UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

)

New York Independent System Operator, Inc.)Docket No. ER21-502-000

)

REQUEST FOR LEAVE TO ANSWER AND ANSWER OF
NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.

Pursuant to Rules 212 and 213 of the Rules of Practice and Procedure promulgated by the Federal Energy Regulatory Commission (“Commission”),1 the New York Independent System Operator, Inc. (“NYISO”) hereby submits this Request for Leave to Answer and Answer in
response to protests and comments filed in response to the proposal in this proceeding submitted by the NYISO on November 30, 2020 (“2021-2025 DCR Filing”).2

The 2021-2025 DCR Filing represents the culmination of the quadrennial review of the
ICAP Demand Curves required by the NYISO Market Administration and Control Area Services
Tariff (“Services Tariff”).3 The periodic reviews (commonly referred to as the “ICAP Demand
Curve reset” or “DCR”) provide a forum for an open and transparent assessment of the
assumptions and parameters for establishing the ICAP Demand Curves.4 The DCR includes a
comprehensive stakeholder process for vetting the necessary assumptions and parameters with
all interested parties. The NYISO’s proposal in this proceeding establishes the ICAP Demand
Curves for the 2021/2022 Capability Year, as well as the methodologies and inputs used in

1 18 C.F.R. §§ 385.212 and 385.213.

2 Docket No. ER21-502-000, New York Independent System Operator, Inc., 2021-2025 ICAP Demand Curve Reset Proposal (November 30, 2020).

3 See Services Tariff § 5.14.1.2.2.

4 Capitalized terms not otherwise defined herein shall have the meaning specified in the Services

Tariff.

conducting the tariff-required annual updates to determine the ICAP Demand Curves for the 2022/2023 through 2024/2025 Capability Years.

The proposal submitted by the NYISO reflects careful consideration of all stakeholder
feedback and comments provided throughout the DCR and strikes a reasonable balance that
establishes appropriate ICAP Demand Curves for the 2021-2025 reset period. Consistent with
prior resets, due to divergent stakeholder interests, the NYISO did not achieve consensus on all
aspects of its proposal.5 The NYISO identified open issues and responded to each within the
2021-2025 DCR Filing. The comments and protests submitted in response to the 2021-2025

DCR Filing raised issues previously identified by the NYISO. Although parties do not agree on all aspects of the NYISO’s proposal, the NYISO has demonstrated that its proposal for the 2021-
2025 DCR is just and reasonable. Accordingly, the NYISO respectfully reiterates its request that the Commission: (1) issue an order on or before January 29, 2021 accepting the NYISO’s
proposal as set forth in the 2021-2025 DCR Filing; and (2) establish an effective date of January 30, 2021 for the tariff revisions proposed by the NYISO in this proceeding.6

I.REQUEST FOR LEAVE TO ANSWER

Rule 213 of the Commission’s Rules of Practice and Procedure generally prohibits

answers to certain pleadings, including protests.7 The Commission, however, has discretion to waive such prohibition.8 The Commission has previously determined that a waiver is

5 2021-2025 DCR Filing at 7.

6 Timely Commission action is necessary to facilitate the NYISO’s ability to proceed with the

necessary steps to conduct the ICAP auctions for the upcoming 2021 Summer Capability Period. The

processes and procedures to prepare for such auctions commence in February 2021. See 2021-2025 DCR Filing at 60.

7 18 C.F.R § 385.213(a)(2). The Commission’s Rules of Practice and Procedure authorize answers to pleadings styled as “comments.”

8 Id.

appropriate in circumstances where an otherwise prohibited answer: (1) will lead to a more
complete and accurate record; (2) helps the Commission better understand the issues; (3)
clarifies matters in dispute or errors; and/or (4) provides information that will assist the
Commission in rendering a decision.9 This answer clarifies matters in dispute, corrects certain
erroneous assertions, provides information that will assist the Commission, and assists in the
development of a complete recording in this proceeding.10 Accordingly, the Commission should accept and consider this answer.

II.ANSWER

The positions advocated by various parties would, if adopted by the Commission, result
in placing either upward or downward pressure on the ICAP Demand Curve parameters
proposed by the NYISO. The NYISO’s proposal for the 2021-2025 DCR strikes a fair and
reasonable balance between the divergent positions of protestors. The NYISO’s proposal
establishes ICAP Demand Curves designed to provide appropriate price signals reflecting the
locational value of Installed Capacity. The proposal submitted by the NYISO is just and
reasonable. The Commission should accept the NYISO’s proposal in this proceeding without
modification.

9 See, e.g., New York Independent System Operator, Inc., 158 FERC ¶ 61,028 (2017) (accepting
answers to protests that provided information that assisted the Commission’s decision making process);
New York Independent System Operator, Inc., 134 FERC ¶ 61,058 (2011) (accepting answers to protests
because they provided information that aided the Commission in better understanding the matters at issue
in the proceeding); New York Independent System Operator, Inc., 99 FERC ¶ 61, 246 (2002) (accepting
answers to protests that help clarify issues and did not disrupt the proceeding); New York Independent

System Operator, Inc., 91 FERC ¶ 61,218 (2000) (accepting an answer deemed useful in addressing issues arising in the proceeding at issue); and Morgan Stanley Capital Group, Inc. v. New York
Independent System Operator, Inc., 93 FERC ¶ 61,017 (2000) (accepting an answer that was helpful in the development of the record).

10 The NYISO has sought to limit the scope of this answer to address certain key disputed issues. Thus, this answer does not respond to all arguments and assertions made by parties in response to the 2021-2025 DCR Filing. The Commission should not construe the NYISO’s silence as to any particular assertion or argument in opposition to its proposal as agreement or acquiescence.

A. Peaking Plant Design and Cost Estimates

The NYISO addresses the following issues raised by certain parties: (1) the inclusion of selective catalytic reduction (“SCR”) emissions control technology for the proposed peaking
plant design in Load Zone G (Dutchess County); (2) cost estimates for a gas interconnection
outside New York City; (3) the assumed land lease cost within New York City; and (4) the
owner’s cost component of the capital cost estimates. The NYISO’s proposed assumptions with respect to each of these issues are appropriate and reasonable. The Commission should not
direct any changes to such assumptions.

1. The Inclusion of SCR Emissions Control Technology for a Dual Fuel Plant Design Is
Appropriate

The NYISO proposes to establish the G-J Locality ICAP Demand Curve based on a

peaking plant located in Load Zone G (Rockland County) for the duration of the 2021-2025 reset
period.11 Certain parties, however, contend that the Commission should direct the NYISO to
revise the peaking plant design for Load Zone G (Dutchess County) to exclude SCR emissions
control technology.12 The NYISO’s proposal to include SCR emissions control technology as
part of the dual fuel peaking plant design in Load Zone G (Dutchess County) is reasonable and
appropriate.

Opposing parties essentially contend that the inclusion of SCR emissions control

technology for the peaking plant located in Load Zone G (Dutchess County) is a purely

economic decision for a developer.13 The NYISO’s proposal to include SCR emissions control

11 See, e.g., 2021-2025 DCR Filing at 6, 14-16, and 57-58.

12 This change, if adopted, would result in Load Zone G (Dutchess County) serving as the basis for the G-J Locality ICAP Demand Curve the 2021-2025 reset period.

13 Docket No. ER21-502-000, supra, Comments and Protest of the Consumer Stakeholders at 8-

15 (December 21, 2020) (“Consumer Stakeholders Protest”); and Docket No. ER21-502-000, supra,

technology for dual fuel peaking plant designs, however, considers several factors other than

economics. The proposed inclusion of SCR emissions control technology seeks to ensure that a dual fuel peaking plant is reasonably available to support reliable grid operations.
Since its inception, the ICAP Demand Curves for the G-J Locality have used peaking plant designs that include both dual fuel capability and SCR emissions control technology. This plant design remains appropriate.

The inclusion of dual fuel capability remains reasonable and appropriate for the reasons
previously determined by the Commission in prior resets.14 Factors supporting dual fuel
capability for the peaking plant used in determining the G-J Locality ICAP Demand Curve
include: (1) improved operational flexibility and availability; (2) enhanced siting flexibility; and

(3) additional revenue earning opportunities when operation on natural gas becomes uneconomic
or unavailable due to gas system constraints and competing demand for natural gas.15
Additionally, the ongoing transition of the resource mix in New York and expected changes in
the resource fleet heighten the need to retain dual fuel capability as part of the peaking plant
design for the G-J Locality ICAP Demand Curve.16 Dual fuel capability enhances resilience and
operational flexibility. Access to sufficient quantities of flexible resources is of paramount
importance as the level of reliance on weather-dependent renewable generation increases over

Limited Protest and Comments of New York Transmission Owners at 6-15 (December 21, 2020) (“NYTOs Protest”).

14 2021-2025 DCR Filing at 16-20. Contrary to the erroneous assertion by certain parties, the

NYISO does not assume that the peaking plants evaluated for Load Zone G (Dutchess County) and Load
Zone G (Rockland County) interconnect to a load distribution company (“LDC”) gas system. See
Consumer Stakeholders Protest at 16. The NYSO expressly recognized that these locations provide
options for a peaking plant to connect to either a LDC gas system or an interstate pipeline. The inclusion
of dual fuel capability provides for improved siting flexibility by preserving the option to connect to a
LDC gas system in light of LDC tariff-imposed dual fuel requirements. See 2021-2025 DCR Filing at 18.

15 2021-2025 DCR Filing at 17-19; and 2021-2025 DCR Filing at Attachment III (Affidavit of
Paul J. Hibbard, Dr. Todd Schatzki, Charles Wu, and Christopher Llop), ¶ 32-35 (“AG Affidavit”).

16 2021-2025 DCR Filing at 19-20.

time. As demonstrated by the NYISO’s comprehensive fuel security study, dual fuel capability is critically important to maintaining system reliability throughout the ongoing transition of New York’s resource fleet to a clean energy system.17

The inclusion of dual fuel capability results in the potential for a severely constraining
limitation on allowable hours of operation in the absence of including SCR emissions control
technology.18 This limitation arises due to the fact that the nitrogen oxides (“NOx”) emissions
from operation on ultra-low sulfur diesel (“ULSD”) are approximately three times higher than
when operating on natural gas.19 The alternative “synthetic minor” source approach to
permitting establishes a single, fixed annual limit on NOx emissions regardless of the fuel used
to operate. The severely restrictive nature of the applicable operating limits for a dual fuel
peaking plant in the absence of SCR emissions control technology is a primary reason the
NYISO has never proposed use of a dual fuel peaking plant design without back-end controls in
any prior reset.20

The significantly higher emissions resulting from operation using ULSD could result in
allowing as little as approximately 312 hours of operation annually for a dual fuel plant without
SCR emissions control technology.21 Availability to support operations during peak load periods
could reasonably require the capability to operate at least 720 hours annually.22 The potential

17 Id.; and Analysis Group, Inc., Fuel and Energy Security in New York State - An Assessment of
Winter Operational Risks for a Power System in Transition (November 2019) at 70-74, available at:
https://www.nyiso.com/documents/20142/9312827/Analysis%20Group%20Fuel%20Security%20Final%
20Report%2020191111%20Text.pdf.

18 2021-2025 DCR Filing at 11-16.

19 Id. at 15.

20 Id. at 13.

21 Id. 15-16.

22 Id.

severely limiting nature of an annual emission cap in lieu of installing SCR emissions control technology results in a peaking plant that may not reasonably support reliable grid operations.
The already constrained nature of the gas supply system in the downstate region and
difficulties faced in developing incremental gas supply infrastructure increase the likelihood for a dual fuel peaking plant to require use of its alternative fuel source (i.e., ULSD) to provide energy during various periods throughout the year. Inclusion of SCR emissions control technology for all dual fuel peaking plant designs provides important operational availability in support of
reliable grid operations. The Commission should reject requests to exclude such back-end
controls from a peaking plant located in Load Zone G (Dutchess County).

2. The Assumed Gas Interconnection Costs for Locations Outside New York City Are
Reasonable

For locations outside New York City, the NYISO proposes an assumed cost of $250,000
per inch diameter per mile for the linear pipeline costs, plus an additional $3.5 million for a
metering and regulation station for the gas interconnection costs of the proposed peaking
plants.23 Certain parties contend that the assumed linear cost component for a gas
interconnection outside New York City understates the expected cost in New York.24 To support
this position, these parties rely on the cost of a single, recent gas lateral connection in New York
(i.e., the CPV Valley lateral project), and raise concerns regarding the dataset relied on by the

23 Id. at 25-26; and 2021-2025 DCR Filing at Exhibit E of Attachment III, Appendix A. For the proposed peaking plants located outside New York City, the NYISO proposes an assumed 5-mile, 16-
inch diameter lateral with an aggregate cost of $23.5 million.

24 Docket No. ER21-502-000, supra, Protest and Supporting Comments of Independent Power
Producers of New York, Inc. at 19-21 (December 21, 2020) (“IPPNY Protest”); and Docket No. ER21-
502-000, supra, Motion to Intervene and Protest of CPV Valley, LLC at 8-12 (December 21, 2020)
(“CPV Protest”).

independent consultant selected to assist with the 2021-2025 DCR (“Independent Consultant”) to confirm the reasonableness of the assumed lateral costs.25

In developing the assumed linear cost component of the gas interconnection cost, the

Independent Consultant relied on confidential data related to its prior experience with generation
projects, including projects located within New York.26 In addition to non-public data, the
Independent Consultant provided information regarding the linear pipeline cost component for
several recent gas pipeline and lateral projects.27 The publicly available data assessed by the
Independent Consultant included two gas lateral projects for generators interconnected to the
New York Control Area, including the CPV Valley lateral project. The Independent Consultant
also evaluated publicly available information regarding three proposed pipeline projects - two
related to incremental gas supply infrastructure in New York and a third project in close
proximity to New York.28

Based on its prior project experience and professional judgment, the Independent
Consultant estimated a linear component cost of $250,000 per inch diameter per mile for
locations outside New York City. The public cost data confirmed the reasonableness of the
value assumed by the Independent Consultant. To determine the estimated linear pipeline cost
from the publicly available project data, the Independent Consultant excluded costs related to
non-linear equipment and construction components, such as metering, regulating equipment, and
compressor station costs.29 Exclusion of such non-linear cost components provides for

25 Id.

26 2021-2025 DCR Filing at 24-25; and 2021-2025 DCR Filing at Attachment IV (Affidavit of Matthew E. Lind and Kieran McInerney), ¶ 36-37 (“BMCD Affidavit”).

27 Id.

28 Id.

29 BMCD Affidavit at ¶ 37.

consistency with the Independent Consultant’s identification of a separate cost component for
non-linear costs as part of its aggregate gas interconnection cost estimate (i.e., an adder of $3.5
million to the estimated linear pipeline cost). After excluding non-linear component costs, the
Independent Consultant identified a range of linear pipeline costs from approximately $100,000
to $500,000 per inch per diameter mile for the public data evaluated.30 The average linear cost
from this dataset was approximately $260,000 per inch diameter per mile.31 The NYISO’s

proposed linear cost value is within the above-identified range and nearly equivalent to the

average value of the dataset, thereby confirming the reasonableness of the estimate developed based on the Independent Consultant’s professional judgment and experience.
Certain parties contend that the inclusion of cost data related to longer-distance pipeline expansion projects undermines the value of the dataset evaluated by the Independent
Consultant.32 Importantly, although the dataset includes costs related to certain pipeline
expansions, the two gas laterals for the generators interconnected to New York establish the highest and lowest values of the observed range of linear cost estimates. Excluding
consideration of the cost data for longer-distance pipelines, the assumed linear cost remains in a range between these two values and near the midpoint thereof.

Furthermore, use of a dataset relating to multiple projects avoids the potential for

establishing costs based on a single project that may have unique circumstances that are not

30 2021-2025 DCR Filing at 25; and BMCD Affidavit at ¶ 37.

31 Id. Certain parties erroneously claim that the Independent Consultant excluded consideration
of the CPV Valley lateral project and the Bayonne lateral delivery project from its assessment. See CPV
Protest at 9-10. To the contrary, the Independent Consultant retained these projects as part of the dataset
and accounted for them in calculating the average linear cost of $260,000 per inch diameter per mile for
all projects within the dataset. Simply as an alternative means of evaluating the data provided from the
projects evaluated, the Independent Consultant also noted that the average linear cost would reduce

slightly to $240,000 per inch diameter per mile if the highest and lowest observed linear costs were not included in the calculation. See 2021-2025 DCR Filing at 25; and BMCD Affidavit at ¶ 37.

32 IPPNY Protest at 19-20; and CPV Protest at 9-10.

broadly applicable to other gas interconnection projects. Significant variations in costs occur
from project to project given the specific circumstances, conditions, and challenges faced by
each project.33 Assessing costs for multiple projects assists with avoiding the inclusion of
unnecessary costs that may result from the conditions and circumstances attendant to one
particular project. This facilitates an appropriate evaluation for purposes of determining a
reasonable cost estimate for a generic, non-site specific estimate as required by the DCR.
CPV Valley, LLC (“CPV”) recommends the use of an alternative dataset replacing the longer-distance pipeline project costs with alternative shorter-distance laterals related to various generation projects.34 CPV contends that such a revised dataset demonstrates that the NYISO’s proposed linear cost component is understated. The linear cost estimates calculated by CPV are inaccurate and overstated due to CPV’s apparent failure to exclude costs related to non-linear equipment and construction costs as was done by the Independent Consultant.35 These non-
linear components comprise a material portion of total project costs.36 Failing to exclude these

33 BMCD Affidavit at ¶ 37.

34 CPV Protest at 10-11.

35 Based on a review of the applications filed with the Commission for the projects evaluated by
CPV, it appears CPV estimated the linear costs by utilizing the total aggregate project costs, including
non-linear cost components. The Declaration of Daniel Nugent included as Attachment A to the CPV
Protest confirms this methodological error by generally describing that CPV calculated its linear cost
estimates by dividing the total cost for each project by the length thereof. See Docket No. CP20-30-000,
Texas Eastern Transmission, LP, Abbreviated Application for a Certificate of Public Convenience and
Necessity and for Related Authorizations at Volume I, Exhibit K (December 19, 2019); Docket No.
CP16-473-000, Texas Eastern Transmission, LP, Abbreviated Application for a Certificate of Public
Convenience and Necessity and for Related Authorizations at Volume I, Exhibit K (June 29, 2016);
Docket No. CP16-17-000, Millennium Pipeline Company, L.L.C., Abbreviated Application for a
Certificate of Public Convenience and Necessity at Volume I, Exhibit K (November 13, 2015); Docket
No. CP14-18-000, Transcontinental Gas Pipeline Company, LLC, Application for a Certificate of Public
Convenience and Necessity at Volume I, Exhibit K (November 7, 2013); and Docket No. CP09-417-000,
Transcontinental Gas Pipeline Company, LLC, Application for a Certificate of Public Convenience and
Necessity at Volume I, Exhibit K (May 22, 2009).

36 The cost estimates included in the initial applications submitted to the Commission for each of
the projects evaluated by CPV indicate that, on average, non-linear costs accounted for more than 20% of
the total estimated project costs. See Docket No. CP20-30-000, Texas Eastern Transmission, LP,

costs produces inflated linear cost estimates for each project. Additionally, the Bayway lateral project cited by CPV includes a gas lateral providing service to two, distinct customers - a
refinery and a gas-fired generator.37 Despite the nature of the project, CPV’s analysis assigns all costs related to the lateral to the generation facility. This assumption is inaccurate and inflates the portion of costs incurred by such generation facility.

The estimated gas lateral costs for the proposed peaking plants outside New York City represent reasonable costs based on the prior experience of the Independent Consultant,
including work on generation development projects in New York. The Independent Consultant further supported its linear cost component based on a review of publically available cost data for relevant gas pipeline and gas laterals projects.

3. The Assumed Land Lease Cost Within New York City Is Reasonable and Adequate
Certain parties erroneously insinuate that the NYISO solely based its proposed land lease cost of $270,000 per acre-year for New York City on escalating the value from the last reset.38 Such assertions are not accurate. While the Independent Consultant initially derived the assumed

Abbreviated Application for a Certificate of Public Convenience and Necessity and for Related

Authorizations at Volume I, Exhibit K (December 19, 2019); Docket No. CP16-473-000, Texas Eastern
Transmission, LP, Abbreviated Application for a Certificate of Public Convenience and Necessity and for
Related Authorizations at Volume I, Exhibit K (June 29, 2016); Docket No. CP16-17-000, Millennium
Pipeline Company, L.L.C., Abbreviated Application for a Certificate of Public Convenience and
Necessity at Volume I, Exhibit K (November 13, 2015); Docket No. CP14-18-000, Transcontinental Gas
Pipeline Company, LLC, Application for a Certificate of Public Convenience and Necessity at Volume I,
Exhibit K (November 7, 2013); and Docket No. CP09-417-000, Transcontinental Gas Pipeline Company,
LLC, Application for a Certificate of Public Convenience and Necessity at Volume I, Exhibit K (May 22,
2009).

37 See Docket No. CP16-473-000, Texas Eastern Transmission, LP, Abbreviated Application for
a Certificate of Public Convenience and Necessity and for Related Authorizations at Volume I (June 29,
2016).

38 IPPNY Protest at 20-21.

lease cost value by escalating values from the last reset, the Independent Consultant conducted a supplemental analysis to confirm the reasonableness of the escalated values.39
The Independent Consultant’s supplemental analysis expressly considered recent
appraisal information submitted by certain stakeholders regarding certain existing generator sites located within New York City.40 The supplemental analysis, in part, sought to determine
whether such appraisal data was broadly applicable to potential generation sites within New
York City. The supplemental analysis identified significant variability as to lease costs for
potential sites within New York City.41

This data demonstrated that the appraisal data submitted by certain stakeholders was

likely not appropriate for broader application to all potential generation sites within New York City. Notably, the Independent Consultant’s supplemental analysis included nine sites adjacent to existing generation facility sites within New York City.42 The proposed lease cost for the
2021-2025 DCR represents a reasonable value within the range of the average lease cost
observed across multiple properties adjacent to existing generation facility sites within New
York City (i.e., $160,712 per acre-year) and the average of the appraisal values submitted by
certain stakeholders (i.e., $645,509 per acre-year).43 Selection of a value within this range is
consistent with expectation that a developer of new plant in a competitive market will seek to
minimize its costs to the extent practicable.

39 2021-2025 DCR Filing at 26-27; and BMCD Affidavit at ¶ 38-40.

40 Id. The stakeholder-provided data included in the Independent Consultant’s supplemental analysis is the appraisal data described in the IPPNY Protest. See IPPNY Protest at 21-22.

41 2021-2025 DCR Filing at 26-27; and BMCD Affidavit at ¶ 38-40.

42 Id.

43 Id.

4. The Estimated Capital Costs, Including the Owner’s Cost Component, Appropriately
Account for all Cost Categories

Certain parties erroneously assert that the Independent Consultant’s estimated owner’s cost fails to fully account for certain cost components, including development, engineering, and financing fees during construction.44 To support their contention, these parties attempt to
compare particular costs on a line-item by line-item basis from the last reset to the estimates developed for the 2021-2025 DCR.45

The engineering and design firm used for the 2021-2025 DCR is not the same entity used
for the last reset.46 Although both firms developed cost estimates consistent with typical industry
practices, the methodologies and cost categorization used by each firm differs.47 As a result,
attempting to conduct line-item by line-item comparisons of the cost estimates from the last reset
to those developed for the 2021-2025 DCR is not appropriate and likely to yield misleading
results.48

To demonstrate that the cost estimates developed for the 2021-2025 DCR appropriately
account for all relevant cost considerations, the Independent Consultant conducted a
supplemental assessment to provide a reasonable and accurate comparison of its estimates to
those from the last reset.49 This analysis clearly demonstrates that the Independent Consultant’s
cost estimates for the 2021-2025 DCR appropriately account for the same relevant cost
components included in the estimates developed for the last reset. The analysis demonstrates

44 IPPNY Protest at 18-19; and CPV Protest at 22-24.

45 Id.

46 2021-2025 DCR Filing at 22-23.

47 2021-2025 DCR Filing at 22-23; and BMCD Affidavit at ¶ 41-44.

48 Id.

49 2021-2025 DCR Filing at 22-23; and BMCD Affidavit at ¶ 45.

that after accounting for inflation of dollar values from the last reset to 2020 dollar values, the
aggregate owner’s cost estimates developed by the two engineering and design firms differ by
less than $200,000 (or approximately 0.3%) for an equivalent peaking plant design and
location.50 The difference for total aggregate capital costs developed by the two firms differs by
less than 1%.51

Contrary to the assertions of certain parties, the Independent Consultant’s supplemental
analysis demonstrates that its cost estimates are accurate and complete. The perceived
deficiencies raised by certain parties are merely the result of the differences in the methodologies
and cost categorization employed by two differing engineering and design firms. Thus, the
Commission should accept the proposed capital cost estimates without modification.

B. Net Energy and Ancillary Services Revenue Estimates

Certain parties oppose the gas hubs proposed by the NYISO for use in estimating the
variable operating costs of the proposed peaking plants in Load Zone C and Load Zone G
(Rockland County). The NYISO’s proposed gas hubs for these locations are reasonable and
appropriate for the 2021-2025 DCR.52 The Commission should reject requests to alter the
NYISO’s proposed gas hubs for Load Zone C and Load Zone G (Rockland County).

1. The Proposed Use of the Niagara Hub for Winter Months for Load Zone C Facilitates
Reasonable Estimates of the Potential Energy and Ancillary Services Revenues

Certain parties contend that the Commission should direct the NYISO to eliminate use of
the Niagara hub during the winter period (i.e., December through March) for Load Zone C.53

50 Id.

51 Id.

52 2021-2025 DCR Filing at 35-40 and 41-43; and 2021-2025 DCR Filing at Attachment VI (Affidavit of Pallas LeeVanSchaick, Ph.D.), ¶ 10-39 (“MMU Affidavit”).

53 NYTOs Protest at 16-37; and Consumer Stakeholders Protest at 21-24. Contrary to the

misleading insinuations by certain parties, the time allotted for oral presentations to the NYISO Board of

These parties claim that the NYISO’s proposal to use the Tennessee Gas Pipeline (“TGP”) Zone

4 (200 leg) hub for April through November and the Niagara hub for December through March is
less representative of the likely gas prices faced by a peaking plant in Load Zone C than use of
either the TGP Zone 4 (200 leg) hub or the Dominion North hub as the sole hub throughout the
year.54 These parties also raise concerns regarding the robustness of the pricing for the Niagara
hub.55

Parties opposing the NYISO’s proposal to use the Niagara hub for the winter period (i.e.,
December through March) allege that the NYISO’s proposal results in lower correlation with
historical operation of gas-fired generators located in Load Zone C than use of either the TGP
Zone 4 (200 leg) hub or Dominion North hub for the entire year.56 Such claims rely on an
assessment conducted by the Market Monitoring Unit (“MMU”) to assist in evaluating various
potential gas hub options for Load Zone C.57 However, these claims fail to account for critical
seasonal differences in correlation. The MMU’s analysis identified that during stressed winter
operating conditions, such as the bomb cyclone and extended Northeast cold snap of the 2017-
2018 winter period, both the TGP Zone 4 (200 leg) hub and Dominion North hub significantly

Directors (“Board”) to address the 2021-2025 DCR was equivalent to past resets. See NYTOs Protest at 39-40. The Board’s determination ultimately reflected its consideration of feedback and comments
provided throughout the DCR, including the written comments submitted by parties to the Board on October 9, 2020. The Board’s determination was not limited to only consideration of the oral
presentations by interested parties on October 19, 2020.

54 NYTOs Protest at 18-28 and 35-37; and Consumer Stakeholders Protest at 21-24.

55 NYTOs Protest at 28-35; and Consumer Stakeholders Protest at 23.

56 NYTOs Protest at 18-28; and Consumer Stakeholders Protest at 24.

57 MMU Affidavit at ¶ 13-15. Certain parties erroneously allege that the MMU’s analysis did not include information related to the use of the Niagara hub prices on the historical dispatch of gas-fired
generators in Load Zone C. See Consumer Stakeholders Protest at 23. Contrary to these erroneous
claims, the analysis conducted by the MMU and submitted as part of the 2021-2025 DCR Filing expressly included results using the Niagara hub prices. See MMU Affidavit at ¶ 13.

overestimated the actual, historic operation of gas-fired generators in Load Zone C, resulting in
artificially inflated estimates of the potential revenue earnings during these critical periods.58
As demonstrated by supplemental analysis conducted by the MMU, the overestimation of potential revenues during winter periods is due to gas pipeline system constraints that limit the availability to deliver gas from the TGP Zone 4 (200 leg) hub to Load Zone C during winter
months.59 This assessment of pipeline capacity utilization demonstrated that sufficient pipeline
capacity is often unavailable during the winter months to accommodate deliveries of gas from
the TGP Zone 4 (200 leg) hub to a peaking plant in Load Zone C.60 Failure to account for such
conditions could result in artificially overestimating potential energy market revenues during the
winter period.

The Niagara hub provides a reasonable and appropriate alternative that better represents
likely gas prices faced by a peaking plant in Load Zone C during the winter period. Unlike the
TGP Zone 4 (200 leg) hub and the Dominion North hub, the Niagara hub does not result in an
artificial overestimate of historic operation by gas-fired generators in Load Zone C during
critical winter periods.61 The Niagara hub also does not experience the historic availability
constraints identified with respect to use of the TGP Zone 4 (200 leg) during the winter period.62
Certain parties opposing the use of the Niagara hub during the winter period raise
potential concerns regarding the level of trading activity and availability of pricing for the

58 2021-2025 DCR Filing at 36-37; and MMU Affidavit at ¶ 13-15 and 22-23. Comparatively,
the Dominion North hub exhibited larger magnitude and more persistent overestimates of historic
operations during winter periods demonstrating its inferiority to the TGP Zone 4 (200 leg) hub.

59 2021-2025 DCR Filing at 36-37; and MMU Affidavit at ¶ 16-21.

60 Id.

61 2021-2025 DCR Filing at 36-37; and MMU Affidavit at ¶ 13-15.

62 MMU Affidavit at ¶ 19 and 21.

Niagara hub.63 These claims rely on data and information from an entity other than the vendor
proposed by the NYISO to serve as the gas price data source for the 2021-2025 DCR. Data and information from a different vendor is less relevant and probative than historical information
from the NYISO’s proposed vendor (i.e., S&P Global Market Intelligence or “SPGMI”).64 The NYISO’s analysis of data and information from SPGMI found that SPGMI published a gas price for the Niagara hub for each day during the December through March period on which gas prices are normally published by indices for the three-year data period used in determining revenue
estimates for the 2021/2022 Capability Year ICAP Demand Curves.65 The NYISO also assessed historic trading activity for the Niagara hub using data obtained from SPGMI. This analysis
demonstrated that, during the winter months when the NYSO proposes to use the Niagara hub,
trading activity was comparable and in some cases greater than other gas hubs either considered for Load Zone C or proposed for use for other Load Zones.66

The NYISO’s proposal to use the TGP Zone 4 (200 leg) hub for April through November and the Niagara hub for December through March is reasonable and appropriate. This proposal accounts for identified constraints that limit the availability of gas from the TGP Zone 4 (200 leg) hub to a peaking plant in Load Zone C during winter months. The NYISO’s proposal seeks to avoid the potential for unnecessary over- or under-estimating of potential energy market
revenues for a peaking plant in Load Zone C.

63 NYTOs Protest at 28-35; and Consumers Stakeholders Protest at 23-24.

64 SPGMI is the successor to SNL Financial. The Commission approved use of SNL Financial as the gas price data vendor for the 2017-2021 reset period. No party has raised any issues or concerns with the NYISO’s proposal to continue use of this data vendor for the 2021-2025 DCR.

65 2021-2025 DCR Filing at 38-39; and 2021-2025 DCR Filing at Attachment V (Affidavit of Zachary T. Smith), ¶ 14 (“NYISO Affidavit”).

66 2021-2025 DCR Filing at 38-40; and NYISO Affidavit at ¶ 14.

2. Texas Eastern Transmission Pipeline (“TETCO”) M3 Is the Appropriate Gas Hub for
Load Zone G (Rockland County)

Certain parties assert that the TETCO M3 hub is not an appropriate gas hub for Load

Zone G (Rockland County).67 These parties contend that the Commission should direct the

NYISO to use the Iroquois Zone 2 hub for Load Zone G (Rockland County).68 To support their position, these parties provide information primarily addressing the availability of interruptible transportation service to accommodate deliveries of gas from the TETCO M3 hub to a peaking plant in Load Zone G (Rockland County).69

Parties opposing the use of the TETCO M3 hub as the appropriate gas hub for Load Zone G (Rockland County) contend that historic data demonstrates limited availability of interruptible service on the Algonquin pipeline to facilitate deliveries of gas to Load Zone G (Rockland
County).70 These parties also contend that the MMU’s analysis is insufficient due to the failure to include information related to interruptible transportation or “IT” flags posted by the
Algonquin pipeline.71 Consistent with other data and information provided by protesting parties, such data relates to the availability of interruptible service and does not otherwise undermine consideration of other gas purchase options that may be available to accommodate deliveries of gas from the TETCO M3 hub to Load Zone G (Rockland County).72

67 Docket No. ER21-502-000, supra, Limited Protest of GenOn Bowline, LLC and GenOn

Energy Management, LLC at 10-22 (December 21, 2020) (“GenOn Protest”); IPPNY Protest at 24-28; and CPV Protest at 12-22.

68 GenOn Protest at 22-25; IPPNY Protest at 28; and CPV Protest at 17-22.

69 GenOn Protest at 10-22; IPPNY Protest at 24-27; and CPV Protest at 12-17.

70 Id.

71 GenOn Protest at 8-11 and 12-15; IPPNY Protest at 26-27; and CPV Protest at 15-16.

72 Supplemental Affidavit of Pallas LeeVanSchaick, Ph.D. at ¶ 6-7 and 12-16 attached hereto as
Attachment I (“MMU Supplemental Affidavit”). As permitted by the Commission’s August 20, 2020
order extending the previous emergency waiver of notarization rules, the MMU Supplemental Affidavit

These parties erroneously presume that the DCR requires or assumes that the peaking plant will rely solely on interruptible service to obtain gas. The NYISO does not assume any particular gas purchasing strategy for the peaking plants.73 This recognizes that a peaking plant can avail itself of multiple gas purchasing strategies. In addition to interruptible service, a
peaking plant could pursue purchases of secondary firm transportation or other arrangements with entities holding unused firm transportation rights.74

Focusing solely on availability of the interruptible transportation service as indicated by
IT flag data is not dispositive.75 This information does not fully account for broader utilization
of pipeline capacity. Notably, an IT flag data indicator of “N” does not necessarily indicate
complete unavailability of such service.76 IT flag indicators more broadly indicate utilization of
interruptible transportation service.77 An IT flag indicator of “N” may simply reflect that parties
have elected not to utilize interruptible transportation service for the period at issue. Non-use of
interruptible transportation service can arise from economic decisions to forego such service due
to the availability of lower cost alternatives. The MMU’s analysis of the pipeline capacity
utilization appropriately evaluates the general availability of alternative options to obtain
deliveries of gas to a peaking plant in Load Zone G (Rockland County).78

has not been notarized. See Temporary Action to Facilitate Social Distancing, 172 FERC ¶ 61,151
(2020).

73 2021-2025 DCR Filing at 34-35.

74 2021-2025 DCR Filing at 34-35 and 42-43; and MMU Affidavit at ¶ 25 and 27-30.

75 MMU Supplemental Affidavit at ¶ 11-12.

76 Id. at ¶ 11.

77 Id.

78 2021-2025 DCR Filing at 41-43; MMU Affidavit at ¶ 24-39; and MMU Supplemental Affidavit at ¶ 6-7 and 11-16.

Certain parties erroneously allege that the analysis conducted by the MMU is limited to
evaluating pipeline capacity utilization following the timely nomination cycle.79 Such statements
are incorrect. The analysis conducted by the MMU and submitted as part of the 2021-2025 DCR
Filing considered data regarding pipeline capacity utilization for both the timely and intraday 3
nomination cycles.80 In assessing the availability of otherwise unused pipeline capacity to
accommodate deliveries for the proposed peaking plant in Load Zone G (Rockland County), the
MMU utilized the lower of the available pipeline capacity values reported for these two
nomination cycles.81

The MMU’s analysis identified that secondary transportation may often be a more
economically rational purchasing strategy.82 Interruptible transportation is available on the
Algonquin pipeline at a cost of $0.2867 per MMBtu.83 The cost of acquiring secondary
transportation depends on an opportunity costs for the owner of the firm transportation rights.
The opportunity cost is generally determined based on gas price spreads between less
constrained and more constrained pricing points along the path covered by the firm
transportation service.84 This opportunity cost is often lower than the cost of interruptible
transportation when available pipeline capacity is not fully utilized. For example, the MMU’s
analysis identified that when pipeline capacity utilization on the Algonquin pipeline was below
95% of the total capability for segments between Rockland County and Massachusetts, the
average difference in gas prices between the TETCO M3 hub and the Algonquin Citygates hub

79 CPV Protest at 14-15.

80 MMU Affidavit at ¶ 33-34.

81 Id.

82 MMU Affidavit at ¶ 27-30.

83 Id. at ¶ 27.

84 Id. at ¶ 28-30.

was approximately $0.15 per MMBtu.85 In these cases, an economically rational peaking plant would seek to utilize secondary transportation rather than more expensive interruptible
transportation service.

The MMU’s analysis concluded that constraints on the Algonquin pipeline typically arise
downstream of the segments used to deliver gas from the TETCO M3 hub to Rockland County.86
Although certain recent projects have upgraded portions of the Algonquin pipeline, these
upgrades have not eliminated the fact that pipeline segments downstream of Rockland County
experience more frequent constraints than the pipeline segments facilitating deliveries from the
TETCO M3 hub to Rockland County.87 These downstream constraints are unlikely to adversely
impact the availability of transportation on the segments of the Algonquin pipeline that facilitate
deliveries to Rockland County.88

Given the availability of reasonable alternatives to sole reliance on interruptible

transportation service, the MMU appropriately analyzed broader pipeline capacity utilization

information in determining whether TETCO M3 represented a reasonable gas hub for Load Zone G (Rockland County).89 The MMU’s assessment determined that sufficient pipeline capacity generally remains available to accommodate delivery of the amount of gas used by the proposed peaking plant in Load Zone G (Rockland County).90

85 Id. at ¶ 29-30; and MMU Supplemental Affidavit at ¶ 7.

86 MMU Affidavit at ¶ 32 and 39; and MMU Supplemental Affidavit at ¶ 6-7 and 14-16.

87 MMU Supplemental Affidavit at ¶ 13-14.

88 MMU Affidavit at ¶ 32; and MMU Supplemental Affidavit at ¶ 13-16.

89 2021-2025 DCR Filing at 42-43; and MMU Affidavit at ¶ 31-39.

90 2021-2025 DCR Filing at 42-43; MMU Affidavit at ¶ 33; and MMU Supplemental Affidavit at ¶ 6-7, 9, and 14-16.

Consideration of additional factors, such as IT flag data and firm service capacity held by
“no-notice” shippers would not alter the conclusions of the MMU’s assessment.91 Available
pipeline data indicates that constraints and restrictions imposed by Algonquin relate to segments
of the pipeline downstream of Rockland County.92 These limitations do not support a conclusion
that similar restrictions and availability limitations exist for the segments of the Algonquin
pipeline that facilitate deliveries of gas from the TETCO M3 hub to Rockland County.93
Contrary to assertions of certain parties that the peaking plant would be unable to operate for much of the year due to the limited availability of interruptible transportation service,94 the MMU’s analysis concluded that sufficient pipeline capacity was available in nearly all hours to accommodate deliveries of gas in quantities consistent with the estimated operation of the
peaking plant in Load Zone G (Rockland County) for the three-year period used in determining
the ICAP Demand Curves for the 2021/2022 Capability Year.95 Certain parties erroneously
assert that the MMU’s analysis was limited to assessing data on a monthly basis.96 Contrary to
such claims, the analysis conducted by the MMU accounted for daily availability of pipeline
capacity.97 Specifically, the MMU identified that sufficient pipeline capacity remained available
to serve the estimated dispatch of the peaking plant, as determined by the net energy and

91 MMU Supplemental Affidavit at ¶ 11-12 and 15.

92 Id. at ¶ 6 and 14-16.

93 Id. at ¶ 11-16.

94 GenOn Protest at 18-19; IPPNY Protest at 27; and CPV Protest at 15-16.

95 MMU Affidavit at ¶ 34; and MMU Supplemental Affidavit at ¶ 9.

96 GenOn Protest at 9.

97 MMU Supplemental Affidavit at ¶ 9-10.

ancillary model, in 89% of all hours for the three-year period from September 1, 2017 through August 31, 2020.98

The NYISO’s proposal to use separate gas hubs for the two locations evaluated in Load
Zone G is consistent with prior DCRs. In fact, the DCR that established the ICAP Demand
Curves for the 2014/2015 through 2016/2017 Capability Years used the same gas hubs proposed
by the NYISO for this reset - the Iroquois Zone 2 hub for Load Zone G (Dutchess County) and
the TETCO M3 hub for Load Zone G (Rockland County).99 Use of the Iroquois Zone 2 hub for
Load Zone G (Rockland County), as recommended by certain parties,100 would not be
appropriate for the 2021-2025 DCR. The Iroquois Zone 2 hub is likely to materially understate
potential revenues earnings for a peaking plant in Load Zone G (Rockland County), resulting in
an artificially inflated estimate of the net cost of new entry for this location.101
The NYISO carefully reviewed and evaluated relevant data and information in selecting TETCO M3 as the gas hub for Load Zone G (Rockland County).102 The NYISO’s proposal appropriately accounts for pipeline capacity availability to facilitate deliveries of gas from the TETCO M3 gas hub to a peaking plant in Load Zone G (Rockland County). TETCO M3 is a reasonable gas hub that appropriately seeks to avoid unnecessary underestimating or
overestimating of potential energy market revenues for a peaking plant located in Load Zone G
(Rockland County).

98 MMU Affidavit at ¶ 34; and MMU Supplemental Affidavit at ¶ 9.

99 2021-2025 DCR Filing at 41; and Docket No. ER17-386-000, New York Independent System
Operator, Inc., Proposed ICAP Demand Curves for the 2017/2018 Capability Year and Parameters for
Annual Updates for Capability Years 2018/2019, 2019/2020 and 2020/2021 at 29, n. 126 (November 18,
2016).

100 GenOn Protest at 22-25; IPPNY Protest at 28; and CPV Protest at 17-22.

101 2021-2025 DCR Filing at 41-43; MMU Affidavit at ¶ 35-39; and MMU Supplemental Affidavit at ¶ 6-7 and 9.

102 2021-2025 DCR Filing at 41-43; and MMU Affidavit at ¶ 23-39.

C. Financial Parameters

The conversion of upfront capital investment costs for each peaking plant, including
property taxes and insurance, into annualized values requires the determination of parameters,
such as: (1) the appropriate weighted average cost of capital (“WACC”) required by a developer
to recover its up-front costs, plus a reasonable return on its investment; and (2) the appropriate
term in years over which recovery occurs (commonly referred to as the “amortization period”).
The NYISO proposes to adopt the financial parameters developed by the Independent
Consultant, including: (1) a return on equity (“ROE”) value of 13%; (2) an assumed cost of debt
(“COD”) equal to 6.7%; (3) a debt-to-equity ratio of 55/45; and (4) a 17-year amortization
period.103

Certain parties raise concerns regarding the proposed ROE and COD values, as well as the recommended 17-year amortization period. Certain parties advocate for the adoption of
lower ROE and COD values.104 Other parties contend these values are understated and do not adequately account for the risk of investing in a new peaking plant in New York.105 Parties also express divergent positions with respect to the proposed amortization period. Certain parties advocate for increasing the amortization period to 20 years,106 while other parties seek adoption of a shorter, 15-year amortization period.107

103 2021-2025 DCR Filing at 47-53.

104 Consumer Stakeholders Protest at 24-26. 105 IPPNY Protest at 14-19.

106 Consumer Stakeholders Protest at 18-21; and Docket No. ER21-502-000, supra, Motion to Intervene and Comments of the Market Monitoring Unit on the New York ISO’s ICAP Demand Curve Reset at 3-13 (December 21, 2020) (“Potomac Economics Comments”).

107 IPPNY Protest at 9-14.

The Independent Consultant developed the proposed values based on a review of relevant market data and information, and its reasoned judgment and professional experience.108 The proposed values are reasonable and appropriate. The Commission should adopt the proposed financial parameter values without modification.

1. The Proposed ROE and COD Values Are Reasonable and Supported by Relevant
Data and Information

Parties advocate divergent positions in favor of either increasing or decreasing the

proposed 13% ROE value. The Independent Consultant derived this value following the review of various data sources addressing various project development finance approaches and the returns required by developers of merchant power plants.109

The Independent Consultant estimated ROE values for publicly traded independent

power producers (“IPPs”) of up to 10.5%.110 The Independent Consultant also identified that

stand-alone project finance approaches exhibited ROE values ranging from 12% to 20%.111 The proposed 13% value is within the range of values identified. Considered in combination with the remaining financial parameters, the value reasonably supports the development of a merchant peaking plant in New York.

Similar to the recommended ROE value, parties express divergent positions seeking to
either increase or decrease the recommended 6.7% COD value. Parties advocating for a lower
COD value note that the proposed value exceeds the currently observed debt cost for generic B-
rated corporate debt.112 Parties advocating for a higher COD value contend that proposed value

108 2021-2025 DCR Filing at 47-53; and AG Affidavit at ¶ 65-82.

109 2021-2025 DCR Filing at 48-49; and AG Affidavit at ¶ 76.

110 Id.

111 Id.

112 Consumer Stakeholders Protest at 24-25.

does not adequately account for the risk of investing in a merchant peaking plant in New York and the costs attendant thereto, such as the potential need to execute financial hedges to secure financing.113 The Independent Consultant’s assessment of debt costs incurred by publicly traded IPPs since 2017 and financial market data regarding debt costs for corporate debt identified a range of reasonable COD values from 4% to 8%.114

The Independent Consultant assumed B-rated corporate debt in assessing the appropriate
debt cost because publicly traded IPPs generally exhibit ratings below investment grade and in
consideration of the relative risk attendant to pursuing a non-recourse, stand-alone financing
approach for project development.115 In selecting a 6.7% COD value, the Independent
Consultant recognized that debt costs for generic B-rated corporate debt would likely decline
over time as the financial markets continued to settle in response to the ongoing COVID-19
pandemic.116 The Independent Consultant, however, recommended a COD value slightly above
generic debt ratings in recognition of the fact that: (1) IPPs tend to experience debt costs that
somewhat exceed contemporaneous debt cost indices; (2) merchant investment in a new peaking
plant in New York faces higher financial risks; and (3) securing debt financing for a merchant
peaking plant may impose certain costs not expressly quantified, such as the potential need to
execute financial hedges.117

The proposed ROE and COD values fall within the range of reasonable assumptions

identified by the Independent Consultant. The Independent Consultant fully evaluated relevant

113 IPPNY Protest at 17-19; and CPV Protest at 24-26.

114 2021-2025 DCR Filing at 49-50; and AG Affidavit at ¶ 74-75.
115 2021-2025 DCR Filing at 49-50; and AG Affidavit at ¶ 75.

116 Id.

117 Id.

data and information in developing the recommended values and fully supported the values selected based on the assessment undertaken.

2. The Proposed Amortization Period Is Reasonable Given the Current Status of the
Climate Leadership and Community Protection Act Implementation

A primary consideration underlying the NYISO’s proposed 17-year amortization period
is the requirement established by the Climate Leadership and Community Protection Act
(“CLCPA”) to transition to 100% zero-emission electricity supply in New York by 2040.118
Certain parties advocate for increasing the amortization period to 20 years given that fossil-fired
generators could potentially pursue retrofitting or other modifications in the future to continue
operation in compliance with the CLCPA’s zero-emission requirement.119 Other parties request
that the Commission direct the reduction of the amortization to 15 years given the likely
timeframe for a new facility to commence operation during the 2021-2025 reset period.120
The proposed amortization period represents the average period of years between the beginning of each Capability Year covered by the 2021-2025 reset period and the January 1, 2040 deadline established by the CLCPA for achieving 100% zero-emission electricity supply. The proposed 17-year amortization period reasonably represents the period a new fossil-fuel fired peaking plant can operate absent retrofitting or other modifications to operate in
compliance with the CLCPA’s zero-emission requirement.121 Determining the amortization
period in this manner is appropriate because the DCR implicitly assumes that the peaking plants

118 2021-2025 DCR Filing at 51-53; and AG Affidavit at ¶ 68-69.

119 Consumer Stakeholders Protest at 18-21; and Potomac Economics Comments at 3-13. 120 IPPNY Protest at 9-14.

121 2021-2025 DCR Filing at 51-53; and AG Affidavit at ¶ 68-69.

underlying each ICAP Demand Curve are initially in service as of May 1, 2021 (i.e., the

beginning of the first Capability Year encompassed by this DCR).122

Notably, the Services Tariff does not permit the NYISO to recalculate the applicable
localized levelized capital cost (commonly referred to the “gross cost of new entry” or “Gross
CONE”) utilizing differing amortization periods over the course of each reset. As part of the
tariff-prescribed annual updates, the Services Tariff limits adjustments to Gross CONE values to
only the application of a composite escalation factor to the applicable Gross CONE values
underlying the ICAP Demand Curves for the first Capability Year of the reset period.123 Use of
the average period of operation prior to 2040 for the proposed peaking plants over the course of
the 2021-2025 reset period reasonably accounts for the requirements of the tariff.
The NYISO’s proposed 17-year amortization period also appropriately accounts for the current state of regulations and programs to implement the CLCPA’s zero-emission requirement. Regulations and programs to implement the CLCPA’s zero-emission requirement will be
developed and refined over the coming years. At this time, however, no regulations or programs
have been developed and/or implemented to define the eligibility requirements to comply with
the 2040 zero-emission requirement.124 Such regulations and/or programs are necessary to
define potential pathways for fossil-fuel fired generation to pursue retrofits or other
modifications to facilitate operation as a zero-emission resource. Absent regulations and/or
programs to define potential pathways for fossil-fuel fired generation to pursue retrofits or other
modifications to facilitate operation as a zero-emission resource, the NYISO is unable to

122 2021-2025 DCR Filing at 52.

123 Services Tariff § 5.14.1.2.2.1.

124 2021-2025 DCR Filing at 52-53.

estimate the potential capital costs related to any such conversion or identify with any reasonable certainty the variable operating costs associated with operating as a zero-emission resource.125
For the 2021-2025 DCR, assuming any retrofitting or other modifications to facilitate transition to a zero-emission resource in the absence of such regulations and/or programs
requires speculation in contravention of Commission precedent.126 The Commission has
consistently held that the NYISO should not speculate as to future laws and/or regulations for purposes of decisions in each DCR.127 Instead, the Commission requires that the NYISO
consider applicable laws and regulations currently in effect at the time of each reset. The
requirement to conduct the DCR every four years provides the appropriate means for assessing the implications of changes to existing laws and regulations over time.

Certain parties recommend an alternative approach that involves using a 20-year

amortization period, while eliminating energy revenues for the last three years of the 20-year
period.128 This alternative approach is not reasonable because it relies on assumption that the
peaking plant is capable of operating to produce energy, if required. Energy production
capability hinges on the ability to operate in continued compliance with the CLCPA’s zero-
emission requirement after 2039. Due to the current absence of regulations or other program
rules that would facilitate the potential for fossil-fuel fired generators to pursue retrofitting or
other modifications to operate as a zero-emission resource, presumed operation beyond 2039

125 AG Affidavit at ¶ 68-69.

126 2021-2025 DCR Filing at 52-53; and AG Affidavit at ¶ 69. Notably, certain parties

advocating for the use of a 20-year amortization period acknowledge the absence of implementing

regulations and the difficulty this presents for this reset in attempting to assess potential pathways for a fossil-fuel fired generator to continue operating beyond 2039 or the costs associated therewith. See, e.g., Potomac Economics Comments at 5-6 and 9.

127 See, e.g., New York Independent System Operator, Inc., 158 FERC ¶ 61,028 at P 61 (2017); and New York Independent System Operator, Inc., 146 FERC ¶ 61,043 at P 74 (2014).

128 Consumer Stakeholders Protest at 20.

would require speculation as to regulations and programs to implement the CLCPA’s zeroemission requirement that do not exist at this time.

The proposed 17-year amortization period reasonably accounts for the current state of
regulations and programs to implement the CLCPA’s zero-emission requirement and the
operational life of the proposed peaking plants through 2039. The NYISO will continue to
monitor the development of regulations and programs to implement the requirements of the
CLCPA over the coming years. The NYISO will consider such information and the implications
thereof in future resets.

III.CONCLUSION

The NYISO’s proposal for the 2021-2025 DCR is just and reasonable. The NYISO respectfully requests that the Commission: (1) issue an order on or before January 29, 2021 accepting the NYISO’s proposal without modification; and (2) establish an effective date of January 30, 2021 for the tariff revisions proposed in this proceeding.

Respectfully submitted,

/s/ Garrett E. Bissell

Garrett E. Bissell
Senior Attorney

New York Independent System Operator, Inc.

Dated: January 5, 2021

cc:Jignasa GadaniLarry Parkinson

Jette GebhartDouglas Roe

Leanne KhammalFrank Swigonski

Kurt LongoEric Vandenberg

John C. MillerGary Will

David Morenoff