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TED J. MURPHY

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EMAIL: tmurphy@hunton.com

November 30, 2010FILE NO: 55430.000063

By Electronic Submission

The Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E.

Washington, D.C. 20426

Re: New York Independent System Operator, Inc., Tariff Revisions to
Implement Revised ICAP Demand Curves for Capability Years
2011/2012, 2012/2013 and 2013/2014, Docket No. ER11-___-000

Dear Ms. Bose:

In accordance with Section 5.14.1.2.11 of its Market Administration and Control

Area Services Tariff (“Services Tariff”) and Section 205 of the Federal Power Act, the New
York Independent System Operator, Inc. (“NYISO”) hereby submits amendments to
Section 5.14.1.21 of its Services Tariff to define the Installed Capacity (“ICAP”) Demand
Curves for Capability Years 2011/2012, 2012/2013 and 2013/2014.2 This filing presents the
results of the periodic review of the ICAP Demand Curves specified in Section 5.14.1.2.11.

The ICAP Demand Curves have now been used for many years in the NYISO-

administered ICAP Spot Market Auctions and are a central element to the overall design of
the NYISO’s capacity market. The NYISO and its Board of Directors (“Board”) are fully
committed to utilizing the prescribed process to ensure that the ICAP Demand Curves
promote the appropriate price signals to existing Capacity market participants and to
potential new entrants, encouraging efficient investment in generation capacity. The ICAP
Demand Curves proposed in this filing represent the outcome of an extensive stakeholder
process and exhaustive analysis by the NYISO’s consultants (as defined below, the

1 Section 5.14.1.2 was Section 5.14.1(b) prior to the NYISO’s submission of its baseline e-
tariff filing. The NERA/S&L Report refers to the Section using the prior numbering.

2 Capitalized terms that are not specifically defined in this filing letter shall have the meaning set forth in the Services Tariff.

The Honorable Kimberly D. Bose November 30, 2010

Page 2

“Consultant”), its staff, and Board of Directors as well as the input of the NYISO’s

independent Market Monitoring Unit (“MMU”). They are also informed by the NYISO’s experience with the currently effective and prior Demand Curves.

The process began with stakeholder review of and input on the request for proposals
issued to select an independent consultant. The selected Consultant conducted a thorough
analysis supported by input from NYISO staff, stakeholders, and the independent MMU,
written and oral comments and discussions on the Consultant’s draft and final reports, and on
the NYISO staff’s draft and final reports. The Consultant’s report with conclusions and the
NYISO staff’s report and recommendations (“NYISO Report”) were reviewed by the
independent MMU and the Board of Directors. There also were fully transparent, extensive,
written and in-person oral comments to, and discussions with, the Board of Directors by
interested stakeholders. The process also included multiple discussions by the Board with
the staff and the independent MMU, resulting in the Board of Directors’ determination at its
meeting on November 16, 2010 to approve the recommendations set forth in the NYISO’s
Report and to authorize this filing with the Federal Energy Regulatory Commission
(“Commission”).

The NYISO believes that the proposed ICAP Demand Curves are both reasonable and
consistent with the underlying objectives for which ICAP Demand Curves were originally
implemented. The Commission should approve the proposed curves as just and reasonable.

I.CONTENTS OF THE FILING

•This filing letter;

•A clean version of the revisions to the Services Tariff;

•A blacklined version of the revisions to the Services Tariff;

•Affidavit of David B. Patton, Potomac Economics, Ltd., independent MMU

(Attachment 1);

•Affidavit of Eugene T. Meehan, NERA (including NERA/S&L Report dated

11/15/10) (Attachment 2);

•Affidavit of David Lawrence, NYISO (including NYISO Report dated

10/30/10) (Attachment 3).

The Honorable Kimberly D. Bose November 30, 2010

Page 3

II.BACKGROUND AND SUMMARY

Section 5.14.1.2 of the Services Tariff requires the NYISO to perform a review of the
ICAP Demand Curves every three years to determine the parameters of the ICAP Demand
Curves for the next three Capability Years. In accordance with the Services Tariff
provisions, in the third quarter of 2009 the NYISO solicited proposals from qualified
Consultants to identify appropriate methodologies and to develop the ICAP Demand Curve
parameters for the three Capability Years beginning in May 2011 for New York City
(“NYC”), Long Island (“LI”), and the New York Control Area (“NYCA”).3 The NYISO
selected the team of National Economic Research Associates, Inc. (“NERA”), with Sargent
and Lundy (“S&L”) as a subcontractor to NERA (collectively, “the Consultant”). The
Consultant began the analysis in December 2009 and participated in thirteen Installed
Capacity Working Group meetings between December 2009 and August 2010, during which
the Demand Curve reset was discussed and developed. At each of these meetings, and
through written comments, stakeholders provided comments to the Consultant on the
Consultant’s assumptions, analysis, estimates, and preliminary results. Based on comments
received, the Consultant adjusted its assumptions and methodologies as appropriate, and
responded to the comments. On July 1, 2010, the Consultant released a first draft of its
report for stakeholder review and comment. The final version was released on September 3,
2010 with a revision on September 7, 2010 (“NERA/S&L Report”).4

On September 3, 2010, as amended on September 7, 2010 and October 30, 2010,5 the
NYISO staff submitted to the NYISO Board of Directors a report which included its
recommendations for the ICAP Demand Curve parameters, the underlying assumptions
utilized in formulating the recommendations, and the three ICAP Demand Curves (“NYISO

3 NYC and LI are currently the two “Localities” within the NYCA. See Services Tariff

§ 2.12. The term Rest of State refers to capacity supplies located in the part of the NYCA outside of the NYC and LI Localities. See Services Tariff § 2.18.

Independent System Operator,” September 3, 2010 (revised September 7, 2010), prepared by NERA Economic Consulting, available at

http://www.nyiso.com/public/webdocs/committees/bic_icapwg/meeting_materials/2010-09-
16/Demand_Curve_Study_Report_9-3-10_clean.pdf.

5 In October 2010, S&L informed the NYISO that a revision was necessary to the CO

emissions rate for the LMS100 combustion turbine, based on discussions with the manufacturer. The manufacturer informed S&L that it planned on updating the software the manufacturer provides for calculating CO emissions, which is software S&L had used in its computations. The NYISO’s
recommendations and the NYISO Report were updated to reflect the addition of oxidation catalysts to the NYC and LI LMS100 peaking units.

The Honorable Kimberly D. Bose November 30, 2010

Page 4

Report”).6 The NYISO Report represents the inclusion of a number of stakeholder

recommendations throughout the reset process, some of which are noted herein.7 The

proposed ICAP Demand Curves would be applicable for the three Capability Years

beginning May 1, 2011 through April 30, 2014. In preparing its recommendation, NYISO staff considered the NERA/S&L Report, stakeholders’ oral and written comments, and the recommendations of the independent MMU. The NERA/S&L Report and the NYISO Report incorporated a number of stakeholder recommendations.

Stakeholders then had an opportunity to submit written comments on the NERA/S&L
NYISO Report, and had an opportunity to make oral presentations to the Board and engage
in a discussion of issues with the Board on October 18, 2010 to express their views.8 The
NYISO staff, the independent MMU, and the NYISO Board reviewed and considered the
stakeholder comments. The NYISO staff recommended that the Board approve the NYISO
Report without any alterations. The present filing was approved by the Board on
November 16, 2010.

As discussed in the attached affidavits, the principal consultant for the NERA/S&L Report believes that the proposed ICAP Demand Curves, as contained in this filing, are
reasonable and consistent with the underlying objectives of the ICAP Demand Curves.9
With one exception, noted below in Section IV.F, the independent MMU also supports the NYISO’s proposals.10

6 Proposed NYISO Installed Capacity Demand Curves for Capability Years 2011/2012,

2012/2013, and 2013/2014, September 3, 2010, amended September 7, 2010 and October 30, 2010 (“NYISO Report”), available at

http://www.nyiso.com/public/webdocs/committees/bic_icapwg/meeting_materials/2010-11-
09/NYISO_demand_curve_recommendations_10_30_2010_clean.pdf.

7 See, e.g., infra PP 6 and 18.

8 Written comments were submitted by: (1) Central Hudson Gas & Electric Corporation,
Consolidated Edison Company of New York, Inc (“Con Edison”), Long Island Power Authority,
National Grid, New York Power Authority, New York State Electric & Gas Corporation, Orange &
Rockland Utilities, Inc., and Rochester Gas & Electric Corporation (collectively, “Transmission
Owners”); (2) City of New York; (3) Con Edison; (4) Dynegy Power Marketing Inc., Entergy Nuclear
Power Marketing, LLC, Mirant New York, Inc., and CPV Valley, LLC (collectively, “New York
Supply Parties”); (5) Independent Power Producers of New York, Inc.; (6) Multiple Intervenors;

(7) NRG Energy, Inc.; (8) State of New York Department of Public Service; (9) State of New York Consumer Protection Board, (10) U.S. Power Generating Company.

9 See Attachment 2, Affidavit of Eugene T. Meehan.

10 See Attachment 1, Affidavit of David B. Patton at P 8.

Robert E. Fernandez, General Counsel
Raymond Stalter, Director of Regulatory Affairs * Gloria Kavanah, Senior Attorney

New York Independent System Operator, Inc.

10 Krey Boulevard

Rensselaer, NY 12144
Tel: (518) 356-6103
Fax: (518) 356-7678
rfernandez@nyiso.com
rstalter@nyiso.com

gkavanah@nyiso.com

*Designated for receipt of service.

* Ted J Murphy
Vanessa A. Colón

Hunton & Williams LLP 1900 K Street, N.W.

Suite 1200

Washington, D.C. 20006 Tel: (202) 955-1588

Fax: (202) 778-2201
tmurphy@hunton.com
vcolon@hunton.com

A.Choice of Peaking Technology

The Services Tariff requires that the Demand Curve reset review “shall assess … the current localized levelized embedded cost of a peaking unit in each NYCA Locality [NYC and LI] and the Rest of State” to meet minimum capacity requirements.11 For purposes of updating the ICAP Demand Curves, “a peaking unit is defined as the unit with technology that results in the lowest fixed costs and highest variable costs among all other units’
technology that are economically viable.”12

In selecting appropriate technologies for each region, the Consultant assumed that

only units that could be practically constructed in a particular location would qualify.13 They also assumed that the units would be reasonably large scale, standard generating facilities that are replicable.14

11 Id.

12 Services Tariff, § 5.14.1.2.

13 NERA/S&L Report at 7.

14 NERA/S&L Report at 7-8.

The Honorable Kimberly D. Bose November 30, 2010

Page 6

The NYISO and the Consultant explored and discussed with stakeholders the

possibility of using dispersed generating resources or Demand Side Resources. After careful
consideration it was decided that traditional large generators for this Demand Curve reset
process would be used because the kind of Demand Side Resources that are generators
presently in place generally do not have the ability to respond to longer deployments under
current market rule designs. Further, there is not yet an established set of parameters or
characteristics for a particular demand response technology (i.e., a technology by which load-
side resources achieve reductions) to be identified with any reasonable measure of certainty.
Even if an identified technology could be ascertained with certainty, the fixed and variable
costs make it unsuitable for consideration as the peaking unit in the current Demand Curve
reset review. The NYISO will, however, consider the use of Demand Side Responses as the
peaking unit in the next reset cycle, contingent upon better definition of the process for
identifying technology types, and the methodology and a means to quantifying the fixed and
variable costs associated with those technologies.15

The Consultant focused on General Electric (“GE”) generating unit technologies,
because they are representative of other manufacturers’ designs and account for over

56 percent of the “peaking units” sold both nationally and in New York.16 The previous two ICAP Demand Curve studies focused exclusively on GE technologies but in this instance the Consultant also considered the Rolls Royce Trent 60 WLE (“Trent 60”) unit as a possible peaking unit technology.

The Consultant examined four types of units: one Frame unit (7FA), and three types
of aeroderivatives: LM6000, LMS100, and the Trent 60. The Consultant compared the
characteristics of each technology and the relative cost on a total cost and a $/kW basis. For
environmental reasons, the Consultant ruled out the use of the Frame 7 unit in NYC and LI.17

The Services Tariff does not explicitly indicate whether the unit with “lowest fixed
costs” should be chosen based on total cost or cost per kilowatt.18 The NYISO’s two
previous Demand Curve update studies selected the appropriate peaking technology based in
part on $/kW figures. The relative sizes of the LMS100 unit and LM6000 unit combined
with the numbers of units installed at a generation station can result in significantly different
choices depending upon how the phrase “lowest fixed costs” is interpreted. For both the
LMS100 and the LM6000 technologies the Consultant developed costs for a two-unit
installation, which significantly reduces the $/kW cost but increases the total plant cost. The

15 See NYISO Report at 6.

16 See NYISO Report at 4.

17 NERA/S&L Report at 8, 19.

18 See Services Tariff, Section 5.14.1.2.

The Honorable Kimberly D. Bose November 30, 2010

Page 7

NYISO Report agreed with the Consultant’s analysis and recommendation that fixed costs
should be measured on a $/kW basis because that approach recognizes the efficiencies of
building two-unit sites and the increased Energy and Ancillary Services revenue that would
be captured. Choosing a peaking technology based on total dollars would ignore these
efficiencies.

1. Choice of Peaking Technology for NYC and LI

For LI and NYC, the Consultant considered three different peaking unit technologies,
the LM6000, LMS100, and the Trent 60. The LM6000 has been used extensively, with more
than 600 units built and an operating history of 10 million hours. The LMS100, developed in
2004 and first commissioned in 2006, was considered for the first time in the 2007 Demand
Curve reset study for the 2008-2011 Demand Curves. The NYISO ultimately proposed to
use it as the peaking unit for NYC and LI in the 2007 reset process, and the selection was

accepted by the Commission.19 As of the end of 2009, there are more than 20 LMS100 units
installed, with more than 35,000 cumulative operating hours. The Trent 60 first entered the
market in 1998 and the first installation in the United States began operation in 2008.

The NERA/S&L Report reflects lower capital and operating costs, per kW, for the

LMS100 than the LM6000 and the Trent 60. The LMS100 has a better heat rate (9023

BTU/kWh HHV versus 9475 BTU/kWh HHV for the LM6000 and 9548 BTU/kWh HHV for the Trent 60), which results in a higher capacity factor and higher energy revenues on a per kW basis. The LMS100 also has a lower fixed cost on a $/kW basis compared with the
LM6000 and the Trent 60.20 Based on the Consultant’s study, and discussions with the
independent Market Monitoring Unit, the NYISO proposes to use the LMS100 as the
peaking unit upon which to establish the NYC and LI Demand Curves.

The NERA/S&L Report, and the figures cited in the NYISO Report, were revised from the respective drafts thereof based on stakeholder comments. Revisions included an increase in capital investment costs for the Zone J unit due to brownfield site remediation, and the cost of emission reduction credits. Fixed operating and maintenance costs (O&M) increased due to the effect of capital investment on property taxes and property values,
higher lease costs in NYC, and increased staffing. Gas transportation costs were revised, and emissions allowances for NOx and CO2 were added.

As mentioned above, in October 2010 S&L informed the NYISO that a revision was
necessary to the CO emissions rate for the LMS100 combustion turbine, based on discussions
with the manufacturer. The manufacturer informed S&L that it planned on updating the

19 See New York Independent System Operator, Inc., 122 FERC ¶ 61,064 at P 23 (2008).

20 See NYISO Report at 4.

The Honorable Kimberly D. Bose November 30, 2010

Page 8

software the manufacturer provides for calculating CO emissions, which is software S&L
had used in its computations. The CO emissions rate is used along with the annual hours of
operation to calculate annual emissions from the unit and determine whether or not an
oxidation catalyst is needed and/or if Emissions Reductions Credits must be purchased.

S&L calculated the maximum CO emissions rate that the 2-unit LMS100

configuration without an oxidation catalyst could have, based on the number of hours of

operation estimated by NERA for NYC and LI, while still staying under the annual tonnage
limit that would trigger the need for an oxidation catalyst. In consultation with the turbine
manufacturer, S&L determined that the LMS100 could not meet the annual tonnage limit
without an oxidation catalyst. Therefore, based on the determination using the new
information, S&L recommended the addition of an oxidation catalyst for the LMS100 in
NYC and LI, and likely for the LMS100 unit in other zones in which it was considered as a
possible peaking unit.

S&L therefore revised the cost estimate for the LMS100 cases in NYC and LI to add the oxidation catalyst, as follows:

• Capital investment cost of 2-unit LMS100 in Zone J was $1,784/kW; now is
$1,807/kW (2010 dollars)

• Capital investment cost of 1-unit LMS100 in Zone J was $2,100/kW; now is
$2,123/kW (2010 dollars)

• Capital investment cost of 2-unit LMS100 in Zone K was $1,667/kW; now is
$1,690/kW (2010 dollars).

As is demonstrated in NERA/S&L Report, these cost estimates continue to be lower than the corresponding values for a LM6000 or Trent 60.21

2.Choice of Peaking Technology for the NYCA

The NYISO proposes to use a 7FA unit in the Capital Zone as the “peaking unit” for
purposes of setting the NYCA Demand Curve. The 7FA has a lower fixed cost on a $/kW
basis compared with either the LMS100 or LM6000 and is economically viable outside of
NYC and LI.22 Due to NOx emission restrictions and the inability to install selective
catalytic reduction equipment on the unit, the 7FA would not be practical in NYC or LI and
therefore could not feasibly satisfy the Services Tariff requirements for the peaking unit in

21 See NERA/S&L Report at 26-27, Table II-3.

22 NERA/S&L Report at 9.

The Honorable Kimberly D. Bose November 30, 2010

Page 9

those areas. The Commission accepted the NYISO’s proposal to use the 7FA unit for the NYCA in the 2008-2011 Demand Curve reset.23

Certain stakeholders have raised a question concerning the ability of a 7FA facility to operate under the New Source Review standards for stationary sources. S&L and the NYISO confirmed with the New York State Department of Environmental Conservation that New Source Review24 standards would apply to any new facility emitting greater than 100 tons NOx annually. For the 2-unit 7FA, the 100 ton limit would translate into a maximum run time in Zone F of 1461 hours. The econometric analysis performed by NERA indicates that, at levels of excess considered for this study, a 2-unit 7FA would operate below 1200 hours and thus would not be subject to New Source Review standards.

Separately, some stakeholders have taken the position that a lower cost LI unit should
be used as the NYCA peaking unit.25 That suggestion is inconsistent with the Services
Tariff, which requires the NYISO and its independent consultant to assess the current
localized levelized embedded cost of a peaking unit located in the Rest of State (“ROS”)
when establishing the NYCA Demand Curve, and does not specify consideration of a unit
located in LI or NYC as the peaking unit to establish the NYCA curve. Even assuming
arguendo that the Services Tariff were ambiguous on this point, the NYISO’s Installed
Capacity Manual, which provides the detailed requirements for the Demand Curve reset,
expressly requires that the NYISO calculate “the estimated localized levelized cost … to
develop a new peaking unit in each Locality (for the ICAP Demand Curves for the New York
City and Long Island Localities) or in the ROS region (for the NYCA ICAP Demand
Curve).”26

23 See New York Independent System Operator, Inc., 122 FERC ¶ 61,064 at P 22 (2008).

24 See 40 C.F.R. § 60, Subpart KKKK (2010); see also NERA/S&L Report at 8.

25 See, Comments of the Transmission Owners, New York Power Authority and Long Island Power Authority on the NYISO Staff’s Installed Capacity Demand Curves Proposal at 3-4
(October 8, 2010). Some stakeholders have argued that the cost data that make a LI unit appear to be less costly than a Rest of State unit are outdated and thus that even if the LI unit were used to set the NYCA Demand Curve that its Net CONE would have to be higher. There is no reason to consider
these concerns further because, as was noted above, the Services Tariff and the ICAP Manual do not allow the NYCA peaking unit to be situated on LI. Even if that were possible, however, the
suggested adjustments would generally be inconsistent with the Consultant’s model which limits the adjustments that are made to the historic data that is used to establish the forecast revenues. If a
factor is updated, then there generally are offsetting adjustments that also would need to be
considered, all of which compound the risk of forecast errors. The model currently uses a “snapshot” in time for developing forecasts, with limited adjustments.

26 ICAP Manual § 5.5(1). The Services Tariff provides that the review will be conducted in
accordance with ISO Procedures. The steps delineated lead to establishing the Demand Curves. The

The Honorable Kimberly D. Bose November 30, 2010

Page 10

B.Capital Investment and Other Plant Costs

1.Overview of the NYISO’s Proposal

The NYISO is proposing to use the capital cost determinations that were developed
by its Consultant. Identified capital costs include direct costs encompassed within
engineering, procurement and construction (“EPC”) contracts, owner’s costs not covered by
the EPC including “social justice” costs, financing costs during construction and working
capital and initial inventories. For the LMS100 in NYC, capital costs were identified as
$1,807/kW while capital costs for the LMS100 on Long Island are $1,690/kW. For the
NYCA, the capital costs for the 7FA are $820/kW. All of these dollar figures are in 2010
dollars.

2.Exclusion of “Deliverability” Costs

Prior Demand Curve resets did not consider the question of whether “deliverability” costs should be included in the Net CONE of the peaking unit. The issue arises now as a consequence of the Commission’s 2008 order approving compliance tariff modifications that established two interconnection service products.27 “Energy Resource Interconnection
Service” (“ERIS”) allows a project to participate in the NYISO-administered energy markets and provide Ancillary Services, but does not permit it to become an Installed Capacity
Supplier. By contrast, “Capacity Resource Interconnection Service” (“CRIS”) permits a project to also participate in the NYISO’s Capacity market.

New projects requesting CRIS are evaluated within the “Class Year” study

framework using the deliverability test defined in Sec. 25.7.8 of Attachment S to the OATT.
The projects that are determined to be deliverable in full or in part are awarded CRIS up to
their MW deliverability level. For those projects deemed undeliverable in full or in part, the
NYISO determines the least cost system upgrade(s) to achieve full deliverability (“System
Deliverability Upgrade” or “SDU”). Projects identified as fully or partially non-deliverable
are assigned a share of the total SDU costs, in $/MW, based upon their impact on the

constrained facility/facilities. Projects accepting their SDU costs are granted CRIS.

The Consultant identified the range of Net CONE results for ROS with and without SDU costs but did not take a position on whether SDU costs should be included as an

ICAP Manual is the chief source of ISO Procedures in respect of the Capacity market. Thus, the ISO Procedures to be followed include using a peaking unit located in the ROS to establish the NYCA
Demand Curve.

27 See New York Independent System Operator, Inc., 122 FERC ¶ 61,267 (2008).

The Honorable Kimberly D. Bose November 30, 2010

Page 11

element of the Demand Curves. For the reasons set forth below, the NYISO proposes that deliverability costs be excluded from the calculation of the peaking unit’s cost of new entry. The independent MMU supports the NYISO’s proposal.28

The NYISO’s deliverability tariff provisions, including the cost allocation

methodology for SDUs, were specifically designed to provide interconnection customers an economic incentive to locate in areas where their capacity would be deliverable.29
Consequently, the NYISO’s allocation rules for SDU costs provide that they shall be borne predominantly by interconnection customers with LSEs assuming a portion only under
limited circumstances.30 The NYISO’s deliverability rules, including their cost allocation components, have been approved by the Commission. Moreover, the Commission stated that the approved “approach allocates costs of transmission consistent with Commission policy and recognizes the competing interests of those involved.”31

The Services Tariff does not expressly state that SDU costs should be included in the
computation of the cost of new entry for the peaking unit when establishing the Demand
Curves. There does not appear to be any precedent from other ISO/RTO capacity markets
that requires the inclusion of those costs. It would be unreasonable to apply the existing
Services Tariff language for the Demand Curve reset to SDU costs and ignore the tariff
provisions that require interconnection customers to pay for SDUs so that they will have an
incentive to make efficient decisions regarding the locations of new investments. If SDU
costs were incorporated into the Demand Curves, the desired economic signal would be
suppressed since SDU costs would effectively be subsidized by capacity buyers.

In addition to providing the economic signal, equitable considerations also favor
excluding SDU costs from the cost of new entry calculation. Including SDU costs would
increase the value of Net CONE at equilibrium, resulting in a proportionate increase to the

28 See Attachment 1 at PP 13-18.

29 See New York Independent System Operator, Inc., 122 FERC ¶ 61,267 at P 39 (2008)

(accepting the NYISO-New York Transmission Owners’ Deliverability Consensus Plan, whose cost
allocation procedures were described by the NYISO and New York Transmission Owners as
necessary to “maintain price signals for efficient location.”); Cf. PJM Interconnection, LLC,
119 FERC ¶ 61,318 at P 77 (2007) (noting that the “universal deliverability” concept was a failure
and accepting PJM Interconnection Inc.’s locational capacity pricing proposal because it “creates a
construct that is designed to send the proper price signals” that will “ensure that required generation,
demand response and/or transmission infrastructure are developed where they are most needed.”).

30 Specifically, LSEs would pay, under certain limited circumstances, up to a 40 percent share of SDU costs associated with high voltage highway facilities. New York Independent System Operator, Inc. and New York Transmission Owners, 122 FERC ¶ 61,267 at P 46 (2008).

31 Id.

The Honorable Kimberly D. Bose November 30, 2010

Page 12

Demand Curves at all levels of excess capacity. New and existing generators would thus all receive higher capacity payments at the expense of customers. This shifting of additional
costs to customers (i.e., LSEs) disrupts the carefully crafted cost allocation rules that
explicitly assign only certain SDU costs to LSEs. Such an outcome seems especially
inappropriate considering that existing generators were grandfathered from the deliverability requirement and paid no costs associated with SDUs. Including SDU costs would provide
these grandfathered generators with a windfall from the resulting higher capacity prices, at
the expense of all customers. Further, the Demand Curves are designed not only to attract
new entry but also to send the proper signal for retirements. Thus, including the costs would skew the economic signal to existing generators.

In addition, as the independent MMU has emphasized,32 generators may avoid SDU costs by procuring deliverability rights from retiring resources, which may well be available at lower cost than the SDU upgrade. A generator that funds an SDU that results in the
creation of additional transmission capacity would also be awarded Incremental
Transmission Congestion Contracts (“TCCs”). It is reasonable to anticipate that the value of Incremental TCC awards would offset a generator’s SDU costs. These revenues, however, are not included in the computation of Energy and Ancillary Services revenues used to
compute the net costs of the peaking unit. Including SDU costs in the Demand Curves would thus, once again, be likely to result in a windfall for generators.

Some stakeholders have contended that excluding SDU costs from the cost of new

entry might inefficiently discourage investment. The NYISO, however, concurs with the

independent MMU that including SDU costs in the Demand Curves would not be an efficient means of providing long-term economic signals to potential investors33 and is concerned that it might promote inefficient investment.

Even if the Commission were to conclude that the inclusion of SDU costs would not
contravene its precedents it would nevertheless be premature for it to override the NYISO
Board’s and the MMU’s determination and direct that such costs be included at this time.
Any deliverability-related adjustments should be considered in relation to the question of
whether it is appropriate to establish a new Capacity Zone in New York. Stakeholders that
have argued for the inclusion of SDU costs34 have conceded that the creation of a new

Capacity zone would ameliorate their concerns.35 The NYISO is already subject to

32 See Attachment 1 at P 17.

33 Id. at P 18.

34 See Comments of the Independent Power Producers of New York Inc. on Proposed

NYISO Installed Capacity Demand Curves and Request for Oral Argument at 3 (October 8, 2010).

35 If the Commission were inclined to include deliverability costs, the deliverability costs
utilized in the NERA/S&L analysis are based on the limited experience applying the deliverability

The Honorable Kimberly D. Bose November 30, 2010

Page 13

compliance obligations to work collaboratively with its stakeholders to develop “criteria for
the potential formation of additional locational ICAP zones”36 and to “address dynamic
changes to the New York Control Area that may warrant the creation of additional capacity
zones within the NYISO market.”37 The NYISO has been working with stakeholders to
develop such criteria.38 By January 4, 2011, the NYISO will make a compliance to establish
criteria to govern the possible creation of new Capacity zones. The continuing stakeholder
discussions that will shape that filing, and the Commission proceedings after the compliance
filing is made,39 are the appropriate venues for exploring deliverability related issues. If the
Commission were to ultimately conclude that the establishment of a new Capacity Zone was
warranted, that change could be effectuated without increasing Capacity payments to all
resources, as would occur if SDU costs were included in the Demand Curves. Leaving these
matters for the deliverability compliance proceedings would also prevent efficient investment
signals from being be muted or skewed.

C.Fixed Operating and Maintenance Costs

1.Overview of the NYISO’s Proposal

The NYISO is proposing to adopt the Consultant’s recommendations40 regarding fixed O&M costs.41 Property taxes were based on those typical in the jurisdictions chosen for each market (NYC, LI and Capital Zone).

As a result of the addition of oxidation catalysts to the LMS100 peaking units in NYC
and LI, the fixed O&M costs change by impacting property taxes and insurance, as follows:

test. The report utilized the deliverability estimate provided by the NYISO at that time which was $178 per kW. See NERA/S&L Report at 73. However, utilizing a larger and thus more meaningful set of data reflects a great difference in deliverability costs from one Class Year to the next Class Year. For example, the November 2010 draft Reports of the NYISO Interconnection Projects Staff estimate that Class Year 2009 projects in Rest of State will have a $/kW SDU cost of $106.899
whereas the Class Year 2010 estimate is 1.791 $/kW.

36 New York Independent System Operator, Inc., Consensus Deliverability Plan of the New York Independent System Operator, Inc. and the New York Transmission Owners at P19, Docket No. ER04-449-016 (filed October 5, 2007).

37 New York Independent System Operator, Inc., 127 FERC ¶ 61,318 at P 53 (2009).

38 New York Independent System Operator, Inc., Notice of Extension of Time, Docket Nos. ER04-449-018, ER04-449-019 (issued October 4, 2010).

39 See Docket Nos. ER04-449-000 through ER04-449-019.

40 NERA/S&L Report at 27-30.

41 NYISO Report at 9.

The Honorable Kimberly D. Bose November 30, 2010

Page 14

• Fixed O&M cost of 2-unit LMS100 in Zone J was $107.70/kW-yr; now is
$108.85/kW-yr

• Fixed O&M cost of 1-unit LMS100 in Zone J was $135.42/kW-yr; now is
$136.59/kW-yr

• Fixed O&M cost of 2-unit LMS100 in Zone K was $48.81/kW-yr; now is
$49.33/kW-yr.

The effect varies by case chiefly because of differing property tax rates in each zone and differing size of project investment (1 or 2 units).

2.NYC Tax Abatement Issues

At the time of the 2007 Demand Curve filing, the NYC Industrial and Commercial
Incentive Program (“ICIP”) provided reductions in real property taxes to new industrial and commercial projects, including power plants. Under ICIP, full property tax abatement was in effect for the first eleven years of operation, and ramped down in 20 percent increments over the next five years until, in year sixteen, there was no abatement. In the prior Demand Curve reset, the NYISO accounted for the ICIP when calculating the costs of the NYC peaking unit, and assumed that a NYC Class 4 property tax rate would apply during the years in which the ICIP exemption was no longer available.

In July 2008, a revised program was established that effectively removed the tax abatement for new generating facilities in NYC. This change prompted litigation over the question of whether the currently effective Demand Curves should be reset to reflect the change in tax treatment. The NYISO Board decided that the NYC Demand Curve approved by the Commission should not be revised, but the Board specified that the current reset
process would include a “thorough evaluation of … any other development incentives.”42 The NYISO Board’s approach was upheld by the Commission.43

On August 3, 2010, the Board of Directors of the New York City Industrial

Development Authority (“NYCIDA”), an agency administered by the New York City
Economic Development Corporation (“NYCEDC”), approved the Third Amended and

42 NYISO Board of Directors Decision on Whether Repeal of the ICIP Requires Resetting the NYC ICAP Demand Curve at 5 (August 27, 2008) available at <

http://www.nyiso.com/public/webdocs/documents/regulatory/market_participant_notices/ICIP_Repea
l.pdf>.

43 Independent Power Producers of New York, Inc., et al. v. New York Independent System Operator, Inc., 125 FERC ¶ 61,311 (2008).

The Honorable Kimberly D. Bose November 30, 2010

Page 15

Restated Uniform Tax Exemption Policy (“UTEP”).44 As part of the UTEP, various

inducements for new installation of peaking units (defined by the NYCIDA as “PlaNYC Energy Program Projects”) in NYC were established.45

Generation projects that satisfy the established criteria and file a request for abatement are eligible for the following tax exemptions:

• Exemption from real property taxes (full exemption for twelve years, no abatement
thereafter)

• Exemption from recording taxes

• Exemption from mortgage recording taxes

• Exemption from sales and use taxes

The now-repealed ICIP benefits were granted as of right to all applicants whose

projects satisfied legislative criteria. By contrast, the NYCIDA Board of Directors has

discretion when reviewing qualified applications. Consequently, the Consultant did not take a position whether to include tax abatement, but instead included in its model the ability to exclude or include any set of terms and conditions on levels of tax abatement.46

The NYISO Report concluded that the most reasonable approach to setting the first post-ICIP NYC Demand Curve was to assume full tax abatement treatment for the NYC peaking unit. The conditions that must be met to qualify for program benefits are clear, and projects meeting the criteria set forth in the UTEP should be granted full tax abatement in accordance with the UTEP provisions.

Some stakeholders have claimed that it is unreasonable to make this assumption
because there is no guarantee that full tax abatement, or even any abatement, would be
granted in all cases. At the same time, the NYCEDC representative stated in the Demand
Curve Reset process, including in oral presentations to the Board, that it is in NYC’s
economic interest to grant abatements to peaking units because so doing would result in
lower capacity prices. The NYISO has therefore concluded that the City will very likely act
in a manner that is consistent with its economic interests and is therefore proposing to use a
full abatement assumption in setting the NYC Demand Curve. This proposal would avoid a

44 Available at

http://www.nycedc.com/AboutUs/PublicMeetings/NYCIDAPublicHearing/Documents/THREE%20UTEP.pdf

45 See NYISO Report at 10.

46 See Table I-1 on page 9 of the NERA/S&L Report, showing the impact of no tax

abatement ($262.97/kW-yr) and full tax abatement per PlaNYC Energy Program terms ($192.32/kW-
yr).

The Honorable Kimberly D. Bose November 30, 2010

Page 16

potentially severe impact on consumers and avoid a windfall to generators, several of which have their taxes abated under the now-repealed ICIP law.

Nevertheless, the NYISO believes that it is important that future Demand Curve reset reviews build upon the actual disposition of qualifying generators’ applications for the
PlaNYC Energy Program benefits. Thus, prior to the next Demand Curve reset cycle, the NYISO will review the outcome of applications that qualified for abatement under the
PlaNYC Energy Program and will recommend that the percentage of tax abatement applied in establishing the next NYC Demand Curve reflect the actual awards made.

The NYISO also finds that stakeholder comments that the UTEP is designed narrowly
to fit the Demand Curve is irrelevant; what is relevant is the fact that a peaking unit
technology would meet the UTEP criteria. The Demand Curve reset process is limited by
Tariff to using a peaking unit. Moreover, to carry the objection to its logical conclusion
demonstrates that even though a combined cycle unit is not eligible for tax abatement under
the UTEP, its overall net cost of new entry is less than that of the peaking unit.

D.Variable O&M and Fuel Costs

The NYISO is proposing to adopt the Consultant’s recommendations47 regarding
variable O&M costs.48 Variable O&M costs are primarily driven by periodic maintenance
cycles: for the LMS100, maintenance is recommended every 50,000 factored operating
hours; for the 7FA, the shorter of 48,000 hours or 2,400 factored starts is recommended.
Other variable O&M costs are directly proportional to plant generating output, as outlined by
the Consultant.

The NYISO is also proposing to adopt the Consultant’s recommendations with respect to fuel and transportation costs.49

E. Development of Levelized Carrying Charges

The Consultant analyzed the elements to be used in developing levelized carrying

charges.50 They determined an annual carrying charge rate using the same methodology that
was used for the previous Demand Curve reset study and approved by the Commission.
Financing assumptions were discussed at length by stakeholders and in written comments,

47 NERA/S&L Report at 30-32.

48 NYISO Report at 12.

49 NYISO Report at 12.

50 NERA/S&L Report at 36.

The Honorable Kimberly D. Bose November 30, 2010

Page 17

and are discussed in the NERA/S&L Report and the NYISO Report.51 The Consultant

proposed a set of financing assumptions that reflect those associated with a larger corporate capital structure. The NYISO believes that the debt/equity parameters chosen provide a reasonable balance, and is proposing to adopt the Consultant’s recommendations.

F. Estimates Regarding the Expected Level of Average Excess Capacity

Expectations as to the amount of Installed Capacity relative to the annual Locational
and NYCA Minimum Installed Capacity Requirement will impact the level of Energy and
Ancillary Services revenues received by the new peaking unit. For the three-year period
covered by this Demand Curve update, the NYISO recommends using a capacity level of
100.5 percent of the target Installed Capacity level for computing Energy and Ancillary
Services revenues. This level comports with the Services Tariff, which states that Energy
and Ancillary Services revenues are to be determined “under conditions in which the
available capacity would equal or slightly exceed the minimum Installed Capacity
requirement.”52

For the remainder of the nominal life of the facility (thirty years) (i.e., the 27 years beyond the 3 years of the Demand Curve), the Consultant recommended that the average percent excess in each region be determined by “first multiplying the ICAP of the peaking unit by 1.5 and then dividing that value by the minimum capacity requirement for the
region.”53 The level of excess Capacity modeled is a judgment based upon the expected frequency and size of new entry, retirements, and the minimum level of excess anticipated before new Capacity would be likely to enter the market.

The NYISO believes that signals for new entry will be provided before the level of
excess drops to the equilibrium point; but the timing of that entry could reasonably coincide
with the time at which the excess is anticipated to fall to zero. The addition of the new entry
peaking unit will bring the excess to 1.0*MW peaking unit. As the excess is absorbed by
load growth, the cycle would repeat, resulting in an average level of excess of 0.5*MW
peaking unit. Using the Consultant’s peaking unit sizes reflected in the Table below, this
would result in an average excess in NYC and LI of 0.5*195 = 98 MW, and 207 MW in
NYCA. Based on the average requirement levels noted by the Consultant,54 (36,000 MW for
NYCA, 8575 MW for NYC and 4700 MW for LI), levels of excess would be 1.1% for NYC,

2.1% in LI and 0.6% in NYCA. The NYISO has concluded, however, that it is unrealistic to

51 NERA/S&L Report at 38, 59; NYISO Report at 12.

52 Services Tariff Section 5.14.1.2.

53 NERA/S&L Report at 70.

54 See NERA/S&L Report at 69.

The Honorable Kimberly D. Bose November 30, 2010

Page 18

assume that, over time, an average level of excess below 1% would be reasonable.55

Therefore, the NYISO is proposing that the level of excess in NYCA be modeled at 1%, with NYC modeled at 1.1% and LI at 2.1%.

Table II-A - Sensitivity Analysis, Levels of Excess Capacity Modeled

Summer Reference Point ($/kW-mo)2011 Est. Capacity Revenue ($/kW-yr)

NYCANYCLINYCANYCLI

Current Demand Curve (2011$)$10.67$17.24$9.37$26.14$ 117.23$26.14

1.5*MW peaking unit$9.38$20.35$11.08$22.98$ 138.38$23.19

1.0*MW peaking unit$8.86$18.43$8.36$21.71$ 125.32$21.71

NYISO recommendation*$8.86$16.91$6.31$21.71$ 114.99$21.71

@100.5% of equilibrium$8.39$15.99$4.88$20.56$ 108.73$21.71

*NYISO recommended excess: NYCA: 1%; NYC: 1.1%; LI: 2.1%

As set forth in Attachment 1, the independent MMU supports the NYISO’s

recommended level of excess for the NYCA but believes that the NYISO’s and its

Consultant’s proposed expected excess capacity levels for NYC and LI (1.1% and 2.1% respectively) are too low over the long-term. The independent MMU’s view is that, in practice, new entry would not perfectly coincide with resource needs. The independent MMU believes that a level of excess equal to the size of the peaking unit (195 MW) is a more reasonable assumption.

The NYISO and its Board carefully considered and discussed this issue with the

independent MMU. The Board supports the recommendation in the NYISO Report which is
the proposal that is included in this filing. As is explained in the Affidavit of David
Lawrence,56the independent MMU’s point is important when examining the Capacity
markets but the Services Tariff calls for an assessment not of expected conditions but of
conditions “in which the available capacity would equal or slightly exceed the minimum
Installed Capacity requirement.” The same distinction is emphasized in the NERA/S&L
Report, which observes that historic levels of excess capacity have been higher than the
NYISO’s estimates but that “[t]he excess adjustment is clearly not designed to compensate
for actual excesses, but only for excesses that will occur near the minimum installed capacity
requirement.”57 The independent MMU’s concerns that the NYISO’s estimates for NYC and

55 NYISO Report at 13.

56 See Attachment 3 at PP 10-11.

57 NERA/S&L Report at 71.

The Honorable Kimberly D. Bose November 30, 2010

Page 19

LI do not reflect “real world” conditions or unreasonably assume that the NYISO and investors will have “perfect foresight,” are therefore misplaced.58

Some stakeholders have argued that the levels of excess used by the NYISO are too
low, or vary too greatly from values used in the past. Others have claimed that the estimates
are too high. The level of excess is a component of the Demand Curves which requires the
application of judgment to its estimates. The estimated excess capacity levels that are
proposed herein are lower than those in the previous Demand Curve reset in part because the
NYISO and its Consultant determined that it is appropriate to set the level in relation to the
size of the peaking unit used to establish the Demand Curves rather than on a larger
combined cycle unit (as was done in the 2007 reset ). As the NERA/S&L Report explained,
this approach is reasonable because the peaking unit represents the efficient addition to
maintain reliability.59 It is also consistent with the Services Tariff’s mandates that the lowest
cost peaking unit be used to set the Demand Curves and that Energy and Ancillary Services
revenues be determined under conditions where available capacity would, at most, slightly
exceed the minimum Installed Capacity requirement.60 As was noted above, the NYISO’s
judgment is that signals for new entry will likely be provided nearly coincident with the level
of excess Capacity falling to near the minimum Capacity requirement.

G. Energy and Ancillary Services Revenue (“Net Revenue Offsets”)

Based upon the Consultant’s energy model and the NYISO’s recommended levels of
excess, estimated energy and ancillary services revenue of $27.44/kW-year for the NYCA,
$101.67/kW-year in NYC, and $168.77/kW-year on LI (all figures in 2011 dollars) were
calculated for the peaking technologies chosen in the study.61 The Consultant used historical
data from November 1, 2006 through October 31, 2009 to benchmark the operation of the
NYISO system in order to determine likely projected Energy and Ancillary Services
Revenues (“Net Revenue Offsets”) to utilize in computing the net cost of new entry for the
peaking unit. The Consultant’s statistical model allowed for the identification and variance
of any causal variables that may impact future Energy prices. These prices were then used to
dispatch the hypothetical peaking unit, calculating both day-ahead and real-time Energy
revenues while recognizing Capacity commitment considerations and operating constraints.62

58 Attachment 1 at PP 24-28.

59 NERA/S&L Report at 71.

60 Of course, as the independent MMU has noted, there is “no one correct assumption

regarding the long-term average level of excess capacity . . . ,” Attachment 1 at P 28. Consequently,
the NYISO’s and its Consultant’s decision to set the estimated excess capacity levels proposed in this
filing on peaking units does not render past decisions to set it on combined cycle units unreasonable.

61 NERA/S&L Report at 9; NYISO Report at 20.

62 NERA/S&L Report at 39.

The Honorable Kimberly D. Bose November 30, 2010

Page 20

The Consultant and the NYISO modified their initial reports in response to stakeholder comments. For example:

• CO2 and NOx allowance credit costs have been included as additional operating costs.

• One set of LBMP regression equation parameters and one LBMP forecast using the
appropriate gas price index for each zone were used.63

The Consultant also evaluated several additional considerations that were raised by stakeholders, including:

• Impact of Lake Erie loop flow

• Use of forward gas prices instead of a regression fit of historical gas prices

• Impact of recession /cool weather adjustments.

Further, certain stakeholders have asserted that the NYISO’s estimated Net Revenue Offsets are too high because they do not adequately adjust for anomalies such as Lake Erie loop flow, and they ignore the premium that generators must pay for gas in the day-ahead market when that premium can be calculated. Others have objected that the Net Revenue Offsets are too low because the NYISO has not accounted for the expected increase in the use of Demand Side Resources.

The NYISO agrees with the Consultant’s conclusion that adjustments for these

conditions should not be made.64 It is the Consultant’s and the NYISO’s expectation that

although large anomalous events with measurable effects may not even out over a relatively
brief three-year period, they will even out in the long run. Unique events, such as
unexpected loop flow reversals, which have large impact (positive or negative) on price will
go away over time, potentially being replaced by large effects which go the other way.
Therefore, for purposes of setting Demand Curves, it is more prudent to limit adjustments for
such events in order to promote stability. Further, adjusting the Energy and Ancillary
services model for such factors opens the door to errors in model prediction that may be
compounded because the results are used in the overall Demand Curve Model.
Consequently, the NYISO is proposing to include the Net Revenue Offsets that were
recommended in the NYISO Report.

63 See NYISO Report at 14.

64 NERA/S&L Report at 54, NYISO Report at 14.

The Honorable Kimberly D. Bose November 30, 2010

Page 21

H.Demand Curves’ Slope and Length

The Consultant reviewed the shapes of the current Demand Curves and found no
basis to change the current shape and zero crossing points.65 As the Consultant notes, the
demand curve methodology determines the level of Capacity revenues needed to yield the
compensatory amount of total revenue (Capacity plus Energy plus Ancillary Services
revenues), considering the slope, average level of excess capacity and variability of excess
capacity. Consequently, any increase in the Demand Curve slope due to a lower zero
crossing point will be compensated by raising the Demand Curve reference point at
equilibrium. As is discussed in the NYISO Report, the NYISO staff conducted a parallel
analysis using NERA’s Demand Curve model, and the results of that analysis also support
this relationship. The analysis did identify and further emphasize the sensitivity of slope
adjustments on capacity revenue under current market conditions, which are characterized by
excess Capacity and low anticipated load growth.66 The NYISO is therefore proposing that
the current Demand Curve slope and zero crossing point be retained and that the zero
crossing point remain at 112% of the ICAP requirement for the NYCA and at 118% for NYC
and LI. This approach is consistent with the NYISO’s determination in the 2007 reset
process that there was “no compelling reason” to change Demand Curve shapes or zero
crossing points at that time. That rationale was accepted by the Commission in 2008.67

Some stakeholders have objected that the current Demand Curve is too shallow,

which, if it were true, would mean that the Demand Curves were overcompensating

Suppliers. The NYISO takes such concerns very seriously but nevertheless believes that its
proposal to continue with previously approved slopes and zero crossing points is the most
reasonable approach. Slope and shape adjustments can have unpredictable but significant
impacts on projected Capacity revenues. For example, it would result in lowering capacity
compensation, which could significantly increase investors’ perception of risk and
significantly raise the levelized costs of entry. Quantification of such effects is difficult and
uncertain and while any revision to the shape and slope would need to account for these
effects, the NYISO and its Consultant believe that any such effort would largely be
guesswork. The validity of the current slope and shape is also demonstrated by the fact that
new Capacity has been entering the market and is being developed, while necessary units are
not exiting.

65 See NERA/S&L Report at 75-79.

66 See NYISO Report at 15-16.

67 New York Independent System Operator, Inc., 122 FERC ¶ 61,064 at P 62 (2008).

The Honorable Kimberly D. Bose November 30, 2010

Page 22

I.Escalation of Demand Curves

The prior Demand Curve study used the Handy-Whitman Index for power-plant

construction to determine a projected escalation rate. The lack, to date, of a strong economic recovery and the uncertainty created by inaction on carbon legislation has led the NYISO to conclude that historic equipment escalation rates will not be sustainable. Consequently, and for reasons set forth in more detail in the NYISO Report, the NYISO is proposing a 1.7% escalation factor for the second and third years of the three-year reset period.68 This value was derived from three publicly available inflation forecasts 69

J.Winter/Summer Adjustment

The NYISO ICAP market operates in two six-month Capability Periods with different amounts of Capacity available in each. The primary reason for this variation is that
generators normally are capable of higher Capacity output in winter than summer due to
lower ambient temperature conditions. Installed Capacity imported from External Control
Areas, new generation, retirements and Special Case Resources also influence the quantity of Capacity available. The monthly ICAP reference point for the NYCA and each Locality is
derived from the annual reference value for new entry, less an estimate of annual net revenue from Energy and Ancillary Services.

The annual reference value is a $/kW-year value based on an average generator

rating. The ICAP Demand Curve reference point used in monthly ICAP Spot Market

Auctions must include adjustments to take these seasonal effects into account. Each monthly
Demand Curve reference point is set to the level that would permit a peaking unit to be paid
an amount over the course of the year that is equal to the annual reference value established
by this update.

The Services Tariff specifies that the translation of the annual net revenue

requirement into monthly values take into account “seasonal differences in the amount of

68 The NYISO understands that the Commission recently approved the PJM Interconnection L.L.C.’s (“PJM’s”) proposal to derive PJM’s version of a demand curve escalation factor using the Handy-Whitman Index. See, e.g., PJM Interconnection, L.L.C., 131 FERC ¶ 61,168 at P 18 (2010). PJM’s capacity market design, however, differs from the NYISO’s in many ways. The NYISO’s
proposal, including the escalation factor, is the product of an extensive stakeholder process that
focused on the particular characteristics and circumstances of the NYISO’s capacity market design and tariff requirements. Basing the NYISO’s escalation factor on the Handy-Whitman Index would contravene the judgment of the NYISO staff which is set forth in the NYISO Report, the NYISO
Board, the Consultant, and the independent MMU.

69 See NYISO Report at 16-17.

The Honorable Kimberly D. Bose November 30, 2010

Page 23

Capacity available in the ICAP Spot Market Auctions.”70 The NYISO has determined that the amount of Capacity available is that amount of Capacity that could be offered into the ICAP Spot Market Auctions (i.e., available capacity). The ratio of available winter to summer Capacity for each Capability Year is used to calculate the ICAP Demand Curve reference points for each Locality and the NYCA.

The NYISO Report recommended a winter to summer Capacity sales ratio of 1.052 for the NYCA as a whole, 1.098 for New York City, and 1.062 for Long Island.71 The NYISO is proposing to use those values in this filing.

V. DESCRIPTION OF REVISED TARIFF PROVISIONS

The ICAP Demand Curves are determined by the parameters specified in Section

5.14.1.2 of the Services Tariff. Accordingly, the tariff revisions submitted with this filing revise tables with the added relevant monthly values for NYC, LI and NYCA for the
2011/2012, 2012/2013 and 2013/2014 Capability Years. The tariff sheets retain the
2009/2010 demand curves in the event these tariff sheets are made effective during the 2010/2011 winter Capability Period. In addition, the revised tariff sheets reflect the
maximum price for Capacity in the ICAP Spot Market Auctions.

VI. REQUESTED EFFECTIVE DATE

The NYISO requests an effective date of January 28, 2011, i.e., sixty days from the date of this November 30, 2010 filing.

VII. REQUEST FOR WAIVER OF INAPPLICABLE COST OF SERVICE
REQUIREMENTS UNDER PART 35 OF THE COMMISSION’S
REGULATIONS

Section 35.13 of the Commission’s regulations generally requires public utilities to file certain cost and other information related to an examination of traditional cost-of-service rates to support proposed changes to their tariffs or rate schedules. However, the tariff
modifications proposed herein do not involve traditional cost-of-service “rates.” Further, the NYISO is not a traditional investor-owned utility. The Commission’s general practice has not been to apply the traditional Section 35.13 requirements to such filings. Nevertheless, to the extent necessary, the NYISO requests waiver of Section 35.13. Notwithstanding the
request for waiver, the NYISO submits the additional information enumerated below is in substantial compliance with relevant provisions of Section 35.13:

70 Services Tariff Section 5.14.1.2.

71 See NYISO Report at 17-18.

The Honorable Kimberly D. Bose November 30, 2010

Page 24

•35. 13(b)(1) - Materials included herewith are listed in Section I of this filing letter.

•35.13(b)(2) - The NYISO’s requests an effective date 60 days from the date of filing

(i.e., January 28, 2011 as set forth in Section VI of this filing letter.

•35.13(b)(3) - Service has been made as provided in Section VIII of this filing letter.

•35.13(b)(4) and (5) - A description of the materials submitted in this filing, and of the

reasons for this filing, is provided throughout this filing letter, particularly in

Section IV.

• 35.l3(b)(6) - The NYISO’s approval of these modifications is evidenced by this filing.

As discussed in Section II of this filing letter, the changes have been approved by the NYISO’s independent Board of Directors after an extensive stakeholder review
process described in Section 5.14 of the Services Tariff.

• 35.13(b)(7) - The NYISO has no knowledge of any relevant expenses or costs of

service that have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative, or unnecessary costs that are demonstrably the product of discriminatory employment practices.

VIII. SERVICE

The NYISO will send an electronic link to this filing to the official representative of
each of its customers, to each participant on its stakeholder committees, to the New York
Public Service Commission, and to the electric utility regulatory agency of New Jersey. In
addition, the complete filing will be posted on the NYISO’s website at www.nyiso.com.
This is in accordance with 18 C.F.R. § 35.2(e).

IX.CONCLUSION

As a result of the processes described above, the new ICAP Demand Curves adopted
by the NYISO Board and proposed in this filing are based on a thorough independent review
and have been scrutinized in an extensive stakeholder process that included written
submissions and oral presentations to, and discussion with the NYISO’s Board of Directors.
Various stakeholders have advocated revisions which would result in raising or lowering the
Demand Curves proposed herein. The Consultant and the NYISO incorporated comments
and revised the inputs and methodology as appropriate. The NYISO’s Report, the
recommendations therein, the Demand Curves provided in the proposed tariff revisions

The Honorable Kimberly D. Bose November 30, 2010

Page 25

approved by the Board of Directors, are fully supported as described in this letter and the
affidavits attached hereto, and the NERA/S&L Report and the NYISO Report, thus
supporting a Commission finding that the Demand Curves are just and reasonable.

Respectfully submitted,

/s/ Ted J. Murphy

Ted J. Murphy
Counsel for

New York Independent System Operator, Inc.

cc:Michael A. Bardee

Gregory Berson
Connie Caldwell
Anna Cochrane
Jignasa Gadani
Lance Hinrichs
Jeffrey Honeycutt

Michael Mc Laughlin
Kathleen E. Nieman
Daniel Nowak

Rachel Spiker