviates “lumpiness” in the resource supply curve by
modeling select block loaded units as dispatchable when establishing prices. The NYISO’s
hybrid approach arrives at a price signal more accurately representing the cost to meet load while reducing the lost opportunity of dispatchable resources.

Additionally, allowing block-loaded resources to be fully dispatchable to zero allows those resources to set the price whenever they were required to meet load. That is, anytime at least one megawatt of the resources output was necessary to meet load, the resource would be eligible to set the price. Limiting the range of dispatchability would tend to prevent these
resources from setting price when only a small portion of their output was necessary to meet load. Because New York has load pockets where only block-loaded resources are available to meet the reliability needs, it is important to allow these resources to be eligible to set price
anytime they are needed to meet load.

Offline GT Pricing

The NYISO utilizes the bids of offline 10-minute block-loaded GTs in RTD to set price
on some occasions. Offline 10-minute block loaded GTs are modeled in both the physical pass
and second ideal pass, but do not receive schedules for settlement from RTD. Start-up costs are
considered for offline 10-minute GTs that are qualified to set price. The start-up cost of the
uncommitted GT is divided by the GT’s UOL and added to the energy offer of the GT to arrive
at an adjusted energy offer. Offline block-loaded 10-minute reserve eligible resources are treated
as dispatchable from zero to their Upper Operating Limit within each pass, with a zero
MW/minute ramp down rate to reflect their minimum run time constraint within dispatch.1 The
zero MW/minute ramp down rate was developed because minimum run time constraints are only
enforceable for online resources within the dispatch algorithm and it was important to have the
dispatch of offline GTs represent, to the extent practicable, the GT’s operating characteristics.
The NYISO first introduced the concept of allowing offline 10-minute GTs to set price as a way to establish more efficient pricing in constrained load pockets. The NYISO has found that allowing these GTs to set price provides both the market and the NYISO operators an indication that an offline GT would efficiently solve the reliability need and, therefore, its start-up is
warranted. The offline GT pricing capability is especially useful for adding price transparency to
unanticipated changes between the time that RTC has completed its commitment evaluation and
the 5-minute RTD dispatch evalution when offline 10-minute GTs are the only option for solving
a reliability need. Because offline 10-minute GTs are capable of starting within 10 minutes,
prior to a subsequent RTC execution, they are eligible to set price in RTD.

1 Such units are excluded from commitment when they are within their minimum down time.
6

Offline GTs that are not eligible to provide 10-minute non-synchronous reserve are not eligible to set price in RTD. Instead, the NYISO relies on RTC, with its look-ahead capability, to commit offline GTs with start-up times that are longer than 10 minutes. Once committed, these resources are subjected to the hybrid GT pricing logic within RTD.

Commission Question

e. CAISO, ISO-NE, NYISO, and MISO currently relax the minimum

operating limit of eligible block-loaded fast-start resources to zero, while

PJM relaxes the minimum operating limit by 10 percent. Please explain the reasons for the specific approach used to relax minimum operating limits. For SPP, please explain whether minimum operating limits are relaxed to zero or not, and the reasons for the chosen approach.

NYISO Response

The NYISO relaxes the minimum operating limit of block-loaded resources to zero when
applying its hybrid GT pricing logic. This is done so that the algorithm can distinguish between
units that are constrained by the block loading treatment and those that are not. In New York,
there are constrained load pockets where GTs are the only resource that can set the price. It is
important to allow maximum dispatch flexibility for the pricing algorithm to set efficient prices
in these areas.

Commission Question

2. Please describe any RTO/ISO and/or stakeholder initiatives or plans, if any, related to
fast-start pricing logic and why those changes are being pursued. What tradeoffs, in
terms of costs and benefits, are the RTO/ISO and/or stakeholders considering during
this process? Please provide a qualitative discussion of whether and how
enhancements to existing fast-start pricing logic could potentially reduce overall
uplift.

NYISO Response

In 2016 the NYISO will be working with its stakeholders on the “Hybrid GT Pricing

Improvements” project. This project is based on recommendation 10 in the Market Monitoring
Unit’s (MMU’s) 2014 State of the Market Report.2 The MMU observed that in 7 to 12 percent
of intervals there are block-loaded units that are economic but are not qualified to set price. This
outcome has been attributed to the Hybrid GT methodology where multiple block loaded GTs
have been committed and not all are found to be eligible to set price. Some GTs are eligible to
set price, while others are not, due to system changes between when RTC evaluated the fleet and
when RTD is dispatching the fleet. The 2016 project will evaluate the proposal to allow all

block-loaded units that are economically committed by RTC to be qualified to set price in the final pricing pass. The project will also evaluate amortizing GT start up costs into their offer over the initial phase of the GT’s commitment and allowing these costs to be reflected in prices. The proposed modification is intended to increase the accuracy of price signals, avoid intervals where the LBMP is lower than the bid cost of the GT, and to reduce uplift.

2 The MMU also raised this concern in earlier State of the Market Reports.
8

Commission Question

3. Please explain the following regarding the RTO’s/ISO’s fast-start pricing logic
eligibility:

a. What type of resource (e.g., combustion turbine) may be considered a fast-start
resource and what are the eligibility requirements (e.g., start-up time and/or
notification time)? Are resources other than block-loaded fast-start resources
eligible to set the LMP under the fast-start pricing logic? Can a fast-start resource
choose not to be included in the fast-start pricing logic?

NYISO Response

What type of resource (e.g., combustion turbine) may be considered a fast-start resource and what are the eligibility requirements (e.g., start-up time and/or notification time)?

All committed block-loaded resources qualified to provide 10-minute nonsynchronous reserves are considered in the NYISO’s hybrid GT pricing logic. Certain Out of Merit
Generation (OOM) types disqualify resources from setting price. These include OOMs due to Transmission Owner (TO) reliability, generator requests, ISO security, ISO voltage support, TO voltage support and for testing.

All 10-minute non-synchronous block loaded resource that are offline are included in the NYISO’s offline pricing logic.

Are resources other than block-loaded fast-start resources eligible to set the LMP under the fast-start pricing logic?

Committed dispatchable resources are considered in the supply curve when establishing prices and schedules; the bids of such resources can set prices. These resources are not directly considered by the hybrid GT pricing logic or offline GT pricing.

Can a fast-start resource choose not to be included in the fast-start pricing logic?

All block-loaded resources eligible to provide 10-minute non-synchronous and 30-minute reserves are included in the NYISO’s hybrid GT pricing logic. All 10-minute non-synchronous reserve eligible resources are considered in the NYISO’s offline GT pricing. Fast-start resources cannot choose to be included or excluded from the pricing logic.

Commission Question

3. Please explain the following regarding the RTO’s/ISO’s fast-start pricing logic
eligibility:

b. Can commitment-related start-up and/or no-load costs be accounted for in the

LMP? If so, please explain how and provide numerical examples to illustrate how these costs are included in LMP.

NYISO Response

Start-up and no-load commitment costs are not accounted for in the LBMP unless offline
GTs are used to set the price. This is because dispatched units’ start-up and/or no-load costs
have already been evaluated in the commitment passes, the commitment was determined to
minimize production cost, and as a result LBMPs are largely high enough to cover these
commitment costs. Start-up costs are considered for offline 10-minute GTs that are qualified to
set price and these costs are amortized over the GT’s UOL and added to the GT’s energy offer as
further explained in the NYISO’s response to Pricing of Fast Start Resources question 3(c).

Commission Question

3. Please explain the following regarding the RTO’s/ISO’s fast-start pricing logic
eligibility:

c. Can offline block-loaded fast-start resources set the LMP? If so, please explain
how and provide numerical examples to illustrate how such resources set the
LMP.

NYISO Response

Offline 10-minute eligible resources are qualified to set price in the pricing pass. The

minimum output levels of such resources are relaxed to zero. In other words, they are considered dispatchable and are allowed to set the price if they are economic. The start-up costs of each
such resource, divided by the generator’s upper operating limit, is added to the energy offer
costs. Combining start-up costs with energy offer costs when allowing offline GTs to set price ensures that the stated LBMPs cover the GT’s approximate commitment costs. Unlike GTs that have been committed and have an enforced minimum run time over which commitment costs can be recovered, offline GTs do not have an enforced minimum run time. Therefore the LBMP
must immediately account for the commitment costs.

Numerical Example:

Consider the following units and a 475 MW load:

Energy

Offer Price

StatusResource($/MWh)Min GenUOLStart Up Cost ($)

NOT

COMMITTEDGT7550501000

Flexible

COMMITTEDUnit16025300n/a (already online)

Flexible

COMMITTEDUnit23025100n/a (already online)

Flexible

COMMITTEDUnit325550n/a (already online)

Physical Pass:

The physical and pricing passes each take place within RTD. Offline GTs are modeled as
dispatchable within the physical pass i.e., their minimum generation level is set to zero. Offline
GTs are not provided a schedule unless committed by the operator. This treatment allows RTD
to price the need for GTs due to changing conditions that were not seen in RTC, while allowing
NYISO Operations to confirm that the condition is expected to continue and is not due to a
transient issue before committing the generator. As explained above, the start-up cost of the
uncommitted GT is divided by the unit’s UOL and added to the energy offer of the unit to arrive
at an adjusted energy offer. The NYISO utilizes Regulation Service to compensate for any under
generation.

Adjusted

Energy OfferPhysical Dispatch

StatusResource($/MWh)Min GenUOL(MW)

NOT

COMMITTEDGT9505025

Flexible

COMMITTEDUnit16025300300

Flexible

COMMITTEDUnit23025100100

Flexible

COMMITTEDUnit32555050

Pricing Pass:

The adjusted energy offer of the uncommitted resource is also considered in the pricing
pass. The uncommitted 10-minute non-synchronous eligible GT is modeled as dispatchable
within the pricing pass. Again, the GT is not provided a schedule unless it is committed by the
operator.

Adjusted

EnergyPricing

OfferStart UpDispatch

StatusResource($/MWh)Min GenUOLCost ($)Solution (MW)

NOT

COMMITTEDGT95050100025

Flexiblen/a (already

COMMITTEDUnit16025300online)300

Flexiblen/a (already

COMMITTEDUnit23025100online)100

Flexiblen/a (already

COMMITTEDUnit325550online)50

Because the uncommitted GT in the above example is dispatched to serve the 475 MW load, the GT would set the Energy component of the LBMP at $75/MWh + ($1000/50MW) = $95/MWh in the pricing pass.

Commission Question

4. Based on the definition in the RTO/ISO tariff, how much block-loaded fast-start

capacity (in MWs) is available? How much fast-start capacity is not block-loaded? Please provide as seasonal capability (i.e., summer capability) and include only capacity that is currently in service and can participate in the market.

NYISO Response

Section 1.6 of the NYISO OATT defines a Fixed Block Unit (i.e. a block-loaded unit) as
“[a] unit that, due to operational characteristics, can only be dispatched in one of two states:
either turned completely off, or turned on and run at a fixed capacity level.”
The combined upper operating limits of all block-loaded, fast-start, 10-minute eligible units currently in service and participating in the NYISO markets as of February 26, 2016 is approximately 2,000 MW. The summed upper operating limits of dispatchable, 10-minute

eligible, fast-start capacity units currently in service and participating in the NYISO markets as of February 26, 2016 is between 1500 MW and 2000 MW.3 The summed upper operating limits of block-loaded, 30-minute eligible, fast-start unit currently in service and participating in the NYISO markets as of February 26, 2016 is approximately 3,000 MW. The aforementioned
figures do not vary significantly when considering summer vs. winter capability.

Commission Question

5. As previously discussed, fast-start pricing logic can result in over-generation or in
resources not following dispatch instructions.

a. Please discuss the extent to which fast-start pricing logic has resulted in over-
generation or resources otherwise not following dispatch instructions.

b. Please describe the current approach, if any, used to address over-generation or
the incentive to not follow dispatch instructions, and discuss the benefits to this
approach versus other potential approaches to address this problem. For example,
approaches include paying resources their opportunity costs, or penalizing them
for deviating from dispatch instructions.

NYISO Response

The NYISO’s generation fleet responds well to NYISO-issued base points and

instructions. The NYISO has not identified its fast-start pricing logic as causing systemic over-
generation, or providing incentives for resources to not follow NYISO dispatch instructions.
The NYISO believes that a combination of well-designed market rules incent resources to follow dispatch instruction and prevent unscheduled overproduction. First, resources changing their bid type from ISO-committed in the Day-Ahead Market to self-committed in the Real-Time Market give up their eligibility to receive Bid Production Cost Guarantee (BPCG) payments in the Real-Time Market. Dispatchable resources are unlikely to risk losing guarantee payments

3 The NYISO uses a range to ensure that its public response does not reveal any Confidential Information.
14

(that are paid over the dispatch day) to garner additional profits over the relatively brief and

unpredictable period when their production is displaced by a block-loaded resource. Second, a generator producing above its basepoint is only compensated for overproduction that exceeds the basepoint by 3% of the generator’s UOL, or less.

Commission Question

6. For those RTOs/ISOs that apply fast-start pricing logic only to the real-time market,
please explain why this methodology is not applied to the day-ahead market.

NYISO Response

The NYISO’s hybrid GT pricing logic is not applied by SCUC or by RTC because all

GTs are modeled as dispatchable in the pricing passes of both SCUC and RTC. SCUC and RTC
can fully evaluate when the units are marginal and thus qualified to set prices, while also
determining the least cost set of resources to serve load. RTD does not commit resources, and is
unable to determine marginality of offline block-loaded units without the hybrid GT pricing
logic.

Commission Question

7. Certain RTOs/ISOs argue that expanding the fast-start pricing logic to resources other
than block-loaded fast-start resources is not needed. However, this limits the amount
of fast-start resources that are able to set LMP. Please explain the advantages or
disadvantages of allowing fast-start resources that are not block-loaded but that have
a limited operating range to set the LMP, and please explain whether it is appropriate
to allow the commitment-related start-up and no-load costs of such resources to affect
prices.

NYISO Response

The NYISO only applies hybrid GT pricing logic and offline GT pricing logic to blockloaded fast-start resources. There has been no discussion of allowing dispatchable units to set price because dispatchable fast-start resources are able to set price within their dispatchable range when they are committed. Dispatchable fast-start resources are not common in New York and the few that exist are not situated in constrained load pockets. The expected benefit of
implementing hybrid pricing for these resources is minimal.

B. Commitments to Manage Multiple Contingencies

The NYISO’s SCUC, RTC and RTD secure the transmission system to address single

contingency events. A subset of these single contingency events involve the simultaneous

outage of multiple transmission elements. For example, failure of a circuit breaker due to a fault-
to-ground may be cleared from the system by the operation of multiple circuit breakers, resulting
in the outage of multiple transmission system elements.4 The NYISO does not ordinarily
perform its market evaluations in a manner that would identify the incremental resource
commitments for single contingencies that involve multiple transmission elements.
New York State Reliability Council (NYSRC) reliability rules stipulate that Con Edison “…operate certain areas of the New York State (NYS) Bulk Power System to meet more
stringent local reliability requirements than the rest of the NYS Bulk Power System.”5 The
NYISO accommodates the Con Edison requirements in performing market analysis for resource

4 Paragraph 30 and footnote 61 of the Order describe this example as an N-2 event.

5 Link to NYSRC Reliability Rules:

http://www.nysrc.org/pdf/Reliability%20Rules%20Manuals/RRC%20Manual%20V35%20Final%208-14-15.pdf

commitment and scheduling for both Day-Ahead and Real-Time markets. For example, in

performing its Day-Ahead Market evaluations the NYISO includes a set of constraints, including
multiple contingency events, that may be satisfied by combinations of various New York City
(NYC) zone J generator commitments which satisfy the NYC Local Reliability Requirements
(LRR). The Power Supplier uplift associated with the incremental resources committed to
satisfy the LRR is calculated and the costs are allocated to Load Serving Entities in the NYC
zone.

In performing its Real-Time Market evaluations while a Con Edison Storm Watch is in effect, the NYISO includes a set of N-1-1 contingencies involving Con Edison transmission equipment in zones outside of NYC. The NYISO employs a calculation, described in Appendix M of its Accounting and Billing Manual,6 which identifies the incremental costs associated with securing the transmission system for the Con Edison Storm Watch condition. The NYISO
allocates these Storm Watch costs to NYC zone Load Serving Entities.

Commission Question

1. Please describe any RTO/ISO and/or stakeholder initiatives or plans, if any, to

incorporate the costs of multiple contingencies into clearing prices for energy and

ancillary services. This description should include estimated costs and a timeline for implementation.

6 Link to Accounting and Billing Manual:

http://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_and_Guides/Manuals/Administrativ
e/acctbillmnl.pdf

NYISO Response

As described above, the NYISO currently solves single contingency events that may
include the simultaneous outage of multiple transmission elements. The clearing prices for
energy and ancillary services incorporate the costs of securing the system for these events.

The costs of solving certain multiple contingency events are addressed through the

markets in three primary ways. First, the multiple contingency Con Edison Storm Watch criteria
is secured for explicitly in the Real-Time Market and reflected in clearing prices.
Second, as it relates to the Con Edison LRR criteria that are solved for in the Day-Ahead Market, the solution will include the commitments needed to satisfy the LRR criteria. The
resources required to meet the LRR criteria are eligible to set price. The Con Edison LRR
criteria are not otherwise explicitly reflected in the Day-Ahead Market clearing prices.
However, if the Con Edison LRR criteria were considered after the Day-Ahead Market posted,
subsequent resource commitments would sometimes be required, and would result in an over
commitment of resources transitioning into real-time. The NYISO’s approach develops efficient
commitments and schedules.

Third, as further explained in response to the next question, certain reserve products are used to prepare for multiple contingencies across the New York Control Area (NYCA). Given that the NYISO’s market solution is a co-optimization between energy, operating reserves and regulation with the objective of minimizing total production cost, the cost of solving for multiple contingencies through reserves is already included in the clearing prices. The calculation of clearing prices for each of these products incorporates resource lost opportunity cost, fairly
compensating resources for each product in the majority of intervals.

No projects that are currently being considered propose to incorporate the costs of

additional multiple contingency constraints into the market solution. The NYISO and its

stakeholders are, however, considering a project called “Modeling 100+kV Transmission

Constraints,” which is based on a recommendation in the 2014 State of the Market report

produced by the NYISO’s Market Monitoring Unit. The proposed project would assess the

value and impacts of modeling 115/138kV transmission constraints in the Day-Ahead and RealTime Markets.

Modeling constraints on facilities above 100 kV that are not modeled today would be

expected to reduce out-of-market commitments to resolve Western transmission constraints.

Market incentives for investment in resources on the 115kV system in upstate New York may be
improved by reflecting these facilities in the NYISO’s energy and ancillary services markets.

Commission Question

2. Please explain whether constraints or reserve products are used to address multiple
contingencies in the day-ahead and real-time energy and ancillary services markets
and, if so, how such constraints or reserve products are incorporated in market
models. Specifically, describe (1) the criteria for determining what constraints or
reserve products are included in the day-ahead or real-time market model to address
multiple contingencies, and (2) provide a detailed description of how constraints or
reserve products to address multiple contingencies are included in both the day-ahead
and real-time market model.

NYISO Response

Operating reserve constraints are modeled in the Day-Ahead and Real-Time Markets.
Operating reserve constraints are addressed by imposing locational and physical resource
qualifications for providing each type of reserve. The amount of a particular operating reserve
product the NYISO secures its system to depends on rules established by the North America

Electric Reliability Corporation (NERC), Northeast Power Coordinating Council (NPCC), and

New York State Reliability Council (NYSRC). The NERC, NPCC and NYSRC rules are used to establish the locational MW requirements for operating reserve procured by the NYISO in the Day-Ahead and Real-Time Markets.7 Not all locational reserve requirements are in place to
secure against multiple contingencies.

Three locational operating reserve product constraints modeled are specific to multiple
contingencies. These include the Southeastern New York (SENY) 30-minute reserve
requirement, the East of Central East (EAST) 10-minute non-synchronous reserve requirement,
and the New York Control Area (NYCA) 30-minute total reserve requirement. Specifically,
1300 MW of 30-minute total reserve is procured in the SENY reserve region in order to re-
prepare the system to withstand the next worst contingency following the occurrence of the worst
contingency for the UPNY-SENY interface. Twelve hundred MW of 10-minute non-
synchronous reserve is procured in the EAST reserve region to restore flows on the Central East
internal interface to within limits following the worst contingency, in order to prepare the system
to suffer the next worst contingency. The NYCA 2620 MW 30-minute total reserve requirement,
tied to an NYSRC rule, is intended to prepare the system to suffer the worst two supply
contingencies before load shedding is required. NYSRC rules also include single contingencies
that involve multiple elements, which are included as constraints within the NYISO’s Day Ahead
and Real-Time Markets.

A Day-Ahead Reliability Unit (DARU) may be committed at the request of a

Transmission Owner (TO), or by the NYISO to address local or statewide reliability needs.

7 NYISO posting of locational requirements:

http://www.nyiso.com/public/webdocs/markets_operations/market_data/reports_info/nyiso_locational_reserve_req
mts.pdf

DARU commitments are included with the Day-Ahead Market run, providing for a more

efficient commitment relative to if the unit were committed after the establishment of Day-

Ahead schedules. All requests by TOs to commit generators via the DARU process, as well as NYISO-initiated DARUs, are posted to the OASIS at or before the time of the Day-Ahead
Market close. DARU requests may or may not be to address multiple contingencies. Typically, the TO will provide the ARR that triggers the DARU commitment.

Local Reliability Rules (LRR) defined by the NYSRC are included in the Day-Ahead and Real-Time Markets. Five LRRs are included in the NYISO’s markets. They address locational reserves, unit commitment, potential loss of generator gas supply, and Storm Watch in New
York City (NYC), as well as potential loss of generator gas supply on Long Island.
The NYISO includes in its Day-Ahead Market evaluation the NYC zone generator
commitment combinations which Con Edison identifies as necessary to satisfy NYSRC
requirements. The NYC LRR contingencies are evaluated and may affect resource commitments in each Day-Ahead Market evaluation.

Each NYC LRR requirement is presented as minimum generation requirement to be
satisfied by a subset of the NYC generation resources. There are multiple requirements for
various localities within the NYC zone to secure for thermal, voltage, loss of natural gas and
emissions conditions. Some required minimum generation production values may vary as a
function of demand. NYC generation resources may contribute to satisfying multiple LRR
requirements.

The NYISO includes in its Real-Time Market evaluation the N-1-1 contingencies Con
Edison identifies as satisfying NYSRC real-time operational requirements. Storm Watch
contingencies occur in real-time and require RTC and RTD to secure one or a number of

multiple contingencies cases as outlined in the table A.5 of the NYISO Emergency Operations Manual.8 Storm Watch contingencies are included in Real-Time Market evaluations for the period over which Con Edison invokes the procedure. These periods may be non-contiguous within a day and may span multiple days.

Commission Question

3. If resources are manually committed (i.e., committed outside of security constrained
unit commitment processes) to address multiple contingencies, please describe the
criteria used to determine whether a manual commitment will be made and how the
RTO/ISO determines what resources are committed. If resources are manually
committed to address only some subset of multiple contingencies, please describe
what criteria the RTO/ISO uses to determine whether a manual commitment will be
made.

NYISO Response

The NYISO’s SCUC and RTC can commit resources to address multiple contingencies, as described in the NYISO’s response to Commitments to Manage Multiple Contingencies
question 2. The NYISO and Transmission Owners can also manually identify resources that must be committed to meet reliability criteria in advance of the Day-Ahead Market by issuing a DARU designation. Should the need arise to commit additional resources outside of the market process in order to resolve reliability requirements, the NYISO determines which resources are available within the needed timeframe to solve the necessary constraints and commits the most economic resource or resources from the options available to it.

Resources may be manually committed using a Supplemental Resource Evaluation (SRE) when a need arises. An additional type of manual commitment is Out-of-Merit Generation

8 Link to Emergency Operations Manual:

http://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_and_Guides/Manuals/Operations/e
m_op_mnl.pdf

(OOM). An OOM commitment or dispatch can be implemented to secure the bulk power

system, during communication failures, or when the Real-Time Commitment does not

successfully run. Transmission Owners can request that a generator be committed or dispatched OOM for local reliability. Generators that are experiencing operating difficulties can request an OOM through their local Transmission Owner.

Commission Question

4. For each month during the twelve month period between October 1, 2014 and

September 30, 2015, please provide: (1) an estimate of the number of resource

commitments made in real-time or day-ahead to address multiple contingencies. This estimate should be broken down by geographic area (e.g., reserve zone or load zone), if possible; and (2) an estimate of the dollar amount of uplift paid to resources
committed to address multiple contingencies.

NYISO Response

The NYISO performs a co-optimized dispatch of resources to provide energy, regulation, and reserves to address all system needs incorporating all of the criteria described in response to the prior questions. As such, it is not possible to tie specific resource commitments to a specific set of multiple contingency constraints that are secured in the market software. The cost of a resource committed to resolve one requirement in the model (e.g. a locational operating reserve requirement), may have resulted from the unavailability of another resource that was scheduled to provide a product of greater value (e.g. energy). The multiple contingency commitments that are capable of being distinguished are set forth in the table below.

Transmission Owners are required to provide a reason, including any applicable ARR
codes, for DARUs and the NYISO posts the ARR codes that are provided with its Operational

Announcement website posting.9 The NYISO also reports commitments with ARR designations as part of its Operations Performance Metrics Monthly Report.10

The table set forth below identifies the resource commitments and Power Supplier uplift paid for the securing the New York City Local Reliability Rules. It also identifies the number of hours for which Con Edison implemented its Storm Watch Procedure and the storm watch costs allocated to the NYC zone Load Serving Entities.11 For more information on LRR
commitments, please see the NYISO’s response to question 2 under the topic heading
“Commitments to Manage Multiple Contingencies.”

NYC LLR

commitmentUnique NYCNYC LLR DAMStorm WatchStorm Watch

Monthunit-hrsLRR UnitsBPCG $Procedure HoursProcedure BMCR $

10/20142534$165,244.200$0.00

11/20141443$226,885.400$0.00

12/2014284$57,975.680$0.00

01/20151646$849,959.290$0.00

02/2015962$412,982.430$0.00

03/20152392$281,228.7010$0.00

04/20156482$636,567.960$0.00

05/201513263$1,754,951.6321$723,021.91

06/201511976$1,649,918.7627$2,334,798.49

07/20157435$594,603.9019$374,013.76

08/20158426$1,033,885.107$354,525.34

09/20155212$448,454.941$60,637.43

$8,112,657.99$3,846,996.93

9 The NYISO’s operational announcements can be found on its website:

http://www.nyiso.com/public/markets_operations/market_data/reports_info/index.jsp The user must select the
Operational Announcements checkbox to see the reports.

10 The Operations Performance Metrics Monthly Report is located in the Monthly Reports folder at the following
link: http://www.nyiso.com/public/markets_operations/documents/studies_reports/index.jsp

11 Though BMCR is not a form of uplift, it is included in the table for completeness.

Commission Question

5. Describe whether and how incorporating additional multiple contingency constraints
or using reserve products in day-ahead or real-time market models would improve
price formation. If taking additional steps to incorporate multiple contingency
constraints or using reserve zones in day-ahead or real-time market models is
unnecessary, impracticable, or would negatively affect price formation, please explain
why.

NYISO Response

The NYISO finds it effective to solve for single contingency events resulting in the outage of multiple transmission elements through the market.

The NYISO has found locational reserve regions to be an effective means of managing

multiple contingencies. When managing multiple contingencies there is often a limited period of time for the NYISO’s operators to restore the system to normal operating conditions following the occurrence of the “first” contingency. This time element can best be modeled in current
market platforms using a locational reserve requirement.

Alternatively, the multiple contingencies can be modeled directly as the simultaneous
loss of several transmission or generation elements. This modeling method has costly side
effects. The modeling must immediately account for reduction in transmission capability which
results in inefficient use of the transmission system and result in higher total production costs
due to the dispatch of less efficient generation. This effectively requires the ISO or RTO to
maintain costly transmission level “reserves” by holding back usable transmission and
generation ramp capability in order to be able to immediately react to the multiple contingency
event, should it occur.

By securing for multiple contingencies in its market evaluations the NYISO provides
power suppliers with commitment and dispatch instructions relating to these conditions in the

same manner as securing for the single event contingencies; there is no out-of-the-ordinary communication required.

The effect of securing the N-1-1 contingencies is transparent in that the NYC LLR

commitment type for each commitment is posted, and the cost allocation to the NYC zone Load Servicing Entities separately identifies costs that are attributable to the NYC LRR, and costs that are attributable to the Con Edison Storm Watch procedures. The costs of, and other information concerning the NYC LRR commitments and Storm Watch are included in various reports that the NYISO regularly publishes.12

Power suppliers are able to recover their costs through the combination of LBMP

revenue, Bid Production Cost Guarantee (BPCG) payments and Day-Ahead Margin Assurance Payments (DAMAP). Constraints involving the NYC LRR may affect resource commitment, but these constraints are not priced and so will not directly affect LBMPs. Storm Watch
contingencies are priced and affect the real-time LBMP. The constraints that are activated to address a Con Edison Storm Watch are included in Real-Time Market evaluations when Storm Watch conditions exist in the monitored geography. Con Edison operations invokes Storm
Watch and provides advance notice to the NYISO when possible so that the NYISO may include these contingencies in its look-ahead Real-Time Market evaluation.

The practices the NYISO employs to secure multiple contingency constraints supports
the Commission’s price formation goals. They provide correct incentives for Market
Participants to follow dispatch signals, provide price transparency, and provide the opportunity
for suppliers to recover their costs. As explained above, the NYISO secures for several different

12 See the NYISO’s response to Transparency questions 1 and 2 for information on the reports the NYISO publishes.
26

types of multiple contingency constraints within its market evaluations, minimizing the need for out-of-market resource commitments.

C.Look-Ahead Modeling

Commission Question

1. Please describe any RTO/ISO and/or stakeholder initiatives or plans, if any, related to
look-ahead modeling. For any look-ahead modeling enhancements that the RTO/ISO
and/or its stakeholders are currently considering, please discuss any evaluation of the
costs and/or complexities of look-ahead modeling relative to its potential benefits,
and the estimated time frame for implementation of any look-ahead modeling
enhancements.

NYISO Response

The NYISO incorporated look-ahead modeling into its Day Ahead Market at its

inception in 1999 and incorporated look-ahead modeling into its Real Time Market in 2005.
Post 2005 the NYISO has implemented various look-ahead modeling enhancements.
The NYISO regularly assesses if additional refinements are needed and has included a “RTC-RTD Forward Horizon Coordination Improvements” market design project for 2016. Slight modeling inconsistencies between RTC and RTD look-ahead evaluations can arise as the programs evaluate external transactions and the start-up/shut-down of gas turbines. The
inconsistencies the NYISO is working to address can result in unforeseen ramp constraints,
undermine the accuracy of prices forecasted by RTC, and could contribute to transient shortage conditions and unnecessary price volatility. The 2016 project will investigate possible revisions and adjustment to the look-ahead RTC and RTD evaluations.

After the possible revisions and adjustments are identified, costs to change the NYISO’s
market software, as well as impacts to the solution time and RTC/RTD scheduling and pricing
must all be considered when deciding if the NYISO will implement the potential improvements
that it identifies. Though the project has not been discussed at length, should the project find
possible improvements, the total implementation time from initial discussion with stakeholders
to market implementation is estimated to be considerable, given the NYISO’s EMS/BMS System
Upgrade project.13

Commission Question

2. Please list all of the unit commitment and dispatch processes that execute after the
close of the day-ahead energy market, up to and including all unit commitment and
dispatch processes used in the real-time market. Please indicate whether each process
uses look-ahead modeling. With respect to each process that uses look-ahead
modeling, please address each of the topics listed below and include examples where
possible.

NYISO Response

The NYISO Security Constrained Unit Commitment (SCUC) reliability commitment

process is embedded in its Day-Ahead Market (DAM) process. After DAM closes, if there is a
significant change to the system (e.g. the loss of a generator or a transmission element)
additional generators may be committed through the Supplemental Resource Evaluation (SRE)
process. Units may be SRE’d by the NYISO operators, or at the request of a Transmission
Owner. Generators committed via SRE are eligible to set price in real-time.14 SREs

13 The EMS/BMS Upgrade project is currently underway and scheduled for completion in 2019. This effort will limit the NYISO’s ability to make additional energy market modifications.

14 SRE commitments are at a unit’s Minimum Generation level. Additional, economic Incremental Energy dispatch from an SRE-committed unit is eligible to set price.

commitments do not use look-ahead modeling, but RTC and RTD will include SREs within their respective look-ahead optimization horizons.

The SRE process is described in the NYISO’s Transmission and Dispatching Operations Manual, Section 5.7.6, Supplemental Commitment Process:

The NYISO may use the SRE process to commit additional resources outside of
the SCUC and RTC processes to meet NYISO reliability or local reliability
requirements. Transmission Owners (TOs) may request the commitment of
additional generators to ensure local reliability in accordance with the local
reliability rules. The NYISO will use SREs to fill these requests by TOs. In
addition, Generator Owners may request the operation of a specific steam unit if
certain combustion turbines have an energy or a non-synchronous reserve
schedule that necessitates operation of the steam unit due to 24-hour NOX
Averaging Period requirements.

When the NYISO requests that generators submit bids in response to an SRE, ICAP suppliers must offer their available capacity unless an offer is pending in the Real Time market when the SRE request is made or the unit is unable to run due to an outage, operational issues or temperature derates. Special Case
Resources are not required to respond to SRE requests by section 5.12.1 of the Market Services Tariff. However, the NYISO may request SCR and EDRP resources to respond to SRE requests on a voluntary basis.

Since SREs are only performed to address reliability concerns, it is intended that
units committed by the SRE process fulfill their obligation by physically
operating.

NYISO Requests for SREs

The NYISO may perform SREs in response to the following [two] conditions:

1. When Day-Ahead reliability criteria violations are forecast after SCUC has

begun or completed its Day-Ahead evaluation (i.e.: too late for additional dayahead commitments).

2. When In-Day reliability criteria violations are anticipated more than 75
minutes ahead (i.e.: too early for RTC commit additional resources).

Additional commitment procedures that occur after SCUC and ordinarily after SREs

include the Real Time Commitment (RTC) and Real Time Dispatch (RTD). RTC executes every

quarter hour and includes a two-and-a-half hour look-ahead with advisory commitments over the look-ahead period. RTD follows RTC, and both optimizations utilize look-ahead capability.
The NYISO’s RTD executes every five minutes and includes a 55 to 65 minute look-ahead,
depending on the interval. The RTC and RTD look-ahead commitment processes are described in greater detail in the NYISO’s response to Look Ahead Modeling question 2(a), below.
From time to time, NYISO operations may implement the Real Time Dispatch -
Corrective Action Mode (RTD-CAM) when the need arises to respond to system conditions that were not anticipated by RTC or the regular RTD. RTD-CAM is used to deal with immediate
system issues quickly and was constructed to minimize execution time, thus RTD-CAM intervals do not utilize look-ahead modeling. RTC, RTD, and RTD-CAM are further described in the
NYISO’s response to Look Ahead Modeling question 2(a) below.

Manual commitments may also occur after SCUC runs. Such commitments are described in the NYISO’s answer to question 3 in the “Commitments to Manage Multiple Contingencies” section of this Report.

Commission Question

a. Please indicate whether the process uses look-ahead modeling solely as an

advisory tool for operators or, alternatively, whether the process uses look-ahead modeling to make actual commitment, dispatch, and pricing decisions. What is the time horizon considered by the look-ahead model? What are the
commitment/dispatch intervals considered by the look-ahead model? How
frequently does the model execute throughout the operating day (e.g., every 15 minutes, every 30 minutes)?

NYISO Response

The NYISO look-ahead modeling process instructs actual commitment and dispatch
decisions, while also providing resources with advisory prices and schedules. The Real Time
Commitment (RTC) program makes binding unit commitment and de-commitment decisions for
the periods beginning fifteen minutes (in the case of Resources that can respond in ten minutes)
and thirty minutes (in the case of Resources that can respond in thirty minutes) after the
scheduled posting time of each RTC run. RTC provides advisory commitment information for
the remainder of the two and a half hour optimization period, and produces binding schedules for
External Transactions to begin at the start of each quarter hour. RTC co-optimizes to solve
simultaneously for all Load, Operating Reserves and Regulation Service requirements and to
minimize the total as-bid production costs over its optimization timeframe. RTC considers
SCUC’s Resource commitment for the day, load forecasts from the load forecasting program and
loss forecasts that RTC itself produces each quarter hour, binding transmission constraints, and
all real-time Bids and Bid parameters. Advisory prices, as well as some of the binding external
proxy generator prices, are produced by RTC.

The NYISO’s Real-Time Dispatch (RTD) program does not make commitment decisions
and will generally not consider start-up costs in any of its dispatching or pricing decisions.15
Each RTD run co-optimizes to solve simultaneously for Load, Operating Reserves, and
Regulation Service and to minimize the total cost of production over its bid optimization
horizon. In addition to producing binding schedules and the majority of binding prices for the
next five minutes, each RTD run will produce advisory schedules and prices for the remaining

15 As explained in the NYISO’s response to Pricing of Fast Start Resources question 3(c), RTD considers the startup costs of non-committed 10-minute eligible resources that are qualified to set price.

four time steps of its bid-optimization horizon. RTD uses the most recent system information and the same set of Bids and constraints that are considered by RTC.

When the NYISO needs to respond to system conditions that were not anticipated by

RTC or the regular RTD, such as the unexpected loss of a major generator or transmission line, NYISO operators will activate the specialized RTD-Corrective Action Mode (RTD-CAM)
program. RTD-CAM runs are nominally either five or ten minutes long and, by design, do not include look-ahead capability in order to minimize execution time. Operators manually execute each RTD-CAM.. Unlike RTD, RTD-CAMs can commit 10-minute start resources. When RTD-CAM is activated, the NYISO has the ability to implement various measures to restore normal operating conditions. Section 6.2 of the NYISO’s Transmission and Dispatching
Operations Manual provides additional details on RTD-CAMs.16

16 Link to Transmission and Dispatch Operations Manual:

http://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_and_Guides/Manuals/Operations/tr
ans_disp.pdf

Commission Question

b. Please discuss whether and how look-ahead modeling affects real-time price
formation and/or operational efficiencies (especially with respect to the
commitment and pre-positioning of fast-start and flexible resources).

NYISO Response

i. Please explain whether and how the RTO’s/ISO’s look-ahead model pre-

positions the dispatch of resources in anticipation of system needs,

especially with respect to expected near-term needs for ramping

capability. Please explain whether and how the RTO’s/ISO’s look-ahead
model optimizes the commitment of resources in anticipation of system
needs.

Look-ahead features are part of both RTC and RTD, each of which are based on the minimization of production costs to meet power system needs through commitment of resources and ramping of resources. Achieving a least production cost commitment and dispatch requires recognition of inter-temporal constraints (e.g. ramp and minimum run time constraints). The RTC horizon is nominally two and a half hours and the RTD
optimization horizon is 55 to 65 minutes, depending on the interval. RTC and RTD
commit and dispatch to resolve anticipated inter-temporal constraints in the look-ahead intervals. RTC and RTD minimize costs over all look-ahead intervals, but only the first interval is binding. All other look-ahead intervals are advisory.

RTC may elect to commit or schedule otherwise uneconomic resources, including
generation and/or interchange, in order to ensure sufficient ramp capability is available to

meet anticipated changes in resource commitments/de-commitments, changes in load or transmission outages, with the goal of minimizing production costs over the entire lookahead interval. Likewise, RTD may elect to ramp otherwise uneconomic resources early in the hour-long optimization horizon in order to ensure sufficient ramp capability is available to meet anticipated changes due to resource commitments/de-commitments, load, interchange ramps or transmission outages.

ii. If the RTO/ISO uses look-ahead modeling to make unit commitment

decisions, how far in advance of real-time does the operator issue

commitment instructions? Does this time period for issuing commitment
instructions differ by resource characteristics, such as start-up time?

There are two mechanisms to get commitment decisions prior to the start of the Real-

Time Market. The first is the DAM which posts results by 11:00 on the day before the real-time operating day. The second is the SRE process, which can be engaged if unexpected conditions occur after the close of the DAM. If the SRE process is implemented, results are posted as soon as the decision is made by the operators.

RTC software makes commitment decisions in real-time. RTC makes binding unit

commitment and de-commitment decisions for the periods beginning fifteen minutes (in the case
of Resources that can respond in ten minutes) and thirty minutes (in the case of Resources that
can respond in thirty minutes) after the scheduled posting time of each RTC run. RTC provides
advisory commitment information for the remainder of the two and a half hour optimization
period, and produces binding schedules for External Transactions to begin at the start of each
quarter hour.

SCUC and RTC each take into account a generator’s start-up time. RTC can start-up generators with 30-mintue and 10-minute start-up times.

iii. Please explain whether and how look-ahead modeling affects real-time

prices. In this regard, please explain whether and how the look-ahead model calculates actual real-time prices, and whether and how constraints in future periods affect price formation.

The real-time price (LBMP) is calculated in RTD recognizing the inter-temporal

constraints, such as ramp constraints, expected future system topology changes (such as the

scheduled outage of a transmission line), future resource availability changes (such as the forced outage of a generator that received a Day-Ahead schedule), load changes, etc. Thus, future
constraints can affect the binding period real-time price.

Whenever there is an intertemporal constraint such that a change in future dispatch costs will occur due to a dispatch decision made in the initial time step, all of the incremental costs must be included in the price of the initial time step in order to properly evaluate whether the least-cost dispatch decision is made.

Consider a scenario with four generators that must be scheduled to minimize production
cost while respecting physical parameters including the Upper Operating Limit (UOL), minimum
generation limit and ramp rate of each generator. The look-ahead example in Table 1 (below) is
contrasted with examples that do not include look-ahead capability in Tables 2a and 2b. The
initial condition at 9:30 in Table 1 shows an incremental cost of $5.00, which is exactly the same
as the 9:30 interval in the set of conditions in Table 2a. The 9:45 interval in Table 1 has
incremental cost of $10.00 because Generator A has been dispatched upward to serve load; the

optimization horizon in the look-ahead case recognizes that Generator C must shut-down at

10:00 and Generator A is dispatched up in anticipation of Generator C’s shut-down.

Conversely, the case in Table 2a does not include Generator C turning off at 10:00 in its optimization horizon and thus does not move Generator A; the incremental cost calculated in Table 2a for 9:45 remains at $5.00 (slightly lower than Table 1). However, in Table 2b the 10:00 interval reflects a $25.00 incremental cost to commit Generator D in order to accommodate the shut-down of Generator C. The incremental cost in Table 2b is significantly higher than the
incremental cost in Table 1 for the 10:00 interval.

In the example, look-ahead modeling avoids the need to commit the quick start unit
(Generator D) to serve load, as well as the price spike associated with that commitment.

“With Look-Ahead” Table 1

“Without Look-Ahead” Table 2a

“Without Look-Ahead” Table 2b

iv. Please discuss whether and how look-ahead modeling can reduce out-of-
market commitments by operators.

Prepositioning the system to address anticipated future constraints can increase the

number of solutions available and thus reduce the need for out-of-market commitments. If the
NYISO did not have look-ahead modeling in RTC and RTD that incorporates ramp rates,
minimum run time, minimum down time, and other generator commitment parameters, the

NYISO’s operators would be required to intervene more frequently in the NYISO’s commitment and dispatch process.

v. Please explain whether and how look-ahead modeling provides greater

benefits when used to make actual market decisions rather than solely as an advisory tool for operators.

RTC and RTD minimize production cost over their respective evaluation horizons. Each
program makes market decisions. The look-ahead modeling sends the right signal to the
marketplace to preposition resources in anticipation of expected future events. Having RTC and
RTD utilize look-ahead modeling to make decisions allows the commitment and dispatch
process to build upon previous decisions. The market software with its look-ahead capability is
able to commit and dispatch more quickly, consider more variables and, generally, to realize a
lower total production cost relative to what an operator could achieve if the software was used
only as an advisory tool.

Incorporating look-ahead modeling into the market solution minimizes the manual

processes and operator decisions that would be required if look-ahead modeling is only used as
an advisory tool for operators. During dynamic system conditions and events it can be
challenging for operators to identify the appropriate commitments as quickly as an automated
market solution.

vi. Please discuss any other potential or actual benefits from look-ahead
modeling.

As explained above, look ahead modeling provides a more accurate representation of

system conditions and allows for the anticipation of ramp constraints, resulting in more accurate instructions to resources and more efficient scheduling with neighboring control areas.

Commission Question

3. Please describe any RTO/ISO and/or stakeholder initiatives or plans, if any, related to
look-ahead modeling. For any look-ahead modeling enhancements that the RTO/ISO
and/or its stakeholders are currently considering, please discuss any evaluation of the
costs and/or complexities of look-ahead modeling relative to its potential benefits,
and the estimated time frame for implementation of any look-ahead modeling
enhancements.

a. Are there any features of existing look-ahead models that could adversely affect
price formation (for instance, are there any instances in which existing look-ahead
model designs could lead to inaccurate price signals)? If so, please describe these
features in detail and discuss whether any improvements are warranted.

b. Please describe any other challenges, complexities, or practical limitations
associated with look-ahead modeling. Where possible, please provide
quantitative examples.

NYISO Response

As discussed in the NYISO’s response to Look-Ahead Modeling question 1, the “RTCRTD Forward Horizon Coordination Improvements” market design project slated for 2016 will be considering the slight modeling inconsistencies between the RTC and RTD look-ahead
evaluations that arise as the two programs evaluate external transactions and the start-up/shut-
down of gas turbines, and will investigate possible revision and adjustment of the look-ahead RTC and RTD evaluations to address the identified inconsistencies.

D.Uplift Allocation

Commission Questions

1. Please provide a high-level overview of the RTO’s/ISO’s existing framework for
allocating uplift charges (e.g., briefly explain the principles that guide the
RTO’s/ISO’s allocation of uplift charges and summarize at a high level how these
principles are applied in the day-ahead and real-time energy and ancillary services
markets).

NYISO Response

The NYISO’s cost allocation rules are designed to differentiate and categorize uplift costs
based on the underlying cause of such costs.17 In doing so, the NYISO identifies whether uplift
costs are attributable to actions taken to ensure statewide reliability or actions taken to address
local reliability.

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 (NYCA), while uplift costs associated with local reliability issues are allocated only to the load within the transmission district for which the local reliability actions were taken.18 Real-time uplift costs are allocated to the applicable loads on a Load Ratio Share basis, based on the actual real-time metered load during the hours in which such uplift costs were incurred.

17 As further described in its response to Transparency question 1, the NYISO provides regular reporting to its Market Participants and to the public detailing the categorization and assignment of various uplift costs.

18 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 based on cost causation principles. See Potomac Economics Price Formation Comments at 16-18.

Commission Questions

2. Please identify any specific areas where the RTO/ISO believes that its existing uplift
allocation methodology needs improvement. Please discuss these areas, along with
any RTO/ISO and/or stakeholder initiatives or plans aimed at improving uplift
allocation.

a. Please identify any specific transaction types, resource types, schedule deviations,
or other uplift drivers that cause uplift on a regular basis, but do not receive an
allocation of uplift charges under current market rules.

b. Please discuss the complexity of re-designing existing market rules and settlement
systems to better align uplift allocation with cost-causation principles. Please
provide a qualitative assessment of whether and how the potential benefits of
improved uplift allocation outweigh the cost and complexity of implementation
and application.

c. Commission staff’s 2014 paper on uplift noted that a small number of resources
receive the majority of uplift payments in every RTO/ISO. Additionally, PJM
asserts that existing uplift allocation rules likely mute investment signals due to
lack of clarity regarding where uplift payments are being received, and asks the
Commission to provide guidance on principles for uplift allocation. Please
identify any specific areas where the RTO’s/ISO’s current uplift allocation
methodology could potentially mute investment signals.

NYISO Response

The NYISO’s method is designed to allocate the cost of uplift to the customers that are

benefitting from the action that caused the uplift. The allocation of uplift to external transactions could be improved. The NYISO supports the reciprocal elimination of uplift and other fees
allocated to external transactions. The allocation of uplift and other fees reduces trade between regions and adversely impacts total production costs.

To ensure that its revenues cover the expected uplift costs and other transaction fees, a

Market Participant will submit an external transaction request when the expected price difference
between regions exceeds the expected total fees. In financial terms, the participant will
incorporate a margin into its offer to cover the expected fees. This rational behavior prevents
price convergence between regions. System costs will be higher than necessary because the

interties will tend to be under‐utilized, relative to external transaction volumes if there were no per‐megawatt transaction fees. In economic terms, transaction fees on external transactions act like a ‘hurdle’ that deters trade and distorts production costs upward.

Allocating uplift and other transaction fees to external transactions impedes price

convergence between regions and raises system production costs. The magnitude of the benefits to loads from eliminating an uplift allocation to external transactions, in the form of lower LMPs due to greater inter‐regional competition, could exceed the cost of uplift and transaction fees that must be recovered from other sources.

Other than addressing the allocation of uplift to external transactions, the NYISO has not identified any areas for improvement where its allocation of uplift mutes appropriate price or
investment signals. The NYISO has not identified any areas where the benefits of changing its uplift allocation methods would outweigh the costs associated with doing so. The NYISO
already identifies individual sources of uplift, down to specific operator actions or market
participant requests, to ensure that uplift is properly allocated, and continually seeks ways to
improve the transparency of the amount of uplift payments. Please see the NYISO’s response to Transparency question 2 for more details about how it reports on and assigns the costs associated with actions taken to protect system or local reliability.

The NYISO has a settlements simulator that allows it to understand expected settlement impacts before the NYISO proposes changes to its market rules. This settlement simulator has become an invaluable tool when the NYISO evaluates its hypothesis and rationale for changing market and/or settlement rules.

Commission Questions

3. Please explain the methodology by which the RTO/ISO allocates day-ahead and real-

time energy and ancillary services market uplift, including an explanation of whether
and how the allocation rules follow cost-causation principles. [fn. Please include in
this response a discussion of virtual transactions.] In this regard, please explain the
following (referencing specific charge codes to the extent that it is practical):

a. Explain whether and how day-ahead and real-time energy and ancillary services

market uplift is allocated to transactions that cause the commitment of resources that receive uplift payments;

b. Explain whether and how the RTO/ISO allocates real-time energy and ancillary

services market uplift to market participants’ deviations from day-ahead

schedules, and whether and how deviations that increase the need for actions that cause uplift (harming deviations) are netted against deviations that reduce the need for actions that cause uplift (helping deviations);

i. explain whether and how uplift related to real-time resource commitments for

transmission constraint management is allocated to schedule deviations;

ii. explain whether and how uplift related to real-time resource commitments for
system reliability is allocated to schedule deviations;

c.Explain the locational granularity with which this uplift is allocated (e.g., RTO-

wide, zonally);

i. explain whether and how uplift related to real-time resource commitments for

voltage and local reliability is allocated to local transmission areas or zones;

d. Explain whether day-ahead and real-time energy and ancillary services market

uplift is allocated on an hourly, daily average, or another basis;

e. Discuss and explain whether there are certain components of day-ahead and real-

time energy and ancillary services market uplift that cannot be allocated
consistent with cost-causation principles, and if so explain how these are
allocated;

f. Explain the conditions under which the RTO/ISO exempts from the allocation of

each charge any market participants, transactions, or schedule deviations that
would otherwise receive an allocation, and explain the rationale for such
exemptions.

g. Finally, list and explain the categories of transactions, or schedule deviations to

which the RTO/ISO allocates day-ahead and real-time energy and ancillary

services market uplift charges. For the period spanning October 1, 2014 through
September 30, 2015, report the share of day-ahead energy and ancillary services
market uplift (in percentage terms) allocated to each category. Similarly, report
the share of real-time energy and ancillary services market uplift allocated to each
category over the same time period. Do not identify any specific market
participants.

NYISO Response

The NYISO has three major categories of uplift:

1) Bid Production Cost Guarantees (BPCG) - both Day-Ahead and real-time: A make-

whole payment paid primarily to generators when a unit’s cost to run has exceeded its
LBMP + ancillary service revenue for the time period committed by the NYISO.
Generators must bid such that the NYISO commits the unit in order to be eligible to
receive a BPCG. Self-Committed generators are not ordinarily eligible for BPCG
payments.19

2) Day Ahead Margin Assurance Payments (DAMAP) - The NYISO will make a generator

“whole” to its Day-Ahead margin if the unit is committed in real-time and actions

required of the unit in real-time cause the Day-Ahead margin to be reduced. Reductions in Day-Ahead margins due to real-time dispatch instructions can result from a NYISO or Transmission Owner (TO) directive to deviate from the Day-Ahead schedule in real-time or from a change in the transmission system.

3) Supplemental Event Credits - Events such as large event reserve pickups and maximum

generation pickups that require generators to ramp to their maximum capability for a short window of time as required by NYISO Operations.

For the period of October 2014 through September 2015, the total uplift that was

allocated to NYISO markets is approximately $80 million, which is roughly 1.5% of the total

cost of the NYISO’s $5.2 billion energy market during the same time period. All cost

values/percentages in this discussion are based on this time period. The table below summarizes the categories and significant causes of NYISO uplift payments.

19 Generators that self-commit in real-time in order to start-up to meet a Day-Ahead schedule and generators that self-commit in response to an SRE request may remain eligible to receive BPCG.

NYISO Uplift Payments October 2014 - September 2015

% of Total Uplift

DA BPCG63%

- DARU35%

- Economic Commitment28%

RT BPCG34%

- SRE11%

- ISO Reliability Commitment3%

- TO Relibility Commitment7%

- Other3%

- Economic Commitment10%

Supplemental Event BPCG<1%

DAMAP2.5%

- ISO/ Other Relibabilty reasons1.50%

- TO Reliability1%

NYISO Uplift Total = $80M

NYISO Energy Market Total = $5.2B

The NYISO’s uplift cost allocation method is primarily based on a “beneficiary pays”
model. All uplift allocations are based on Load Ratios Shares (at different levels of granularity
that are discussed below) based on real-time physical Load. Allocations are based on either New
York Control Area (NYCA)-wide shares (including export and wheel-through transactions as
applicable) or subzonal Load Ratio Shares. The NYISO is made up of 11 zones and 23
subzones. The subzones are areas of load broken up by the service districts of the local
Transmission Owners (TOs) operating in the particular zone. Costs are allocated NYCA-wide if
the cause of the uplift was a NYISO directive to address state-wide reliability, or to local
subzone if the local TO directed the action. In either case, the cost allocation is based on a pro-
rata allocation of the responsible LSEs’ Load Ratio Shares in the relevant area (all NYCA or
local). This means that Day-Ahead and Real-Time energy and ancillary services Market uplift is

not allocated to the transactions that cause the commitment of resources, but rather is allocated to the Load that benefits from the commitment of the resources.

While the NYISO allocates all components of energy and ancillary service market uplift
using the “Beneficiary Pays” model, external transactions scheduled as part of Coordinated
Transaction Scheduling (CTS) with ISO-NE are exempt from such allocations. That initiative
reciprocally eliminated all NYISO and ISO New England fees on CTS transactions between the
two control areas. As discussed in the NYISO’s answer to Uplift question 2, the NYISO
supports the reciprocal elimination of uplift and other transaction fees on exports because these
fees reduces trade between regions and adversely impact total production costs.
The assignment of uplift based on deviations from schedules is a key subject in the
Commission’s question 3(a) and 3(b)(i) and (ii). The NYISO’s market structure has only one
payment that links Day-Ahead schedules to real-time output, which is the DAMAP. Otherwise,
settlements for the Day-Ahead and Real-Time Markets are not coupled. Any uplift resulting
from an action taken in the Day-Ahead Market is borne by Day-Ahead load and transactions.
Any uplift arising in the Real-Time Market is borne by real-time load and transactions.
The NYISO manages schedule deviations in several ways. For deviations where a
generator exceeds its real-time schedule, the generator will only be paid for energy produced in
excess of its schedule up to 3% of its Upper Operating Limit (UOL). Generators that
consistently produce less energy than they are scheduled to produce in real-time may be assessed
an under generation penalty.20 In addition, generators that do not produce the MWs they were
scheduled to provide Day-Ahead in real-time are subject to a balancing obligation.

20 See Services Tariff Sections 15.3.5.3, 15.3.5.5.1, 15.3.5.5.2 and 15.3A.1.
46

BPCG Discussion

Bid Production Cost Guarantees (BPCGs) are uplift payments made when a generator’s
revenues from Energy and Ancillary Services (Regulation, Reserves, and Voltage Support) do
not at least equal its bid cost of providing those products for a given commitment day. There are
different reasons why BPCG payments may be necessary, but the payments often result when a
generator is committed to address a reliability need via one of the following commitment
methods, Local Reliability Rules (LRR), Day-Ahead Reliability Unit (DARU), Supplemental
Resource Evaluation (SRE), or Out-of-Merit Generation (OOM). It is not unusual for a unit to
be committed economically for start-up and for a portion of the day, but to still receive a BPCG
settlement for the day as a result of changing conditions over the course of the day, or as a result
of minimum run time and/or minimum down time requirements that require a Generator to run at
times when its operating costs exceed the LBMP. Since BPCG is determined over the course of
the day and not a smaller time period, it is quite possible for a generator to receive a BPCG
payment and still be part of the “least cost” commitment solution.

Day Ahead BPCG may be paid to generators that were committed economically in the
Day-Ahead Market, but where the LBMP and ancillary service revenues produced for the entire
commitment period are not sufficient to cover the generator’s full cost of operation. Day-Ahead
BPCG represents approximately 63% of the NYISO’s total market uplift. The uplift cost
associated with economic commitments is approximately 27% of NYISO’s total market uplift
(and 43% of total Day-Ahead BPCG payments). Day-Ahead BPCG is also paid to generators
that are committed through the DARU process. The DARU process identifies generators that are
needed for reliability, and commits them if they are not committed economically in the Day-

Ahead Market.21 DARU units are eligible to receive a Day-Ahead BPCG if their bid costs

exceed their LBMP and ancillary service revenues for the commitment day. The cost of DARU commitments (which are frequently requested to address local reliability) are allocated based on subzonal Load Ratio Shares. DARU uplift costs represent 56% of Day-Ahead BPCG and 35% of the total NYISO market uplift.

As with Day-Ahead BPCG, real-time BPCG compensates generators for costs to run that
are not recovered through LBMP or ancillary service revenues. Unlike Day-Ahead BPCG, costs
for real-time BPCG are allocated based on the source of the commitment that required the unit to
run. For example, when a generator that is committed at the request of a Transmission Owner to
address a reliability need, either via an SRE22 or OOM,23 any resulting BPCG costs are allocated
to the subzone that the generator is located in. When the NYISO commits a generator in real-
time to address a statewide reliability need, the uplift costs associated with that commitment are
allocated NYCA-wide, irrespective of the location of the unit being committed.

OOM commitment and redispatch occur more frequently than SRE commitments and

OOM status can be used to address a more diverse set of reliability concerns. However, OOM is not as significant a cause of uplift as SRE or DARU. Some of the common OOM types that are used to commit, de-commit or redispatch generators include:

21 Section 1.4 of the NYISO OATT defines a DARU as “A Day-Ahead committed Resource which would not have been committed but for the commitment request … in order to meet the reliability needs of the …system which request was made known to the ISO prior to the close of the Day-Ahead Market.”

22 Section 1.19 of the NYISO OATT defines an SRE as “a determination of the least cost selection of additional
Generators, which are to be committed, to meet: (i) changed or local system conditions for the Dispatch Day that
may cause the Day-Ahead schedules for the Dispatch Day to be inadequate to meet the reliability requirements of
the Transmission Owner’s local system or to meet Load or reliability requirements of the ISO; or (ii) forecast Load
and reserve requirements over the six-day period that follows the Dispatch Day.” Uplift resulting from an SRE
commitment may be allocated statewide or to a local transmission zone, depending on the reliability need that
required the commitment.

23 Section 1.15 of the NYISO OATT defines OOM as “[r]esources committed and/or dispatched by the ISO at specified output limits for specified time periods to meet Load and/or reliability requirements that differ from or supplement the ISO’s security constrained economic commitment and/or dispatch.”

Committed for ISO Reliability

Committed for TO Reliability

Generator Request (various reasons)24

Operator Intervention (various reasons)25 Start Up/ Shut Down

For the purposes of this discussion, the NYISO addresses the two reliability based OOM
categories because those are the two categories that commonly generate uplift. Real-time BPCG
resulting from OOM reliability commitments OOM dispatch limitations reflects approximately
10% of uplift for the time period discussed. Approximately 3% of real-time uplift is related to
ISO reliability commitments, while the remaining 7% is attributable to Transmission Owner
reliability commitments.

Day-Ahead Margin Assurance Payments

In certain instances, if a generator with a Day-Ahead energy, regulation, or operating reserves schedule is required to buy out of those schedules in real-time, a Day-Ahead Margin Assurance Payment (DAMAP) is available to protect the generator’s Day-Ahead margin. Section 25.1 of the Services Tariff states:

The purpose of [DAMAP] is to protect Suppliers’ Day-Ahead Margins associated
with real-time reductions after accounting for: (I) any real-time profits associated
with offsetting increases in real-time Energy, Regulation Service, or Operating
Reserve schedules; and (ii) any Supplier-requested real-time de-rate granted by
the ISO.

24 Generator requested OOM operation often occurs to address generator that is not able to operate within its normal operating limits. The NYISO has specific tariff rules in place to limit the potential for generator-requested changes to operating parameters to cause uplift. See the NYISO’s August 22, 2008 filing in FERC Docket No. ER08-1438, which was accepted in a Letter Order issued on September 18, 2008.

25 NYISO operators may use OOM to address generators that are not responding to dispatch instructions. See the NYISO’s August 22, 2008 filing in FERC Docket No. ER08-1438, which was accepted in a Letter Order issued on September 18, 2008.

An example of a circumstance which may result in an obligation to pay DAMAP is when
real-time operations diverge from what was expected Day-Ahead. For example, Gas Turbines
(GTs) generally have minimum down times. If the NYISO economically commits a GT to run in
real-time, after the GT is turned off it may no longer be able to return to satisfy its Day-Ahead
schedule (for energy or non-synchronous reserves) and must “buy out” of its Day-Ahead
schedule at real-time prices (it has a balancing obligation). In this circumstance, the NYISO will
make the generator “whole” to its Day-Ahead margin by paying a DAMAP for the affected
hours.

DAMAP is allocated based on the reason the generator diverged from its Day-Ahead

schedule. If a Transmission Owner took an action that prevented a generator from operating to
achieve its Day-Ahead schedule, the associated de-rate is allocated via subzonal Load Ratio
Shares. Other causes of DAMAP are allocated NYCA-wide based on Load Ratio Shares.

DAMAP payments comprise only 2.5% of total market uplift for the period in question. Of that, roughly one-third of the DAMAP uplift is associated with local reliability requests, with 51% of DAMAP payments (~1% of total uplift) being the result economic commitments or
NYISO reliability calls. The remaining DAMAP costs resulted from unusual OOM
commitments or dispatches. Examples of these types of unusual commitments or dispatches
include generator request to modify their Upper Operating Limit due to real-time conditions,
generators that are set OOM for testing, or generators that are set OOM to permit the NYISO to conduct an audit of the generator’s capabilities.

Supplemental Event Credit

For intervals in which the ISO has called a large event reserve pick-up or a maximum

generation pickup, any Supplier who meets certain eligibility requirements26 is eligible to receive
a special interval-level BPCG. Large event reserve pick-ups are not uncommon, but are usually
limited to short durations.27 The real-time BPCG costs associated with supplemental events
represent less than 0.5% of all uplift payments. All supplemental events are allocated NYISO-
wide, as only the NYISO operators can initiate a large event reserve pick-up or a maximum
generation pickup.

Commission Questions

4. Some commenters suggest that MISO’s uplift allocation methodology matches cost-
causation principles and represents an industry best practice.

a. Please discuss the advantages and disadvantages of MISO’s approach, and discuss
whether it represents an industry best practice.

b. Please discuss whether other RTOs/ISOs should create allocation categories that
relate to the underlying causes of uplift, and how these categories should be
defined. Discuss the types of uplift costs that can be assigned to cost-causation
categories. What types of uplift costs, if any, cannot be readily assigned such
categories? Why are such uplift costs difficult to categorize in accordance with
cost-causation?

NYISO Response

The NYISO is not familiar enough with the MISO uplift allocation methodology to

discuss the MISO uplift allocation methodology in detail. The NYISO allocates uplift costs

consistent with “beneficiaries pay” principles (i.e., those receiving the benefits of a given action

26 See Services Tariff Section 18.5.1.

27 During the period discussed in this response (October 2014 through September 2015) there were 121 cases of reserve pick-ups and no maximum generation pick-ups. The reserve pickups normally impacted individual 5 minute intervals, resulting in minimal uplift payments.

ultimately bear its costs), which is consistent with the recommendations of Potomac

Economics.28 Similar to the MISO, the NYISO categorizes uplift costs based on the underlying cause and then allocates costs based on cost causation principles. 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 district for which the local reliability actions were taken.

Commission Question

5. Please discuss other potential approaches to allocating uplift charges based on cost-
causation, and explain the potential advantages and disadvantages of such
approaches.

NYISO Response

The NYISO is not familiar enough with uplift allocation approaches that differ from the approaches that the NYISO employs to discuss the potential advantages and disadvantages of such alternative approaches.

Commission Questions

6. Some commenters argue that allocating uplift charges to virtual transactions reduces
the volume of such transactions, thereby impeding the convergence of day-ahead and
real-time energy prices, while other commenters argue that RTOs/ISOs should
allocate a portion of uplift charges to virtual transactions.

a. Please discuss whether and how the RTO’s/ISO’s uplift allocation methodology
nets virtual transactions or other deviations from day-ahead schedules for
purposes of allocating uplift charges. Please discuss the advantages and
disadvantages of such practices in the context of cost causation and the
convergence of day-ahead and real-time prices.

28 See Potomac Economics Price Formation Comments at 16-18.
52

b. Please discuss the advantages and disadvantages of allocating to virtual

transactions a portion of the uplift charges associated with the day-ahead market alone (and not allocating to virtual transactions any uplift charges associated with the real-time market), and whether such an approach is consistent with cost-
causation principles.

NYISO Response

Virtual bidding should improve price convergence by correctly incentivizing Virtual

Loads to only purchase when Day-Ahead prices are expected to be lower than real-time prices -
thereby by helping Day-Ahead Market and Real-Time Market prices converge. A Virtual
Supply transaction will make money if it is sold in an hour and at a location where the Day-
Ahead price is higher than real-time price, thereby also aiding the convergence of the Day-Ahead and Real-Time Markets.

Uplift is generally not allocated to Virtual Load because it is not the beneficiary of the

action that generated the uplift and because in well structured markets Virtual Loads do not have incentive to impact uplift. Excessive scheduling of Virtual Load could drive the commitment of more Day-Ahead generation than is necessary to meet the real-time Load. In this case, the
Virtual Load should be purchasing energy at a higher Day-Ahead price than the real-time price it is selling back its energy at. Allocating additional uplift to this transaction could increase the
cost of this ‘bad deal,’ but that allocation would also increase the cost for Virtual Load
transactions that improve convergence between Day-Ahead and real-time prices, and therefore improve the NYISO’s Day-Ahead commitment.

Excessive scheduling of Virtual Supply could cause insufficient generation to be

committed in the Day-Ahead Market. The NYISO protects against this possibility by including
an integrated forecast load commitment pass in its Day-Ahead Market that commits sufficient
generation to meet the next day’s load forecast. Because it is possible that Virtual Supply would

impact the need for reliability commitments, Virtual Supply is allocated a portion of the uplift that is caused by Day-Ahead forecast load commitments.

However, the majority of uplift results from physical dispatch. Therefore, from a cost-
causation standpoint there is no real benefit to allocating uplift costs to Virtual Load or Virtual
Supply transactions.29 It would not be appropriate to allocate physical uplift to Virtual Load,
even though the commitment of Virtual Load has an impact on Day-Ahead to real-time price
convergence.

E.Transparency

Commission Question(s)

1. Please provide an up-to-date description of the RTO’s/ISO’s efforts or plans, if any,
to address any RTO/ISO-specific transparency shortcomings. Are there any
RTO/ISO and/or stakeholder initiatives to improve the transparency of data released
publicly about uplift, operator actions, and other changes to the market parameters
that can affect market clearing prices? If so, please describe any plans and related
timelines.

NYISO Response

Over time, the NYISO has revised and enhanced its data reporting and the format in

which such information is presented based on feedback from stakeholders and based on its own
internal review. Such enhancements are aimed at improving clarity and making data and
information more readily accessible and easily comprehensible. For example, the NYISO’s

29 There is minimal uplift (forecast BPCG) allocated to Virtual Load, but it is insignificant compared to total uplift.
The total uplift costs related to forecast deviations is approximately $53 thousand during the period in this
document. This is not a significant amount as compared to the $80 million in total uplift for the reported period.

Market Operations Report30 and Operations Performance Metrics Monthly Report31 report

provide a monthly rundown on the causes and amount of uplift. Other reports are covered in the NYISO’s responses to Transparency question 2, below.

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. The push towards
increased transparency is both for publicly available data and for individual stakeholder data.

For example, the NYISO’s 2015 projects included the ICAP Reference System Phase 2 project that streamlined the data collection process and provided increased transparency to
stakeholders of the Capacity Market references. The NYISO also completed a Public Website Renewables Page project that developed a new page on the NYISO public website where
renewable energy data is displayed, showing current activity and trends of renewable energy production and provides historical data.

The NYISO has additional efforts planned in 2016 to increase transparency. The

Settlement Sub Accounts project is intended to provide more transparency in the settlement data
visible to Financially Responsible Parties. This project will provide additional reporting by
allowing accounts to be split into multiple sub accounts, down to a bus level of granularity.
The NYISO is currently soliciting market participant feedback to better understand areas of opportunity for further improving data transparency. If opportunities are identified, it is

30 The Market Operations Report is presented at each monthly Business Issues Committee meeting. The January 2016 report can be found at:

http://www.nyiso.com/public/webdocs/markets_operations/committees/bic/meeting_materials/2016-01-
13/Market%20Operations%20Report_%20BIC_01%2013%2016.pdf

31 The Operations Performance Metrics Monthly Report is presented at each monthly Management Committee meeting. The January 2016 report can be found at:

http://www.nyiso.com/public/webdocs/markets_operations/committees/mc/meeting_materials/2016-01-
27/Agenda%2003_Operations_Report.pdf

expected that this effort will be prioritized to be worked on in 2017 by the NYISO’s Market Participants.

Commission Question(s)

2. Please describe how and the degree to which the RTO/ISO reports the specific
reasons for uplift and operator actions. Please also respond to the following:

a. Are there particular uplift or operator action categories that could be refined or

disaggregated to improve transparency about the underlying reasons for uplift? If so, please describe.

b. Please also describe the tradeoffs involved in refining uplift categories.

c. Calpine recommends that RTOs/ISOs report the hourly MW and the duration of
the uneconomic dispatch each time a resource is committed out-of-market. Please
report on whether sharing each element (hourly MW and duration of uneconomic
dispatch, to the extent known) is feasible shortly after uneconomic unit
commitments are made; and if it is not feasible, please explain the existing
barriers.

NYISO Response

The NYISO reports on the specific reasons for uplift and operation actions in multiple
ways with different levels granularity and analysis. The NYISO posts operational
announcements including operator initiated out-of-market actions as well as other operating
modes (ex. large event reserve pickups). Each items is time stamped and, for out-of-market
actions (including DARU, SRE and OOM actions) includes the unit(s) involved, the level of
individual unit commitment, and the reason for the commitment. The posting also includes a
reference to the relevant Application of NYSRC Reliability Rule (“ARR”) number, if
applicable.32

32 List of ARRs posted on NYISO’s web site:

http://www.nyiso.com/public/webdocs/markets_operations/market_data/reports_info/TO_Application_of_Reliabilit
y_Rules.pdf

The Operations Performance Metrics Monthly Report that is presented at the NYISO’s Management Committee meetings 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.

In addition to the announcements and reports described above, the “Value of Markets” page on the NYISO’s web site provides information on uplift as a percentage of total monthly energy costs.33

33 Link to Value of Markets page on NYISO web site: https://home.nyiso.com/value-of-markets/
57

Commission Question(s)

3. PJM notes that certain information that is currently considered commercially-

sensitive by market participants may not actually be commercially sensitive. Under
section 18.17 of its Operating Agreement, PJM can only post non-aggregated
commercially-sensitive offer data approximately four months after bid and offer data
were submitted and at a locational level no more granular than zonal. Are there any
RTO/ISO tariff provisions that restrict the release of uplift category information
(location, speed, frequency, or driver) beyond what is needed to protect confidential
information?

NYISO Response

The NYISO is not aware of any tariff provisions that restrict its release of uplift category information (location, speed, frequency, or driver) beyond what is needed to protect Confidential Information and Protected Information. The NYISO reports on local reliability commitment hours and montly local reliability commitment costs by load zone. However, the NYISO does not publically provide unit specific uplift costs.

Similar to PJM, Section 12.4 of the NYISO OATT treats as confidential “any

commercially sensitive information including, without limitation, trade secrets, equipment
specific information (e.g., Generator specific data such as heat rates, etc.), and business
strategies, affirmatively designated as Confidential Information by its supplier or owner.”

The NYISO does not treat any of the information it posts in operational announcements as confidential. The NYISO’s operational announcements34 ordinarily include the reason for each commitment and the level of individual unit commitments.

34 The NYISO’s operational announcements can be found on its website:

http://www.nyiso.com/public/markets_operations/market_data/reports_info/index.jsp The user must select the
Operational Announcements checkbox to see the reports.

Commission Question(s)

4. How frequently should categories of incurred uplift charges be shared with market

participants? How promptly should categories of incurred uplift be shared with market participants?

a. Is it feasible to disclose uplift or operator actions (including MWs and expected
duration), as soon as or shortly after the commitment is made (whether in real-
time, if the commitment of uneconomic units is made in real-time, or shortly after
the close of the day-ahead market, if the commitment is made day-ahead), while
disclosing the reason for that uplift or operator action at a later time once the
RTO/ISO has been able to determine the cause? Is releasing this information
feasible while protecting confidential information? What protections are
required?

b. If it is feasible to release this information as soon as it is known in real-time, is it
also feasible to release the information at a zonal level in real- time? Does
reporting real-time zonal information address concerns about protecting
confidential information? More specifically, please respond to the following
questions:

i. Is zonal reporting of individual uplift categories feasible and is zonal reporting

the appropriate geographic level for uplift reporting? If not, what is the

appropriate geographic granularity for reporting uplift categories?

ii. Can zonal reporting of each uplift category be accomplished without revealing
proprietary information?

iii. Are there any uplift categories for which zonal reporting would not send a
sufficiently granular signal? (For example, is zonal reporting sufficiently

granular for uplift related to local voltage support?)

NYISO Response

The NYISO currently releases the costs and categories of incurred uplift charges monthly
in the NYISO’s operations performance metrics reports. As covered in the NYISO’s response to
Transparency question 2(a)-(c) above, the NYISO also posts information on operator actions
shortly after out-of-market actions are taken. The aggregated dollar costs of uplift are available
to stakeholders on a daily basis though the daily reconciliation reports. Disclosing the costs of
uplift more frequently than daily might risk releasing generator-specific confidential information
because in some hours only one generator is the subject of an out-of-market action that generates
uplift.

Uplift, generated from the payment of Bid Production Cost Guarantees (BPCGs), is a daily payment. BPCGs are calculated over the course of 24 hours. Hours in which profits are made offset hours in which the unit incurs a loss. It is not possible to accurately report on BPCG uplift on a more frequent basis than daily.

Zonal reporting is feasible in some limited instances but not in others because some local
reliability commitment impact so few generators that disclosing the information would release
confidential data. The NYISO has not identified any areas where information is insufficiently
granular.

Commission Question(s)

4. How frequently should categories of incurred uplift charges be shared with market
participants? How promptly should categories of incurred uplift be shared with
market participants?

c. PSEG Companies recommend that RTOs/ISOs never provide unit-specific
information about bidding levels, but instead provide uplift cost information
categories that are both narrow enough to be useful and broad enough that
individual unit profiles cannot be discerned.35 To what degree is that principle
(adjusting the dissemination of uplift information, as needed, to protect
confidential information), one which can be applied in real-time or immediately
after the close of a market in order to adjust regular reporting requirements?

NYISO Response

The releasing of uplift cost information in real time does not obviate the concerns about
the release of Confidential Information because out-of-market commitments can be infrequent
enough that the uplift payment could be tied to a specific generator and reveal its costs. With the
MW commitment (provided by the operational announcements) there would be enough

35 PSEG Companies Comments at 10; see also Western Power Trading Forum Comments at 8.
60

information to calculate marginal costs in certain circumstances, which are commercially sensitive and considered Confidential Information under the NYISO’s tariffs.36

Commission Question(s)

5. PSEG Companies suggest that NYISO’s specific uplift reporting practice may

represent a “best practice.” This reporting includes: (1) all operator-initiated out-of-
market actions in the daily operational announcements that are released as the actions
are taken; (2) which units are involved; (3) the level of the individual unit
commitment; and (4) the time of the actions. Are the speed, level of unit-specific
detail (excluding payment information), and geographic granularity of this uplift
reporting simultaneously feasible in other RTOs/ISOs? If not, to what degree could
the RTO/ISO improve the speed and granularity of its out-of-market commitment and
operator action reporting to approach NYISO’s level of transparency in reporting
real-time uplift?

NYISO Response

The NYISO appreciates the PSEG Companies identifying the NYISO uplift reporting practice as a “best practice.”

Commission Question(s)

6. Direct Energy contends that unexpected operator actions, when needed, should be
made pursuant to predictable protocols that are known to market participants.
Calpine argues that models or algorithms used to determine operator actions, as well
as any non-market changes to model inputs or results, should be transparent and
publicly disclosed.

a. Please explain the RTO’s/ISO’s process for releasing changes to market models
(such as revising assumptions about constraints or adding new closed-loop
interfaces). What factors does the RTO/ISO consider when determining whether
or not to release information about changes to market model inputs?

b. Does the RTO/ISO release this information to all market participants?

c. What limits are necessary prior to disseminating changes to the RTO/ISO market
model?

36 The LBMP at the generator’s location plus the uplift paid would give a good indication of the generator’s operating costs at a given level of dispatch.

NYISO Response

The NYISO works with its Market Participants via its stakeholder meetings when it plans
to make significant changes to its market models. During these meetings the NYISO identifies
the drivers for the change, the expected market impacts and the timeframe for implementing the
change.

The NYISO has found this process beneficial. Stakeholders have helped improve upon
the NYISO’s proposed market model assumptions. For example, when the NYISO rolled out
how it intended to implement the Lake Erie Circulation adjustment Market Participant feedback
helped ensure that the adjustments NYISO implemented are transparent to the marketplace.

The table below captures operators actions or algorithms to model factors that could affect the scheduling of resources.

Operatora) Process to Releaseb) Released to allc) Necessary

ActionChangeMPsLimits

DARUsPosted to operationalYesSome DARU

announcements, see Dayinformation is

Ahead Scheduling manual37posted earlier

SREsPosted to operationalYesNone

announcements

OOMsNoneNo: confidentialNone

generator

37 Day-Ahead Scheduling Manual section 4.2.6 Day-Ahead Reliability Unit (DARU) Commitment, Transmission owner requests for DARUs:

http://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_and_Guides/Manuals/Operations/d
ayahd_schd_mnl.pdf

information

TSAsPosted to NYISO Main pageYesNone

PARPosted to PAR Schedules andYesNone

optimizationPAR Flows

TLRsManual override ofNo: only MPNone

transactionssubmitting the

transaction can see

the change

Circulation -Posted to Power Grid DataYesTypically done

UnscheduledInterface Pricing38weekly with

Power Flowability to update

as needed

Central EastPosted with DAM ScheduledYesNone

Capacitors foroutages

DAM

MaintenancePosted as part of activeYesNone

contingenciesconstraints if binding

Transaction cutsManual override ofNo: only MPNone

transactionssubmitting the

transaction can see

the change

Reserve pickPosted to operationalYesNone

upsannouncements

System StatePosted to operationalYesNone

changesannouncements

SCR activationPosted to operationalYesNone

announcements

38 Link to Interface Pricing Expected Unscheduled Power Flows:

http://www.nyiso.com/public/webdocs/markets_operations/market_data/power_grid_info/DAM_UPF_Web_Posting
.pdf

III.CONCLUSION

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 the responses it
provided in this Report in determining what, if any, actions it should take in this proceeding.

Respectfully submitted,

/s/ Alex M. Schnell
Alex M. Schnell

Assistant General Counsel/Registered Corporate Counsel

New York Independent System Operator, Inc.

10 Krey Blvd.

Rensselaer, New York 12144 (518) 356-6000

aschnell@nyiso.com

Dated: March 4, 2016

cc:Michael Bardee

Anna Cochrane
Kurt Longo
Max Minzner
Daniel Nowak
Larry Parkinson

J. Arnold Quinn
Douglas Roe

Kathleen Schnorf
Jamie Simler
Gary Will

CERTIFICATE OF SERVICE

I hereby certify that I have this day served the foregoing document upon each person

designated on the official service list compiled by the Secretary in this proceeding in accordance with the requirements of Rule 2010 of the Rules of Practice and Procedure, 18 C.F.R. §385.2010.
Dated at Rensselaer, NY this 4th day of March, 2016.

/s/ Mohsana Akter

Mohsana Akter

New York Independent System Operator, Inc.

10 Krey Blvd.

Rensselaer, NY 12144 (518) 356-7560