10 Krey Boulevard, Rensselaer, NY 12144
Ph: 518.356.6000 | Fax: 518.356.8899
November 30, 2020
By Electronic Delivery
Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426
Re: New York Independent System Operator, Inc., Docket No. ER21-____-
000; 2021-2025 ICAP Demand Curve Reset Proposal
Dear Secretary Bose:
In accordance with Section 205 of the Federal Power Act1 and Part 35 of the regulations of the Federal Energy Regulatory Commission (“Commission”) and Section 5.14.1.2.2 of the New York Independent System Operator, Inc. (“NYISO”) Market Administration and Control Area Services Tariff (“Services Tariff”), the NYISO submits the proposed Installed Capacity (“ICAP”) Demand Curves for the 2021/2022 Capability Year.2 The NYISO also proposes the methodologies and inputs for use in conducting annual updates to determine the ICAP Demand Curves for the 2022/2023, 2023/2024, and 2024/2025 Capability Years.
The ICAP Demand Curves, as well the annual update methodologies and inputs proposed herein are the results of the extensive periodic review process required by Section 5.14.1.2.2 of the Services Tariff. This quadrennial review process is commonly referred to as the “ICAP
Demand Curve reset” or “DCR.” Given the period covered by this periodic review, the NYISO refers to this as the “2021-2025 DCR.”3
The NYISO respectfully requests: (i) an order accepting the proposed 2021/2022
Capability Year ICAP Demand Curves, as well as the annual update methodologies and inputs to determine the ICAP Demand Curves for the 2022/2023, 2023/2024, and 2024/2025 Capability Years on or before January 29, 2021 (i.e., sixty days after filing); and (ii) an effective date of
January 30, 2021 (i.e., the day following the end of the statutory 60-day notice period) for the
tariff revisions proposed herein.
1 16 U.S.C. § 824d.
2 Capitalized terms not otherwise defined herein shall have the meaning specified in the Services
Tariff.
3 References to “reset period” herein means the period of Capability Years for which ICAP Demand Curves resulting from the methodologies and inputs established during each DCR remain in effect. For example, the reset period covered by this DCR encompasses the 2021/2022 through
2024/2025 Capability Years.
Website: www.nyiso.com | LinkedIn: NYISO | Twitter: @NewYorkISO
Honorable Kimberly D. Bose November 30, 2020
Page 2
I.Documents Submitted
The NYISO respectfully submits the following documents with this filing letter:4
1.A clean version of the proposed revisions to the Services Tariff (“Attachment I”);
2.A blacklined version of the proposed revisions to the Services Tariff
(“Attachment II”);
3. An Affidavit from Paul J. Hibbard, Dr. Todd Schatzki, Charles Wu, and
Christopher Llop of Analysis Group, Inc., including the report titled Independent Consultant Study to Establish New York ICAP Demand Curve Parameters for the 2021/2022 through 2024/2025 Capability Years - Final Report dated September 9, 2020 (“Attachment III”);
4. An Affidavit from Matthew E. Lind and Kieran McInerney of Burns &
McDonnell Engineering Company, Inc. (“Attachment IV”);
5. An Affidavit from Zachary T. Smith of the NYISO, including the report titled
Proposed NYISO Installed Capacity Demand Curves for the 2021-2022
Capability Year and Annual Update Methodology and Inputs for the 2022-2023, 2023-2024, 2024-2025 Capability Years - Final Report dated September 2020 (“Attachment V”); and
6.An Affidavit from Dr. Pallas LeeVanSchaick of Potomac Economics Ltd.
(“Attachment VI”).
II.Background
Every four years, the NYISO and its stakeholders undertake a comprehensive review to determine the necessary inputs and assumptions for developing the ICAP Demand Curves for the four-year period covered by the reset.
The NYISO develops ICAP Demand Curves based on the estimated cost to construct and
operate a hypothetical new capacity supply resource in various locations throughout New York.5
4 As permitted by the Commission’s August 20, 2020 order extending the previous emergency waiver of notarization rules, the affidavits submitted with this filing have not been notarized. See Temporary Action to Facilitate Social Distancing, 172 FERC ¶ 61,151 (2020).
5 Services Tariff § 5.14.1.2.2 refers to the hypothetical new capacity supply resource as a
“peaking plant.” The Services Tariff defines a “peaking unit” to mean “the unit with technology that
results in the lowest fixed costs and highest variable costs among all other units’ technology that are
economically viable.” The Services Tariff defines a “peaking plant” to mean “the number of units
(whether one or more) that constitute the scale identified in the [DCR].” The Services Tariff refers to the levelized cost to construct a peaking plant in a given location as the “peaking plant gross cost.”
Honorable Kimberly D. Bose November 30, 2020
Page 3
This cost is offset by an estimate of the potential revenues the hypothetical resource could earn
from participating in the NYISO-administered energy and ancillary services markets.6 The
resulting net value determines the revenue the hypothetical resource would need to receive from
the capacity market to obtain sufficient revenues to support market entry under the system
conditions specified for use in the DCR. Specifically, for the purposes of the DCR and
establishment of the ICAP Demand Curves, the costs and estimated revenues of each peaking
plant are not determined based on current market conditions. Instead, the Services Tariff
requires that such costs and revenues be estimated under market conditions in which the
available capacity is equal to the applicable minimum Installed Capacity requirement plus the
MW value of the peaking plant (referred to herein as the “tariff-prescribed level of excess
conditions”).7 This requirement is designed to ensure that the ICAP Demand Curves are
established at a level that should provide sufficient revenues to cover the costs of a peaking plant
when market entry by such facility is required to maintain reliability.
In February and March 2019, the NYISO collaborated with stakeholders on the
development of a request for proposals to select an independent consultant to assist with
conducting the DCR and development of the appropriate methodologies and inputs to establish the ICAP Demand Curves for the 2021-2025 reset period.8 The NYISO issued the request for proposals in April 2019. After review of the proposals submitted, the NYISO ultimately selected Analysis Group, Inc. (“AG”) to serve as the independent consultant for the 2021-2025 DCR.9
Consistent with past DCRs, AG subcontracted with an engineering consultant to assist in the
development of certain aspects of the scope of work. For the 2021-2025 DCR, AG
subcontracted with Burns & McDonnell Engineering Company, Inc. (“BMCD”). BMCD
primarily assisted AG with the assessment of potential technologies to serve as the hypothetical peaking plant used in the establishment of each ICAP Demand Curve, as well as the costs to
construct, own and operate such peaking plant options. AG, together with BMCD, are
hereinafter referred to collectively as the “Independent Consultant.”
The Independent Consultant commenced discussions with stakeholders in August 2019
and continued discussions with stakeholders at the Installed Capacity Working Group
(“ICAPWG”) over the course of the next 12 months to inform its final report and
recommendations for the 2021-2025 DCR. Stakeholders provided input on the Independent
Consultant’s assumptions, methodologies, analysis, and preliminary results. The Independent
Consultant also received input from the Market Monitoring Unit (“MMU”) throughout the DCR.
6 The Services Tariff refers to the estimate of potential energy market revenue earnings for a
peaking plant as the “net Energy and Ancillary Services revenue offset.” See Services Tariff § 5.14.1.2.2.
7 Services Tariff § 5.14.1.2.2. For purposes of the 2021-2025 DCR, the specified system
conditions are determined based on the NYCA Minimum Installed Capacity Requirement and the
applicable Locational Minimum Installed Capacity Requirements established for the 2020/2021
Capability Year.
8 Services Tariff § 5.14.1.2.2.4.1.
9 Services Tariff § 5.14.1.2.2.4.2.
Honorable Kimberly D. Bose November 30, 2020
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Based on its analysis and consideration of the feedback received from stakeholders and
the MMU, the Independent Consultant issued its draft report for the 2021-2025 DCR on June 5,
2020.10 The Independent Consultant reviewed its draft report at the June 10, 2020 ICAPWG
meeting. Stakeholders and the MMU submitted written comments in response to the draft
report.11
After consideration of the feedback received, the Independent Consultant issued an
interim version of its final report for the 2021-2025 DCR on August 5, 2020. This interim
version reflected the Independent Consultant’s final recommendations on inputs, assumptions, and methodologies for the 2021-2025 DCR and updated the preliminary results contained in its draft report accordingly.12 The Independent Consultant issued the updated version of its final report on September 9, 2020.13 The updated version reflected the Independent Consultant’s recommended ICAP Demand Curves for the 2021/2022 Capability Year using the tariff-
prescribed three-year historical data period applicable for such ICAP Demand Curves (i.e.,
September 1, 2017 through August 31, 2020).14
Based on consideration of stakeholder and MMU feedback throughout the DCR, the
Independent Consultant’s draft report, and comments submitted in response to the Independent
10 Services Tariff § 5.14.1.2.2.4.3. The Independent Consultant’s draft report provided results
and recommendations, including preliminary values for the 2021/2022 ICAP Demand Curves using the
historical data period from September 1, 2016 through August 31, 2019. The Independent Consultant
noted that: (1) all preliminary results and recommendations remained subject to change; and (2) the
calculated values for the 2021/2022 Capability Year ICAP Demand Curves would be updated in the
Independent Consultant’s final report to reflect the historical data period prescribed by the tariff for use in
establishing such curves (i.e., September 1, 2017 through August 31, 2020). The Independent
Consultant’s draft report is available at: https://www.nyiso.com/documents/20142/13248786/Analysis-
Group-2019-2020-DCR-Draft-Report.pdf.
11 Services Tariff §§ 5.14.1.2.2.4.4 and 5.14.2.2.2.4.5. Comments submitted in response to the
Independent Consultant’s draft report are available at: https://www.nyiso.com/installed-capacity-market.
From this page, the comments can be obtained by navigating through the following content sections:
“Reference Documents”“2021-2025 Demand Curve Reset”“Stakeholder Comments”“Consultant’s
Draft Report.”
12 The historical data period utilized in calculating preliminary values for the 2021/2022
Capability Year ICAP Demand Curves continued to reflect the period from September 1, 2016 through August 31, 2019. The Independent Consultant noted that an updated version of its final report would be issued using the required three-year historical period (i.e., September 1, 2017 through August 31, 2020) to calculate the Independent Consultant’s recommended ICAP Demand Curves for the 2021/2022 Capability Year. The Independent Consultant’s interim final report is available at:
https://www.nyiso.com/documents/20142/14404876/Analysis%20Group%20Interim%20Final%20Dema
nd%20Curve%20Reset%20Report.pdf.
13 Services Tariff § 5.14.1.2.2.4.6.
14 The updated version of the Independent Consultant’s final report is included as Exhibit E of the Affidavit of Paul J. Hibbard, Dr. Todd Schatzki, Charles Wu, and Christopher Llop attached hereto as Attachment III (“AG Affidavit”).
Honorable Kimberly D. Bose November 30, 2020
Page 5
Consultant’s draft report, NYISO staff issued its draft recommendations for the 2021-2025 DCR on August 5, 2020.15 NYISO staff reviewed its draft recommendations at the August 10, 2020 ICAPWG meeting. Stakeholders and the MMU submitted written comments in response to NYISO staff’s draft recommendations.16
After consideration of the feedback provided, NYISO staff issued its final
recommendations on September 9, 2020.17 At the September 22, 2020 ICAPWG meeting, the
NYISO reviewed its final recommendations and highlighted aspects that differed from the
Independent Consultant’s final report and NYISO staff’s draft recommendations. These changes
included: (1) in coordination with the Independent Consultant, modifying certain logic related to
the use of gas price data contained in the model that calculates the net Energy and Ancillary
Services revenue offset values for the peaking plants; (2) the proposed gas hub for the peaking
plant located in Load Zone C; and (3) enhancements to the translation of the annual peaking
plant gross cost values to monthly values used in establishing the maximum clearing price value
for each ICAP Demand Curve.18
Following issuance of NYISO staff’s final recommendations, stakeholders submitted
written comments to the NYISO Board of Directors (“Board”) regarding the recommendations
for the 2021-2025 DCR.19 Stakeholders also participated in oral presentations before the Board
15 Services Tariff § 5.14.1.2.2.4.7. Consistent with the Independent Consultant’s draft report,
NYISO staff’s draft recommendations included preliminary results and recommendations, including
preliminary values for the 2021/2022 Capability Year ICAP Demand Curves using historical data for the period from September 1, 2016 through August 31, 2019. NYISO staff noted that the recommendations and results set forth in its draft recommendations were preliminary and subject to change. NYISO staff also noted that updated values for the 2021/2022 Capability Year ICAP Demand Curves using data for the period from September 1, 2017 through August 31, 2020 would be included in its final
recommendations. NYISO staff’s draft recommendations are available at:
https://www.nyiso.com/documents/20142/13248786/NYISO-Staff-Draft-DCR-Recommendations-
Final.pdf.
16 Services Tariff §§ 5.14.1.2.2.4.7 and 5.14.1.2.2.4.5. Comments submitted in response to
NYISO staff’s draft recommendations are available at: https://www.nyiso.com/installed-capacity-market.
From this page, the comments can be obtained by navigating through the following content sections:
“Reference Documents”“2021-2025 Demand Curve Reset”“Stakeholder Comments”“NYISO
Staff’s Draft Report.”
17 Services Tariff § 5.14.1.2.2.4.8. NYISO staff’s final recommendations are included as Exhibit A of the Affidavit of Zachary T. Smith attached hereto as Attachment V (“NYISO Affidavit”).
18 NYISO, 2021-2025 ICAP Demand Curve Reset: NYISO Staff Final Recommendations (presented at the September 22, 2020 ICAPWG meeting), available at:
https://www.nyiso.com/documents/20142/15473217/2019-
2020%20NYISO%20Staff%20Final%20Recommendations.pdf.
19 Services Tariff § 5.14.1.2.2.4.9. Stakeholders comments submitted to the Board are available
at: https://www.nyiso.com/installed-capacity-market. From this page, the comments can be obtained by
navigating through the following content sections: “Reference Documents”“2021-2025 Demand Curve Reset”“Stakeholder Comments”“Comments to the NYISO BOD.”
Honorable Kimberly D. Bose November 30, 2020
Page 6
on October 19, 2020.20 After due consideration of: (1) stakeholder comments throughout the
DCR, including those provided in writing and orally in response to NYISO staff’s final
recommendations; (2) comments provided by the MMU throughout the DCR; (3) the
Independent Consultant’s final report; and (4) NYISO staff’s final recommendations, the Board directed NYISO staff to file the results for the 2021-2025 DCR as proposed herein. The Boardapproved proposal reflects the proposed 2021/2022 Capability Year ICAP Demand Curves, as well as the methodologies and inputs to be used in the annual updates to determine the ICAP
Demand Curves for the 2022/2023 through 2024/2025 Capability Years, that are set forth in
NYISO staff’s final recommendations.21
As further described herein, the NYISO proposes to use the H class frame turbine as the
peaking plant in establishing each of the ICAP Demand Curves. The H class frame turbine
replaces the F class frame turbine that the Commission approved for the last reset covering the
2017/2018 through 2020/2021 Capability Years (“2017-2021 DCR”).22 For the New York
Control Area (“NYCA”) ICAP Demand Curve, the NYISO proposes continued use of a gas-only
peaking plant without selective catalytic reduction (“SCR”) emissions control technology. The
NYISO proposes that the ICAP Demand Curves for the G-J Locality, New York City (“NYC”),
and Long Island (“LI”) continue to utilize dual fuel peaking plants that include SCR emissions
control technology. Based on updates to methodologies, inputs, and assumptions developed
during this DCR and proposed herein, the assumed locations of the peaking plants for the NYCA
and G-J Locality ICAP Demand Curves are different than those used for the 2017-2021 DCR.23
The NYISO proposes use of a peaking plant located within Load Zone C as the basis for the
NYCA ICAP Demand Curve instead of Load Zone F as was used for the 2017-2021 DCR. The
proposed ICAP Demand Curve for the G-J Locality utilizes a peaking plant located within the
Rockland County portion of Load Zone G (“Load Zone G (Rockland County)”). The G-J
Locality ICAP Demand Curve for the 2017-2021 DCR used a peaking plant located within the
Dutchess County portion of Load Zone G (“Load Zone G (Dutchess County)”).
20 Services Tariff § 5.14.1.2.2.4.10.
21 NYISO Affidavit at Exhibit A (“NYISO Final Recommendations”); and NYISO Affidavit at ¶
29.
22 New York Independent System Operator, Inc., 158 FERC ¶ 61,028 (2017) (“2017-2021 DCR
Order”). The Commission also approved use of the F class frame turbine for the reset prior to the 2017-
2021 DCR that covered the ICAP Demand Curves for the 2014/2015 through 2016/2017 Capability Years (“2014-2017 DCR”). See New York Independent System Operator, Inc., 146 FERC 61,043 (2014)
(“2014-2017 DCR Order”).
23 For the NYCA and G-J Locality ICAP Demand Curves, the DCR assessed more than one
generic site location for a potential peaking plant. In these cases, the NYISO proposes selection of the location that results in the lowest reference point price for each ICAP Demand Curve. Thus, the peaking plant locations proposed herein are dependent on the various inputs and assumptions proposed by the NYISO for each location. If the inputs and assumptions for any of these locations were changed, the
proposed location for the peaking plant used in determining the NYCA and/or G-J Locality ICAP
Demand Curve may also need to be revised.
Honorable Kimberly D. Bose November 30, 2020
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The DCR serves as a forum for thoroughly vetting proposed methodologies, inputs and
assumptions used in establishing the ICAP Demand Curves. The collaborative nature of this
open and transparent process helps to reduce the scope of disputed issues. Although the DCR
ultimately refined and helped to minimize the number of disputed issues, consensus among
divergent stakeholder interests was not achieved on all aspects of the 2021-2025 DCR. The
NYISO anticipates that the following disputed matters are likely to be raised in this proceeding:
(1) the inclusion of SCR emissions control technology for the Load Zone G (Dutchess County)
peaking plant option; (2) the inclusion of dual fuel capability for the peaking plant used in
establishing the G-J Locality ICAP Demand Curve; (3) the estimated cost of a gas lateral
connection, especially as it relates to the peaking plant used in establishing the G-J Locality
ICAP Demand Curve; (4) the estimated land lease cost for the peaking plant in NYC; (5) the
assumed level of owner’s costs for design, permitting, and financing during construction; (6) the
gas hub(s) used in determining the variable operating costs for the Load Zone C peaking plant
option; (7) the gas hub used in determining the variable operating costs for the Load Zone G
(Rockland County) peaking plant option; (8) the supply resource modeling assumptions used in
determining level of excess adjustment factors; (9) the assumed cost of debt, return on equity,
and amortization period used in translating the up-front capital costs of developing and owning
each peaking plant into an annual levelized value; and (10) the absence of any one-time
adjustment to historical data to exclude energy market outcomes impacted by the COVID-19
pandemic. The NYISO addresses each of these issues within this filing.
III.Peaking Plant Technology and Design
Section 5.14.1.2.2 of the Services Tariff defines the peaking unit as the “technology that results in the lowest fixed costs and highest variable costs among all other units’ technology that are economically viable.” The Commission has established that economic viability
determinations are a matter of judgment that is informed by the consideration of multiple
factors.24 These factors include: (i) the availability of the technology to most market
participants; (ii) existence of sufficient operating experience to demonstrate that the technology is proven and reliable; (iii) whether the technology is dispatchable and capable of being cycled to provide peaking service; and (iv) the ability to achieve compliance with applicable
environmental requirements and regulations.25
The Commission has also recognized that the peaking plant design for each ICAP
Demand Curve must be capable of being replicated.26 As such, the peaking plant design should
24 See, e.g., 2017-2021 DCR Order at P 18; 2014-2017 DCR Order at P 60; New York
Independent System Operator, Inc., 134 FERC ¶ 61,058 at P 37 (2011) (“2011-2014 DCR Order”); and New York Independent System Operator, Inc., 125 FERC ¶ 61,299 at P 20 (2008) (“2008-2011 DCR Rehearing Order”).
25 Id. The Independent Consultant applied these criteria in this DCR to guide determinations
regarding the appropriate technology and plant design to use in establishing each ICAP Demand Curve.
See, e.g., AG Affidavit, Exhibit E at 13 (“Independent Consultant Final Report”); and Affidavit of
Matthew E. Lind and Kieran McInerney at ¶ 11 attached hereto as Attachment IV (“BMCD Affidavit”).
26 2017-2021 DCR Order at P 19 and 65.
Honorable Kimberly D. Bose November 30, 2020
Page 8
not represent a single least possible cost design that may support only the construction of a single facility. Establishing the ICAP Demand Curves purely on the basis of a single least possible cost design is likely to result in providing price signals that could sustain only the development of, at best, a single facility. If, however, system conditions dictated a need to develop more than one peaking plant during a given reset period, such a market design would likely fail its objective of supporting new entry when needed and could require reliance on out-of-market action to ensure continued availability of sufficient resources to maintain reliability.
The NYISO carefully evaluated the above-described considerations, as well as the views of all stakeholders, in determining the peaking plant designs proposed herein. The NYISO’s
proposal is intended to produce ICAP Demand Curves that provide appropriate price signals
regarding the value of capacity in each capacity region, while simultaneously ensuring that the curves are capable of providing the needed revenues to elicit new market entry when required to ensure that reliability is maintained.
Although the NYISO has proposed to modify the class of frame turbine technology used
in establishing each ICAP Demand Curve, the general plant designs for each location remain
consistent with the designs approved by the Commission for the 2017-2021 DCR.27 The peaking
plant proposed for establishing the NYCA ICAP Demand Curves remains a gas-only unit
without SCR emissions control technology.28 For the G-J Locality, NYC, and LI ICAP Demand
Curves, the NYISO proposes continued use of a dual fuel peaking plant with SCR emissions
control technology.29
A. Peaking Plant Technology
Consistent with prior DCRs, the Independent Consultant developed information for a
variety of potential peaking plant technology options.30 The Independent Consultant produced
results for the various technology options in Load Zone C, Load Zone F, Load Zone G (Dutchess
27 2017-2021 DCR Order at P 2 and 20.
28 NYISO Final Recommendations at 58-59.
29 Id.
30 Independent Consultant Final Report at 12-19; AG Affidavit at ¶ 19-23; and BMCD Affidavit at ¶ 10-13.
Honorable Kimberly D. Bose November 30, 2020
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County), Load Zone G (Rockland County), NYC, and LI. The technology options evaluated
included the H class frame turbine,31 the F class frame turbine,32 and aeroderivative turbines.33
For this DCR, the Independent Consultant also expanded the technologies evaluated to
include consideration of battery storage technology for the first time.34 Consideration of battery
storage, in part, recognizes the ongoing transition of the resource mix in New York and state
policies to accelerate the transition to a clean energy resource fleet. Rather than select a
particular manufacturer or chemistry, the Independent Consultant developed cost estimates for
battery storage that are representative of the three most commonly utilized lithium-ion chemistry
options (i.e., lithium nickel manganese cobalt oxide [“NMC”], lithium iron phosphate [“LFP”],
and lithium nickel cobalt aluminum oxide [“NCA”]). The Independent Consultant assessed 200
MW battery storage plants with discharge durations of 4 hours (800 MWh of energy storage
capability), 6 hours (1,200 MWh of energy storage capability), and 8 hours (1,600 MWh of
energy storage capability). Due to the availability of alternative lower cost, economically viable
technology options, the NYISO does not recommend any battery storage option as the peaking
plant for any location in this DCR.35
For the 2021-2025 DCR, the NYISO proposes to replace the F class frame turbine used in establishing the ICAP Demand Curves for the 2014-2017 DCR and 2017-2021 DCR with the H class frame turbine.36 The H class frame turbine is a larger, more efficient, and more flexible
technology than the F class frame turbine. The NYISO proposes use of the H class frame turbine for the 2021-2025 DCR because it represents the lowest cost technology option amongst the
economically viable options evaluated.
The NYISO considered the H class frame turbine for informational purposes only in the
2017-2021 DCR because, at that time, the H class frame turbine had no actual commercial
31 The Independent Consultant selected the GE 7HA.02 unit to serve as the representative H class frame turbine technology. The evaluated peaking plant option consisted of a single H class frame turbine in a simple cycle configuration.
32 The Independent Consultant utilized the GE 7F.05 as the representative F class frame turbine technology. The peaking plant option assessed consisted of a single F class frame turbine in a simple cycle configuration.
33 The Siemens SGT-A65 unit served as the representative aeroderivative turbine technology. The peaking plant option evaluated consisted of three aeroderivative units operating in a simple cycle configuration.
34 Independent Consultant Final Report at 18-19; AG Affidavit at ¶ 30; and BMCD Affidavit at ¶
13.
35 NYISO Final Recommendations at 59; Independent Consultant Final Report at 7; and AG Affidavit at ¶ 25 and 31.
36 NYISO Final Recommendations at 4 and 58-59; Independent Consultant Final Report at 7; and AG Affidavit at ¶ 25.
Honorable Kimberly D. Bose November 30, 2020
Page 10
operating experience in a simple cycle configuration.37 Since the last DCR, the H class frame
turbine has achieved commercial operation and operated successfully in a simple cycle
configuration equipped with SCR emissions control technology.38 For example, the Canal 3
generation facility in Massachusetts, which consists of a single GE 7HA.02 unit operating in a
simple cycle configuration and equipped with SCR emissions control technology, commenced
commercial operation in June 2019.39 Consistent with precedent, the successful operation of this facility provides the necessary actual operating experience to support selection of this technology as a peaking plant in New York.40
Unless otherwise noted, the remainder of this filing letter addresses matters based on
consideration of the H class frame turbine as the peaking plant for each of the ICAP Demand
Curves.
B. Environmental Requirements and SCR Emissions Control Technology
The NYISO proposes peaking plant designs consistent with those approved by the
Commission for the 2017-2021 DCR.41 For the 2021-2025 DCR, the NYISO proposes
continued use of a gas-only peaking plant without SCR emissions control technology as the basis for the NYCA ICAP Demand Curve.42 Instead of installing back-end emissions controls, the
NYISO proposes that the gas-only peaking plant for the NYCA ICAP Demand Curve operate
pursuant to an enforceable permit restriction to limit annual nitrogen oxides (“NOx”) emissions below applicable environmental requirements.43 For the G-J Locality, NYC, and LI ICAP
Demand Curves, the NYISO proposes continued use of dual fuel peaking plant designs equipped with SCR emissions control technology.44
37 See, e.g., 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 7-9 (November 18, 2016) (“2017-2021 DCR Filing”); and 2017-2021 DCR Order at P 28.
38 NYISO Final Recommendations at 59; Independent Consultant Final Report at 17-18; and BMCD Affidavit at ¶ 13.
39 See, e.g., NYISO Final Recommendations at 59; BMCD Affidavit at ¶ 13; and BMCD, Burns & McDonnell Reaches Substantial Completion for Canal 3, available at:
https://www.burnsmcd.com/insightsnews/in-the-news/2019/09/substantial-completion-for-canal-3.
40 See, e.g., 2017-2021 DCR Order at P 28; 2011-2014 DCR Order at P 57-60; and New York
Independent System Operator, Inc., 122 FERC ¶ 61,064 at P 23 (2008) (“2008-2011 DCR Order”).
41 2017-2021 DCR Order at P 2, 27, 58-59 and 91.
42 NYISO Final Recommendations at 58-59; and AG Affidavit at ¶ 25.
43 NYISO Final Recommendations at 14-15; and AG Affidavit at ¶ 40.
44 NYISO Final Recommendations at 58-59.
Honorable Kimberly D. Bose November 30, 2020
Page 11
1. Overview of Environmental Requirements
The Independent Consultant evaluated the impacts of applicable environmental
requirements on the peaking plant design for each location assessed as part of the DCR.45 This
evaluation included consideration of applicable New Source Performance Standards (“NSPS”),
as well the requirements imposed by permitting under the New Source Review (“NSR”)
program. NSPS establishes emissions requirements that apply to the H class frame turbine in all
locations. The NSR program establishes additional requirements that vary by location.
NSPS includes both greenhouse gas and NOx emissions standards that affect the H class
frame turbine. The carbon dioxide (“CO2”) emissions limits imposed by NSPS effectively
results in establishing a maximum allowable operating limit of 3,066 hours annually to comply
with the applicable requirements.46 The NSPS also establishes NOx emissions standards that
require the H class frame turbine to limit its NOx emissions rate to less than 15 parts per million
by volume (“ppmv”) at 15% oxygen (“O2”) when operating on natural gas.47 The standard
model GE 7HA.02 turbine has a NOx emissions rate of 25 ppmv at 15% O2. As a result, the
standard model unit would require the installation of SCR emissions control technology to
comply with the NSPS NOx emissions standards.48 However, GE also offers an alternative
7HA.02 model that has a NOx emissions rate of 15 ppmv at 15% O2.49 This alternative model
achieves lower NOx emissions by lowering the combustion temperature. This lowered
temperature does impact the turbine’s efficiency resulting in a reduction in output capability of
approximately 5% compared to the standard model.50 Although slightly less efficient, the
alternative model does present an option that can be considered for potential operation without
the need to install SCR emissions control technology for compliance with NSPS.
The NSR program subjects new units to an evaluation of their impact on air quality in
consideration of the surrounding area in which the new unit is located.51 Based on a comparison
of a criteria pollutant’s concentration in a given area to the applicable National Ambient Air
Quality Standard (“NAAQS”) for such pollutant, an area is designated as either in “attainment”
(i.e., pollutant concentration levels below the applicable NAAQS) or “non-attainment” (i.e.,
pollutant concentration levels in excess of the applicable NAAQS).52 Further designation is used
for non-attainment areas to signify the degree of exceedance (e.g., designation as either
“moderate” or “severe” non-attainment). Attainment status for an area affects the
45 Independent Consultant Final Report at 21-34; BMCD Affidavit at ¶ 22-35; and AG Affidavit at ¶ 36-39.
46 Independent Consultant Final Report at 21-22; and BMCD Affidavit at ¶ 34.
47 Independent Consultant Final Report at 21; and BMCD Affidavit at ¶ 23.
48 Independent Consultant Final Report at 21; and BMCD Affidavit at ¶ 24-25.
49 Id.
50 Id.
51 Independent Consultant Final Report at 22-30; and BMCD Affidavit at ¶ 26.
52 Independent Consultant Final Report at 22-23; and BMCD Affidavit at ¶ 26.
Honorable Kimberly D. Bose November 30, 2020
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preconstruction review process that applies to a new unit. New units constructed in nonattainment areas are subject to significantly more stringent requirements.
New units constructed in attainment areas are subject to permitting under the Prevention
of Significant Deterioration (“PSD”) program.53 The PSD programs applies Best Available
Control Technology (“BACT”) analysis to assess the requirement to include pollutant control
technologies. BACT generally assesses pollutant control technologies installed on similar
facilities. BACT also permits the consideration of economic feasibility in assessing the need to
install a particular control technology. Based on its experience, the Independent Consultant
concluded that a new unit in New York subject to a BACT review for NOx emissions would be
required to install SCR emissions control technology to reduce NOx emissions.54
Alternatively, a new unit could elect to “synthetically limit” its operating profile to
maintain compliance with the applicable emissions limit for a particular pollutant.55 To pursue
this alternative, the new unit must accept a cap on allowable emissions below the applicable
threshold for such pollutant. New units subject to such an emissions cap are deemed a “synthetic
minor source” and are subject to less restrictive analysis. For example, a BACT analysis for
potential control technology is not required for a synthetic minor source. The Commission has
previously approved use of the synthetic minor approach for gas-only units located in an
attainment area to avoid the need to install SCR emissions control technology for reducing NOx
emissions.56
New units constructed in non-attainment areas are subject to permitting under the
Nonattainment New Source Review (“NNSR”) program.57 The NNSR program uses a Lowest
Achievable Emissions Rate (“LAER”) in assessing the need for back-end controls to reduce
emissions of a particular pollutant. Unlike BACT, LAER does not include consideration of cost
in determining the need for control technology. As a result, LAER typically results in more
stringent requirements than BACT.58 Given the Independent Consultant’s determination that the
less stringent BACT analysis would ultimately require installation of SCR emissions control
technology in New York, the more stringent LAER assessment for NOx emissions would
likewise require installation of SCR emissions control technology to reduce NOx emissions.59
53 Independent Consultant Final Report at 23-25; and BMCD Affidavit at ¶ 27.
54 Independent Consultant Final at 24; and BMCD Affidavit at ¶ 29.
55 Independent Consultant Final Report at 23 and 29-30; and BMCD Affidavit at ¶ 28.
56 See, e.g., 2017-2021 DCR Order at P 60-67; and 2014-2017 DCR Order at P 74-77.
57 Independent Consultant Final Report at 23 and 26-27; and BMCD Affidavit at ¶ 26.
58 Independent Consultant Final Report at 23; and BMCD Affidavit at ¶ 27.
59 BMCD Affidavit at ¶ 34.
Honorable Kimberly D. Bose November 30, 2020
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2. SCR Emissions Control Technology Analysis
Load Zone G (Rockland County), New York City, and Long Island are designated as
severe non-attainment areas. The applicable NOx emissions limit for these locations is 25
tons/year.60 The Independent Consultant concluded that for these severe non-attainment areas,
the NNSR will require the installation of SCR emissions control technology to comply with
NSR.61 For areas where SCR emissions control technology is included, the more efficient,
standard model of the GE 7HA.02 is used. Inclusion of SCR emissions control technology
allows this more efficient version to comply with the applicable NOx emissions limits under both
NSPS and NSR.62
Load Zones G (Dutchess County), C, and F are attainment areas. However, because New
York State is within the Ozone Transport Region, these locations are subject to a more stringent
requirement than would otherwise apply.63 For these locations, the applicable NOx emissions
limit is 100 tons/year.64 Absent pursuing a synthetic minor approach, if viable, new units in
these locations would also require the installation of SCR emissions control technology.65
The inclusion of dual fuel capability significantly affects the viability of the synthetic
minor approach. Operation on ultra-low sulfur diesel (“ULSD”) produces significantly higher
NOx emissions than operation on natural gas.66 In fact, the NOx emissions produced by the H
class frame turbine is nearly three times higher when operating on ULSD.67 This severely limits
the number of hours the unit can operate annually under the emissions cap applicable to the
synthetic minor approach.68 Due to the severely constraining nature of the emissions cap for
operation on ULSD, the NYISO has never proposed in any past DCR that a dual fuel plant
pursue the synthetic minor approach in lieu of installing SCR emissions control technology.69
The NYISO’s prior reliance on the synthetic minor approach has been limited to gas-only plants
used for establishing the NYCA ICAP Demand Curve.70 Since its inception, the NYISO has
60 Independent Consultant Final Report at 25-26; NYISO Final Recommendations at 12-13; and BMCD at ¶ 32.
61 Independent Consultant Final Report at 26-27; and BMCD Affidavit at ¶ 34.
62 Independent Consultant Final Report at 26-27.
63 BMCD Affidavit at ¶ 27.
64 Independent Consultant Final Report at 24-26; NYISO Final Recommendations at 13; and BMCD Affidavit at ¶ 27 and 31.
65 Independent Consultant Final Report at 24 and 27.
66 Independent Consultant Final Report at 31; and AG Affidavit at ¶ 41.
67 Independent Consultant Final Report at 31; and NYISO Final Recommendations at 14-15.
68 Independent Consultant Final Report at 28; BMCD Affidavit at ¶ 35; AG Affidavit at ¶ 41; and NYISO Final Recommendations at 14-15.
69 NYISO Final Recommendations at 14; and AG Affidavit at ¶ 41.
70 NYISO Final Recommendations at 14.
Honorable Kimberly D. Bose November 30, 2020
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established the G-J Locality ICAP Demand Curve using a dual fuel peaking plant design equipped with SCR emissions control technology.71
For the NYCA ICAP Demand Curve, the NYISO proposes continued use of a gas-only
peaking plant design subject to an emissions cap in lieu of installing SCR emissions control
technology.72 This represents a reasonable and viable option in consideration of the level of
annual operation allowed under such emissions cap. For a gas-only H class frame unit, the 100 tons/year NOx limit applicable to a synthetic minor source in Load Zones C or F translates into the ability to operate for approximately 1,060 hours per year.73 This value is similar to the
allowed hours of operation deemed acceptable in prior DCRs.74 For locations where the NYISO proposes use of a synthetic minor approach, the alternative GE 7HA.02 model is used. As noted above, this alternative model is tuned to emit 15 ppmv of NOx at 15% O2, thereby achieving
compliance with the applicable NSPS emissions requirements for the H class frame turbine.75
Use of this alternative model does slightly reduce the efficiency and output capability of the
turbine compared to the standard GE 7HA.02 model.
The NYISO’s proposed inputs and assumptions result in a peaking plant located in Load Zone G (Rockland County) serving as the basis for G-J Locality ICAP Demand Curve.76
Rockland County is located within a severe non-attainment area. Therefore, as noted above, the Independent Consultant concluded that the LAER analysis would require the peaking plant
design to include SCR emissions control technology to reduce NOx emissions.77
Although the NYISO’s proposed G-J Locality ICAP Demand Curve uses a peaking plant
in the Rockland County location, certain stakeholders oppose the NYISO’s proposal to include
71 See, e.g., 2014-2017 DCR Order at P 57; and 2017-2021 DCR Order at P 58-59.
72 NYISO Final Recommendations at 14-15; Independent Consultant Final Report at 29-30; and AG Affidavit at ¶ 25 and 40.
73 Independent Consultant Final Report at 28; BMCD Affidavit at ¶ 35; AG Affidavit at ¶ 40; and NYISO Final Recommendations at 15.
74 For example, for the 2014-2017 DCR, the gas only peaking plant design used in establishing the NYCA ICAP Demand curve was subject to an emission cap that allowed nearly 1,000 hours of operation annually. See, e.g., 2014-2017 DCR Order at P 73, n. 55.
75 Independent Consultant Final Report at 21 and 27-28.
76 For the G-J Locality ICAP Demand Curve, the DCR assessed two potential locations for the peaking plant - Load Zone G (Dutchess County) and Load Zone G (Rockland County). The NYISO
proposes selection of the location that results in the lowest reference point price for each ICAP Demand Curve. Based on the NYISO’s proposed inputs and assumptions, the Dutchess County location results in a higher reference point price than the Rockland County location. See NYISO Final Recommendations at 59; Independent Consultant Final Report at 8; and AG Affidavit at ¶ 25.
77 Independent Consultant Final Report at 27.
Honorable Kimberly D. Bose November 30, 2020
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SCR emission control technology for the peaking plant in the Dutchess County location.78 If
SCR emissions control technology were not included in the peaking plant design for the
Dutchess County location, the resulting reference point price for this location would be lower than the Rockland County location.79 As a result, these stakeholders contend that the NYISO should remove the SCR emissions control technology from the peaking plant design for Load Zone G (Dutchess County) and use this location as the basis for the G-J Locality ICAP Demand Curve for the 2021-2025 reset period.
Dutchess County is designated as an attainment area that is within the Ozone Transport
Region.80 Therefore, similar to Load Zones C and F, the synthetic minor approach may be
available to achieve compliance with the NOx emissions limit under the PSD program (i.e., 100
tons/year).81 However, unlike Load Zones C and F, the proposed peaking plant design for Load
Zone G (Dutchess County) includes dual fuel capability. From the perspective of translating the
NOx emissions cap required for a synthetic minor source, each hour of operation on ULSD is
roughly equivalent to three hours of operation on natural gas. Depending on the number of hours
the peaking plant operates on ULSD, the allowed hours of operation could be as low as
approximately 312 hours annually.82 The severely constraining nature of the emissions cap for a
dual fuel unit does not produce a viable peaking plant that appropriately supports reliability.83
For example, the NYISO recently developed enhancements to the ICAP market to better accommodate the participation of resources subject to daily run-time limitations.84 The
78 NYISO Final Recommendations at 14-15; Independent Consultant Final Report at 30; and AG Affidavit at ¶ 41.
79 Based on the proposal set forth herein, the resulting G-J Locality ICAP Demand Curve
reference point price for Load Zone G (Rockland County) is $14.57/kW-month for the 2021/2022
Capability Year, compared to $14.91 per kW-month for Load Zone G (Dutchess County). If SCR
emissions control technology were removed from the recommended design for Load Zone G (Dutchess County) and all other components of the NYISO’s proposal were to remain unaltered, the reference point price for Load Zone G (Dutchess County) would decrease to $13.33/kW-month for the 2021/2022
Capability Year. Thus, this revised value would represent the lowest reference point price of the locations evaluated for the G-J Locality ICAP Demand Curve and become the basis for such curve for the 2021-
2025 DCR. See NYISO Final Recommendations at 60; and NYISO Affidavit at ¶ 25.
80 Independent Consultant Final Report at 24-25; and NYISO Final Recommendations at 14.
81 Independent Consultant Final Report at 26; and NYISO Final Recommendations at 14.
82 Independent Consultant Final Report at 28; AG Affidavit at ¶ 41; BMCD Affidavit at ¶ 35; and NYISO Final Recommendations at 14-15. Comparatively, the synthetic minor approach for the gas-only peaking plant proposed for establishing the NYCA ICAP Demand Curve affords such unit to operate for approximately 1,060 hours annually.
83 NYISO Final Recommendations at 14-15; and AG Affidavit at ¶ 25 and 41.
84 Docket No. ER19-2276-000, New York Independent System Operator, Inc., Proposed Tariff Revisions Regarding Establishment of Participation Model for Aggregations of Resources, Including Distributed Energy Resources (June 27, 2019); and New York Independent System Operator, Inc., 170 FERC ¶ 61,033 (2020).
Honorable Kimberly D. Bose November 30, 2020
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enhancements include adjustments to ICAP payments based on each resource’s relative
contribution to resource adequacy (i.e., compensation designed to reflect the value of a resource
from the perspective of reliability). The NYISO plans to implement these enhancements
beginning with the 2021/2022 Capability Year (i.e., the first Capability Year encompassed by the
2021-2025 DCR). Initially, resources must be capable of providing the energy equivalent of
their ICAP obligation for at least 6 or 8 hours each day in order to be valued equivalent to a
resource that is not subject to any daily run-time limitations (i.e., qualify to receive 100% of the
applicable ICAP payment). However, once the incremental penetration level of resources
subject to daily run-time limitations exceeds 1,000 MW, only those resources that are capable of
operating for at least 8 hours daily will be valued equivalent to a resource that is not subject to
any daily run-time limitations. Ensuring the capability to operate 8 hours each day during the
period of the Summer Capability Period when load levels tend to be greatest (June - August)
would require the ability to operate for approximately 720 hours. The potential for the emissions
cap applicable to a synthetic minor source to limit the operation of a dual fuel peaking plant in
Load Zone G (Dutchess County) to as little as 312 hours annually does not support this level of
resource availability.
The ongoing transition of the resource fleet in New York to greater reliance on weather-
dependent renewable resources underscores the critical importance of flexible and controllable
resources.85 The availability of resources such as the peaking plant designs proposed herein will
be critical to maintaining system reliability as this transition continues to unfold. Subjecting
such resources to unnecessary operating limitations may adversely impact the availability of the
flexible and controllable capability offered by such resources to meet system needs and assist
with managing the greater variability introduced by a system with growing reliance on weather-
dependent resources.
As further described in the following section, the inclusion of dual fuel capability for the
peaking plant design used in establishing the G-J Locality ICAP Demand Curve remains
appropriate. The Commission should not alter this feature of the proposed peaking plant design.
Therefore, the peaking plant design for both the Dutchess County and Rockland County
locations should remain a dual fuel plant equipped with SCR emissions control technology.
C. Dual Fuel Capability
The NYISO proposes to maintain the dual fuel capability assumptions approved by the
Commission for the 2017-2021 DCR.86 For the 2021-2025 DCR, the NYISO proposes
continued inclusion of dual fuel capability for the peaking plants used to establish the G-J
85 See, e.g., NYISO, Reliability and Market Considerations for a Grid in Transition (December
20, 2019), available at: https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-
Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf.
86 See, e.g., 2017-2021 DCR Order at P 91.
Honorable Kimberly D. Bose November 30, 2020
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Locality, NYC, and LI ICAP Demand Curves.87 The NYISO also proposes continued use of a
gas-only design for the peaking plant used to establish the NYCA ICAP Demand Curve.88
For NYC and LI, dual fuel capability is mandated and must be included in the proposed
peaking plant designs for these regions.89 Certain local electric reliability rules applicable to
NYC and LI require dual fuel capability. Furthermore, in these locations, nearly all gas-fired
generators are interconnected to local distribution company (“LDC”) gas systems. LDC gas
tariffs in NYC and LI require that gas-fired generators connected to the LDC system include dual
fuel capability.
In contrast to NYC and LI, dual fuel capability is not explicitly mandated for the
proposed peaking plant designs used in establishing the NYCA or G-J Locality ICAP Demand Curves. There are no mandatory dual fuel requirements imposed by local electric reliability rules for these locations. Additionally, although LDC gas tariffs throughout these regions do impose dual fuel requirements for gas-fired generators connected to LDC systems, generators in these areas may have viable options to interconnect to an interstate gas pipeline. Direct
connection to an interstate gas pipeline would allow a gas-fired generator to bypass the
imposition of dual fuel capability that would apply to an interconnection with a LDC system. Absent mandatory requirements, the NYISO considered additional factors in evaluating whether the appropriate peaking plant design should include dual fuel capability.
The NYISO proposes to retain use of gas-only peaking plant designs for Load Zones C
and F.90 This determination is consistent with considerations for the 2017-2021 DCR.91 The
upstate region of New York is far less geographically constrained than the lower Hudson Valley,
NYC, and LI. This presents greater siting flexibility with broader availability of sites and
infrastructure to accommodate the interconnection of a new gas-fired plant. The magnitude and
severity of gas system constraints is also generally less acute than in the downstate region. This
arises, in part, from the connection of gas supply lines in upstate New York to neighboring shale
gas producing regions. Based on these factors, the NYISO proposes use of a gas-only peaking
plant design in establishing the NYCA ICAP Demand Curve for the 2021-2025 DCR.
The NYISO proposes a different conclusion for the peaking plant design used in
establishing the G-J Locality ICAP Demand Curve.92 Since its inception, the G-J Locality ICAP
87 NYISO Final Recommendations at 15-16 and 59; Independent Consultant Final Report at 7 and 34-36; and AG Affidavit at ¶ 25 and 32-35.
88 Id.
89 NYISO Final Recommendations at 15; Independent Consultant Final Report at 35; and AG Affidavit at ¶ 32 and 35.
90 NYISO Final Recommendations at 16; Independent Consultant Final Report at 35-36; and AG Affidavit at ¶ 25 and 35.
91 See, e.g., 2017-2021 DCR Filing at 18; and 2017-2021 DCR Order at P 95.
92 NYISO Final Recommendations at 15-16; Independent Consultant Final Report at 35-36; and AG Affidavit at ¶ 32 and 35.
Honorable Kimberly D. Bose November 30, 2020
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Demand Curve has used a dual fuel peaking plant design.93 The conditions supporting this
design remain the same for this DCR. The benefits of dual fuel capability in the downstate
region, including the lower Hudson Valley, has not diminished since the last reset. In fact, the critical importance of maintaining appropriate incentives to encourage resource flexibility and availability to operate on fuel sources other than solely natural gas have grown. Therefore, the NYISO proposes continued inclusion of dual fuel capability as part of the peaking plant design used for the G-J Locality ICAP Demand Curve.
Certain stakeholders oppose the inclusion of dual fuel capability as part of the peaking
plant design used for the G-J Locality ICAP Demand Curve. The Commission has considered
the objections raised by these stakeholders in each of the last two resets. These stakeholders
contend that in the absence of a mandatory dual fuel requirement for the lower Hudson Valley,
such capability should only be included if the incremental energy market revenue that can be
achieved for a particular Capability Year fully offsets the additional costs associated with the
inclusion of dual fuel capability in the peaking plant design. The assessment of additional
considerations, however, continues to support the inclusion of dual fuel capability for the G-J Locality ICAP Demand Curve.
The Commission’s prior approval of including dual fuel capability for the peaking plant
used in establishing the G-J Locality ICAP Demand Curve has considered multiple factors.
These considerations include improved siting flexibility, enhancements to reliability and
operational flexibility, and increased revenue earning opportunities when operation on natural
gas becomes unavailable or uneconomic due to gas system constraints and competing demand
for natural gas.94
The inclusion of dual fuel capability provides for increased siting flexibility for a gas-
fired peaking plant in the lower Hudson Valley.95 This enhanced flexibility is especially
important for geographically constrained areas, such as the lower Hudson Valley. The increased flexibility provides opportunities for a developer to identify a location for a new generation
facility that seeks to minimize both electric and gas interconnection costs. Notably, the DCR does not assume a particular gas interconnection option for any peaking plant (i.e., LDC system connection, or direct connection to an interstate pipeline). Instead, the gas interconnection cost assumptions reflect generic site assumptions and are intended to represent a cost to reasonably accommodate either gas interconnection option.
The ability of pipeline developers to expand the capability of the gas pipeline system in New York remains challenging.96 Absent expanded capability, competition for the use of natural gas to serve retail gas demands and electricity generation constrains the capability to
93 See, e.g., 2014-2017 DCR Order at P 83; and 2017-2021 DCR Order at P 92-93.
94 Id.
95 NYISO Final Recommendations at 15; Independent Consultant Final Report at 35-36; and AG Affidavit at ¶ 32 and 35.
96 Independent Consultant Final Report at 36; and AG Affidavit at ¶ 35.
Honorable Kimberly D. Bose November 30, 2020
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simultaneously serve all such demand. The constrained nature of the gas system is generally
greater in the downstate region than in upstate New York. In fact, the constrained nature of the
gas system downstate and increasing levels of demand for natural gas resulted in certain LDCs
imposing restrictions on service to new gas customers for periods during 2019.97 These
constraints underscore the benefits of being able to produce electricity using fuel sources other
than natural gas.
This capability also enhances resilience and operational flexibility in maintaining system reliability. The NYISO recently conducted a comprehensive, forward-looking evaluation of fuel and energy security in New York.98 The study did not identify any near-term reliability risks.
The availability of dual fuel capability throughout the current resource fleet was a key
contributing factor to the results. In fact, the study highlighted the importance of dual fuel
capability to maintaining reliability throughout the ongoing transition to a clean energy system in New York.99 The study specifically noted the critical importance of dual fuel capability in the
downstate region. The study observed:
Taking into consideration the demand for natural gas by LDCs for
serving retail needs, there is simply not enough gas available for
power generation under prolonged, severe cold winter conditions
to ensure reliable operations, absent the ability of dual-fuel units to
switch fuels. While these resources may operate economically -
and to the advantage of electricity consumers - most of the year on
available non-firm supplies of natural gas, under severe cold
weather conditions LDC demand and other firm natural gas
transportation commitments (including deliveries to neighboring
regions) reduce available natural gas for power generation to levels
below that needed for reliable system operations, absent the ability
to switch to oil. Maintaining adequate dual fuel and other oil-fired
operating capability is critical to reliable operations during adverse
winter conditions, especially in the downstate region.100
97 See, e.g., National Grid, National Grid to Lift Natural Gas Moratorium Immediately for
Customers in Brooklyn, Queens and Long Island (November 25, 2019), available at:
https://www.nationalgridus.com/News/2019/11/-National-Grid-to-Lift-Natural-Gas-Moratorium-
Immediately-for-Customers-in-Brooklyn,-Queens-and-Long-Island.
98 See NYISO Final Recommendations at 16; and AG, Fuel and Energy Security in New York
State - An Assessment of Winter Operational Risks for a Power System in Transition (November 2019),
available at:
https://www.nyiso.com/documents/20142/9312827/Analysis%20Group%20Fuel%20Security%20Final%
20Report%2020191111%20Text.pdf (“2019 Fuel Security Study”).
99 2019 Fuel Security Study at 70-74.
100 Id. at 70-71.
Honorable Kimberly D. Bose November 30, 2020
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In December 2019, the New York State Department of Environmental Conservation
(“NYSDEC”) adopted requirements to reduce smog-forming pollutants from simple-cycle
combustion turbines (“NYSDEC Peaker Rule”).101 These generators (commonly referred as
“peakers”) typically operate to maintain reliability during the most stressful operating conditions,
such as periods of peak electricity demand. The new regulation, which phases in compliance
obligations between 2023 and 2025, affects approximately 3,300 MW of simple-cycle turbines
located primarily in the lower Hudson Valley, NYC, and LI. The rule required affected
generators to submit compliance plans to the NYSDEC in March 2020. Based on the
compliance plans, the NYISO expects that, by May 1, 2025, approximately 1,800 MW of
nameplate capacity will likely be unavailable to operate during the summer in order to comply
with the rule’s emissions requirements.102 Notably, all but 85 MW of this capacity is either dual
fuel or operates on a primary fuel source other than natural gas.103 It is critically important to
maintain appropriate incentives for dual fuel capability in light of the anticipated loss of this
resource capability that has historically been available to operate on fuel sources other than
natural gas during critical operating conditions.
Based on the foregoing, maintaining dual fuel capability as part of the peaking plant
design used in establishing the G-J Locality ICAP Demand Curve remains appropriate and
reasonable. The ongoing transition of the resource fleet in New York only serves to highlight the importance of this capability to helping maintain reliability over the coming years.
D. Peaking Plant Costs
The Services Tariff requires that the DCR assess “the localized levelized embedded cost
of a peaking plant” used in establishing each ICAP Demand Curve. The Independent Consultant
conducted a rigorous evaluation to develop estimates of the capital investments costs to construct
the proposed peaking plant designs used for each ICAP Demand Curve.104 The Independent
Consultant also developed estimates of the fixed operations and maintenance (“O&M”) and
variable O&M costs associated with the ongoing operation of each such peaking plant.105 The
101 6 NYCRR Subpart 227-3, available at: https://www.dec.ny.gov/regulations/116131.html.
102 See NYISO, 2020 RNA Report at 12-15 (presented at the October 28, 2020 Management Committee meeting), available at:
https://www.nyiso.com/documents/20142/16333532/06%202020%20RNA%20Presentation.pdf.
103 See NYISO, 2020 Load & Capacity Data Report at Table III-2, available at:
https://www.nyiso.com/documents/20142/2226333/2020-Gold-Book-Final-Public.pdf.
104 Independent Consultant Final Report at 36-59 and Appendix A; AG Affidavit at ¶ 19-24 and 28-29; and BMCD Affidavit at ¶ 10-20. The Independent Consultant developed cost estimates for
generic sites within the following locations for each ICAP Demand Curve: (1) Load Zones C and F for the NYCA ICAP Demand Curve; (2) Load Zone G (Dutchess County) and Load Zone G (Rockland County) for the G-J Locality ICAP Demand Curve; (3) Load Zone J for the NYC ICAP Demand Curve; and (4) Load Zone K for the LI ICAP Demand Curve.
105 Independent Consultant Final Report at 36-59 and Appendix A; and BMCD Affidavit at ¶ 10-
20.
Honorable Kimberly D. Bose November 30, 2020
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Independent Consultant developed the cost estimates based on BMCD’s experience as a
contractor, engineering design firm, and consultant in the power generation and energy storage industries. BMCD’s experience includes recent work related to both power generation and energy storage projects in New York.106
The Independent Consultant developed the cost estimates based on a generic site in each location evaluated.107 For all locations other than New York City, the Independent Consultant assumed use of a generic greenfield site.108 For New York City, BMCD assumed use of a
brownfield site.109 The New York City cost estimate also includes an assumed need to raise the existing site elevation by 4 feet to comply with floodplain zoning requirements implemented
following Hurricane Sandy.110
The NYISO has reviewed the Independent Consultant’s cost estimates and considered stakeholder feedback relating thereto. The NYISO proposes to adopt the cost estimates
developed by the Independent Consultant for the peaking plants proposed herein for use in establishing the ICAP Demand Curves.111
The following sections provide an overview of the cost estimates developed by the
Independent Consultant. These sections also address certain concerns raised by stakeholders during the DCR regarding the cost estimates.
1. Capital Investment Costs
The capital investment costs include the installed cost of the peaking plant, owner’s costs,
and financing during construction. The installed cost estimates reflect use of an engineering,
procurement, and construction (“EPC”) contract.112 EPC cost estimates were prepared for a
generic site in each location evaluated and do not include preliminary engineering or
development activities. Direct costs included within the EPC cost estimates include labor,
materials, engineered equipment, subcontracts, and construction equipment.113 The EPC cost
estimates also include certain indirect costs such as construction management, engineering,
startup activities, warranty, and other general administrative expenses.114 The EPC cost
106 Independent Consultant Final Report at 36-39; and BMCD Affidavit at ¶ 15-20. 107 Independent Consultant Final Report at 36-39; and AG Affidavit at ¶ 28-29. 108 Independent Consultant Final Report at 37.
109 Id. at 37-38.
110 Id. 38.
111 NYISO Final Recommendations at 17-24.
112 Independent Consultant Final Report at 42, 45-47 and Appendix A; and BMCD Affidavit at ¶
14-16.
113 Independent Consultant Final Report at 42; and BMCD Affidavit at ¶ 15. 114 Independent Consultant Final Report at 42.
Honorable Kimberly D. Bose November 30, 2020
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estimates also include a 10% contingency applied to all direct and indirect project costs to
account for uncertainties, as well as a 5% EPC contractor fee applied to all direct and indirect
costs.115
2. Owner’s Costs
The owner’s costs consist of various categories of costs, including development
activities, project management oversight, project engineering, permitting, legal fees, financing
during construction, initial fuel inventory for dual fuel plant designs,116 and emissions reduction
credits (“ERCs”).117 The owner’s cost also includes estimates for both electric and gas
interconnections.118 Owner’s costs also include: (1) an assumed cost of 0.45% applied to all
EPC costs for builder’s risk insurance; and (2) a 5% contingency applied to all EPC and Owner’s
costs.119
Certain stakeholders contend that the owner’s cost estimates are understated and do not
appropriately account for certain costs of developing a new gas-fired generator in New York.120
These stakeholders identified certain owner’s cost line items from the 2017-2021 DCR and
attempt to compare such line items to the costs developed by BMCD for this DCR.121 Specific
costs identified by such stakeholders include engineering, development, permitting, and
financing fees during construction. It is important to recognize that cost categorization and
methodology used by BMCD in this DCR differ from those used by a different engineering and
design firm that was involved with the 2017-2021 DCR.122 As a result, attempting to conduct a
line-by-line comparison to the owner’s cost estimate developed for the 2017-2021 DCR is likely
115 Id.
116 For dual fuel plants, the initial fuel inventory provides the capability to operate the proposed peaking plants for 96 hours before needing to replenish the ULSD supply. This represents an onsite reserve to support round-the-clock operation on ULSD for four days (or the capability to operate on ULSD during on-peak periods for six days).
117 Independent Consultant Final Report at 43-45 and Appendix A; and BMCD Affidavit at ¶ 16.
For New York City, the peaking plant design assumes use of municipal water supply. The cost of a water
line to the plant to connect to the municipal system is included in the owner’s cost. For all other
locations, BMCD assumed that the proposed peaking plants obtain water supply from an onsite well. The
cost for such onsite well is included as part of the EPC cost estimate. See Independent Consultant Final
Report at 45.
118 Independent Consultant Final Report at 44-45. The electric and gas interconnection cost are intended to reflect “all-in” estimates that include development, engineering, permitting, procurement, equipment/materials, and construction. See BMCD Affidavit at ¶ 44.
119 Independent Consultant Final Report at 43.
120 BMCD Affidavit at ¶ 41-45.
121 Notably, BMCD was not the engineering and design firm used for the 2017-2021 DCR. 122 Id. at ¶ 42-44.
Honorable Kimberly D. Bose November 30, 2020
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to produce inadvertently misleading results.123 For example, for this DCR, the cost estimates
developed for electrical and gas interconnections are intended to reflect “all-in” costs and include the costs related to development, engineering, permitting, procurement, and construction
materials. The scope of work and components of project development addressed by the owner’s cost estimates by each firm may also differ.124
In response to the concerns raised by stakeholders, BMCD conducted a comparative
assessment of the aggregate total of the owner’s cost components from the 2017-2021 DCR to
the same costs for this DCR.125 Comparing the costs on an aggregate basis provides a more
informative comparison and mitigates the potential for inaccurate conclusions that can result
merely from the use of divergent cost categorization approaches and methodologies by different
engineering and design firms. After escalating the costs from the 2017-2021 DCR to current
year dollar values, BMCD’s evaluation identified very little divergence in costs.126 In fact, the
observed difference in aggregate owner’s costs was only 0.3%.127 BMCD’s assessment also
observed a difference of only 0.9% in aggregate total capital investment costs.128
Electric Interconnection
The electrical interconnection cost estimates include all necessary costs required to
satisfy the Minimum Interconnection Standard.129 For locations other than New York City, these
costs include an assumed three-mile, overhead generator lead between the plant’s switchyard and
the point of interconnection (“POI”).130 For New York City, BMCD assumed a one-mile,
underground interconnecting transmission line between the plant’s switchyard and POI.131 The
Independent Consultant assumed that plant switchyards use air insulated switchgear (“AIS”) in
all locations, except New York City. For New York City, the Independent Consultant assumed
the peaking plant’s switchyard would include gas insulated switchgear (“GIS”).132
123 Id. at ¶ 43.
124 Id. at ¶ 44.
125 Id. at ¶ 45. BMCD conducted this cost comparison using a dual fuel H-class frame turbine
peaking plant equipped with SCR emissions control technology in Load Zone G (Dutchess County).
126 BMCD Affidavit at ¶ 45.
127 NYISO Final Recommendations at 18-19 and Appendix D; and BMCD Affidavit at ¶ 45. The total difference in owner’s cost estimates was less than $200,000 after escalating the estimates from the 2017-2021 DCR to 2020 dollar values.
128 BMCD Affidavit at ¶ 45.
129 Independent Consultant Final Report at 44 and Appendix A. These costs include developer attachment facilities, system upgrade facilities, and connecting transmission owner attachment facilities. The estimated cost of the generator step-up transformer is included in the EPC cost estimate.
130 Independent Consultant Final Report at 44.
131 Id.
132 Id.
Honorable Kimberly D. Bose November 30, 2020
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The NYISO conducted an assessment to determine whether any of the proposed peaking plants would incur System Deliverability Upgrade (“SDU”) costs to obtain Capacity Resource Interconnection Service (“CRIS”).133 The assessment concluded that the proposed peaking plants for each location could be constructed without a need to incur SDU costs.134
Gas Interconnection
For locations other than New York City, the gas interconnection cost estimate consists of
two components: (1) an estimated cost of $3.5 million for a metering and regulation station; and
(2) an estimated average gas lateral cost of $250,000 per inch diameter per mile.135 Based on its prior experience with gas laterals for generation facilities, BMCD assumed a 5-mile, 16-inch diameter lateral for the peaking plants proposed herein.136
For New York City, the estimated gas interconnection assumes a 1-mile, 16-inch
diameter lateral for the proposed peaking plant.137 The total estimated cost of the gas lateral for
New York City is $20 million, consisting of a $5 million estimated cost for a metering and
regulation station and $15 million for the 1-mile lateral.138 The lateral costs reflect the
reasonable expectation of the increased costs associated with constructing a lateral within New
York City.139
Certain stakeholders contend that the average per inch diameter per mile costs for a gas lateral are understated, especially in the lower Hudson Valley. The Independent Consultant
carefully considered this feedback and conducted additional reviews of its estimated costs during the DCR.140 Based on the results of its supplemental evaluations, BMCD adjusted its
preliminary cost estimates for all locations.141
133 NYISO Final Recommendations at 16-17. As required by the Commission, the NYISO
conducted the deliverability assessment under the tariff-prescribed level of excess conditions used for the DCR. See, e.g., 2011-2014 DCR Order at P 53.
134 NYISO Final Recommendations at 17; and Independent Consultant Final Report at 44.
135 Independent Consultant Final Report at 45 and Appendix A; and BMCD Affidavit at ¶ 36. 136 Independent Consultant Final Report at 45; and BMCD Affidavit at ¶ 36.
137 Id.
138 Id.
139 BMCD Affidavit at ¶ 36. The $15 million lateral cost effectively represents an implicitly higher per inch diameter per mile cost to reflect the greater difficulty of constructing a gas pipeline in New York City.
140 BMCD Affidavit at ¶ 37; and NYISO Final Recommendations at 19.
141 Id.
Honorable Kimberly D. Bose November 30, 2020
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For locations other than New York City, BMCD initially assumed an estimated lateral
cost of $180,000 per inch diameter per mile.142 In response to stakeholder concerns, BMCD
conducted a further reviewed based on its recent project experience and a review of cost
estimates for five recent projects in or near New York.143 The set of projects reviewed included
two recent gas lateral connections for generators interconnected to New York, as well as three
interstate pipeline projects.144 The average per inch diameter per mile costs observed for these
projects ranged from approximately $100,000 to $500,000.145 The average linear cost for these
projects was approximately $260,000 per inch diameter per mile.146 The two gas lateral projects
included as part of the assessment established the highest and lowest values within the dataset.
Based on the results of the supplemental analysis, BMCD concluded it was reasonable to adjust
its initial assumption. As a result, BMCD increased the assumed linear cost of a gas lateral to
$250,000 per inch diameter per mile.147
3. Fixed O&M
Fixed O&M costs generally address fixed plant expenses not affected by the operation of the plant.148 Fixed O&M consists of two components: (1) fixed plant expenses (e.g., plant staff labor, routine maintenance, safety equipment, building and grounds maintenance, and
administrative and general expenses); and (2) fixed non-operating expenses (e.g., site leasing costs, property taxes, and insurance).149
Property Taxes
The property tax treatment for the proposed peaking plants varies by location.150 The
recommended property tax treatment for New York City varies from all other locations due to
the availability of a statutorily provided tax abatement. For all other locations, the recommended
142 NYISO Final Recommendations at 19.
143 Independent Consultant Final Report at 45; BMCD Affidavit at ¶ 37; and NYISO Final Recommendations at 19.
144 BMCD Affidavit at ¶ 37; and NYISO Final Recommendations at 19. The supplemental
analysis included consideration of costs for the following projects: (1) CPV Valley Millennium Pipeline
[gas lateral connection for a generator]; (2) Bayonne Lateral Delivery project [gas lateral connection for a
generator]; (3) the Northern Access pipeline project [interstate pipeline project]; (4) the Constitution
pipeline project [interstate pipeline project]; and (5) PennEast pipeline project [interstate pipeline project].
145 BMCD Affidavit at ¶ 37; and NYISO Final Recommendations at 19.
146 Id. Exclusion of the highest and lowest observed linear costs for the dataset produced an average linear cost of approximately $240,000 per inch diameter per mile.
147 BMCD Affidavit at ¶ 37; and NYISO Final Recommendations at 19.
148 Independent Consultant Final Report at 48-51; BMCD Affidavit at ¶ 18; and NYISO Final Recommendations at 24.
149 Independent Consultant Final Report at 48-51.
150 Independent Consultant Final Report at 50-51; and NYISO Final Recommendations at 29-31.
Honorable Kimberly D. Bose November 30, 2020
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property tax rate assumes the proposed peaking plant will enter into a payment in lieu of taxes (“PILOT”) agreement.
The peaking plant used in establishing the NYC ICAP Demand Curve qualifies for an as-
of-right tax abatement pursuant to New York State Real Property Tax law.151 The statutory tax
abatement applies for the first 15 years of the assumed amortization period for the peaking plant.
For the remaining duration of the assumed amortization period, the assumed property tax rate is
4.7%.152
For locations other than New York City, the applicable property tax rate assumes that each peaking plant will enter into a PILOT agreement.153 The assumed property tax rate for locations other than New York City is 0.5%.154 The Independent Consultant developed this rate based on a review of PILOT payment data for eight gas-fired generators in various locations through New York outside of New York City.155
Land Lease Costs
Consistent with the methodology used in the last two resets, BMCD initially derived the
assumed land lease costs based on escalating the values used in the 2017-2021 DCR.156 The
resulting land lease cost assumptions are as follows: (1) $22,000 per acre-year for Load Zones C,
F, G (Dutchess County), and G (Rockland County); (2) $26,000 per acre-year for Long Island;
and (3) $270,000 per acre-year for New York City.157
Certain stakeholders have raised concerns with the assumed land lease costs for New
York City. For the New York City peaking plant, BMCD assumed a land lease cost of $270,000
per acre-year.158 To support their concerns that the estimated land lease value was understated,
certain stakeholders submitted recently conducted real estate appraisals for certain utility
properties within New York City.159 The estimated land lease costs based on such appraisals
were approximately double BMCD’s proposed land lease cost for New York City. In response
to these estimates, BMCD conducted a supplemental evaluation to determine whether the
151 New York Real Property Tax Law § 489-BBBBBB(3)(b-1).
152 Independent Consultant Final Report at 51; and NYISO Final Recommendations at 29-30.
153 Independent Consultant Final Report at 50-51; and NYISO Final Recommendations at 30-31.
154 Id.
155 Id.
156 Independent Consultant Final Report at 49.
157 Id.
158 Independent Consultant Final Report at 49; BMCD Affidavit at ¶ 38-40; and NYISO Final Recommendations at 24.
159 Independent Consultant Final Report at 49; and BMCD Affidavit at ¶ 38-40.
Honorable Kimberly D. Bose November 30, 2020
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assumed value (i.e., $270,000 per acre-year) was reasonable or potentially required adjustment.160
BMCD’s supplemental analysis reviewed data regarding property values for more than
15 representative sites and estimated lease rates relating thereto from a variety of sources.161 The
data sources used included: (1) property tax values for properties adjacent to existing generation
facilities within New York City; (2) the stakeholder-provided appraisals; (3) recent market
transaction data; and (4) quotes previously obtained by BMCD through discussions with property
owners in New York City as part of work conducted for other power generation and energy
storage projects in New York City.162 The supplemental evaluation showed a high level of
variability in potential lease costs for representative sites in New York City. The estimated lease
costs for the sites evaluated ranged from $10,000 per acre-year to $1 million per acre-year.163
BMCD’s supplemental evaluation included nine sites in New York City adjacent to existing
power plants.164 The average land lease cost estimated for these sites was approximately
$160,000 per acre-year.165 Based on the variability observed, BMCD concluded that the
assumed land lease cost of $270,000 per acre-year is reasonable for purposes of this DCR.166
Given observations of significantly lower costs than the appraisal data for the specific sites
provided by stakeholders, the recommended value is consistent with the expectation that a
developer in a competitive market would seek to lower its overall costs to the extent practicable.
160 Independent Consultant Final Report at 49; BMCD Affidavit at ¶ 19 and 38-40; and NYISO Final Recommendations at 24 and Appendix C.
161 BMCD Affidavit at ¶ 38-39; and NYISO Final Recommendations at Appendix C.
162 BMCD Affidavit at ¶ 19 and 38-39; and NYISO Final Recommendations at Appendix C. 163 BMCD Affidavit at ¶ 39-40; and NYISO Final Recommendations at Appendix C.
164 BMCD Affidavit at ¶ 39.
165 BMCD Affidavit at ¶ 39-40; and NYISO Final Recommendations at Appendix C.
166 BMCD Affidavit at ¶ 40. The NYISO evaluated the potential impact of differing land lease
cost assumptions for New York City on the resulting reference point price for the NYC ICAP Demand
Curve for the 2021/2022 Capability Year. Increasing the assumed land lease cost to $350,000 per acre-
year (i.e., a value that is approximately equal to the average lease cost for sites used in BMCD’s
supplemental analysis) would result in a $22.75/kW-month reference point price for the 2021/2022
Capability Year NYC ICAP Demand Curve (i.e., an increase of $0.39/kW-month compared to the
NYISO’s proposal). Utilizing an assumed land lease cost of $540,000 per kW-month (i.e., double the
recommended value and similar to the value advocated by stakeholders opposing the recommended
value) would increase the reference point price of the NYC ICAP Demand Curve for the 2021/2022
Capability Year to $23.67/kW-month (i.e., an increase of $1.31/kW-month compared to the NYISO’s
proposal). See NYISO Affidavit at ¶ 26.
Honorable Kimberly D. Bose November 30, 2020
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4. Variable O&M
Variable O&M costs directly relate to the operation of each peaking plant and the
production of electricity.167 These costs include routine equipment maintenance, water usage, water treatment, water disposal, and other consumables including fuel. For peaking plant designs that include SCR emissions control technology, variable O&M costs also include ammonia and catalyst replacements.
Variable O&M also includes major maintenance costs. For the proposed peaking plant
designs, major maintenance typically includes turbine, hot gas path, and major inspections. The
Independent Consultant assumed recovery of major maintenance costs primarily on a per start
basis.168
The variable O&M costs and operational and performance specifications for the proposed peaking plants are utilized in estimating the potential revenues such plants could earn from
participation in the NYISO-administered Energy and Ancillary Services markets.
IV.Net Energy and Ancillary Services Revenue Estimates
The Services Tariff requires that the DCR assess the likely net energy and ancillary
services (“EAS”) revenues that a peaking plant could potentially earn from participation in the
NYISO-administered markets.169 The estimated net EAS revenues serve as an offset to the
estimated cost to construct and operate a peaking plant. The resulting net value determines the
revenue a peaking plant would need to receive from the capacity market to obtain sufficient
revenues to support market entry under the tariff-prescribed level of excess conditions.
The estimated net EAS revenues are determined using historical data.170 The NYISO
uses the most recent three years of historical market prices and fuel and other variable operating
costs, along with the operating characteristics of the peaking plant, to estimate the potential
revenue earnings for each peaking plant. This approach assumes that the estimated average
annual net EAS revenues a peaking plant could have earned over the most recent three-year
period provides a reasonable estimate of forward-looking expectations. The NYISO updates
167 Independent Consultant Final Report at 52-53 and Appendix A; BMCD Affidavit at ¶ 18; and NYISO Final Recommendations at 23-24.
168 Independent Consultant Final Report at 52-53 and Appendix A. 169 Services Tariff § 5.14.1.2.2.
170 See Services Tariff § 5.14.1.2.2.2; Docket No. ER16-1751-000, New York Independent System Operator, Inc., Proposed Services Tariff Revisions to Implement Enhancements to the Periodic Reviews of the ICAP Demand Curves at 5-7 (May 20, 2016) (“DCR Process Enhancements Filing”); and New
York Independent System Operator, Inc., 156 FERC ¶ 61,039 at P 16 (2016) (“DCR Process
Enhancements Order”).
Honorable Kimberly D. Bose November 30, 2020
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these estimates pursuant to the tariff-prescribed annual updating procedures to ensure that the ICAP Demand Curves incorporate changes in market outcomes over time.171
A. Net EAS Model
The Services Tariff requires the development of a model to determine the net EAS
revenues estimates for each peaking plant.172 This model is commonly referred to as the “Net EAS Model.”
The Independent Consultant, in collaboration with stakeholders and the NYISO,
developed the Net EAS Model for use during the 2021-2025 DCR.173 The proposed Net EAS
Model for the 2021-2025 DCR is substantially similar to the Net EAS Model approved by the
Commission for the last reset.174 The revisions to the prior model’s commitment and dispatch
logic for the 2021-2025 DCR relate to: (1) the manner in which the model applies gas prices in
estimating each peaking plant’s variable operating cost to produce electricity;175 and (2) the
assumed cost for dual fuel peaking plants to provide Operating Reserves.176 The NYISO further
describes each of these changes to the model’s commitment and dispatch logic below.
To enhance transparency and accessibility of the Net EAS Model to stakeholders, the Independent Consultant developed the model for the 2021-2025 DCR using “R” programming language, which is a free, open source software.177 Comparatively, the 2017-2021 DCR Net EAS Model used “SAS” software that requires obtaining a license to use.
The NYISO proposes to adopt the Net EAS Model developed by the Independent
Consultant.178 The Net EAS Model developed during the DCR is posted on the NYISO website
and publicly available to all interested parties.179 The NYISO used the model in determining the
2021/2022 Capability Year ICAP Demand Curves proposed herein. Subject to updating certain
data inputs as required by the tariff prescribed annual updates, the Net EAS Model remains fixed
171 See, e.g., New York Independent System Operator, Inc., 156 FERC ¶ 61,039 at P 27 (2016); and 2017-2021 DCR Order at P 166.
172 Services Tariff § 5.14.1.2.2.2.
173 AG Affidavit at ¶ 42-52.
174 See 2017-2021 DCR Filing at 22-25; and 2017-2021 DCR Order at P 17, n. 27, and 166.
175 NYISO Final Recommendations at 32-33 and Appendix B; and AG Affidavit at ¶ 51.
176 NYISO Final Recommendations at 37 and Appendix A, p. 8-10; Independent Consultant Final Report at 80; and AG Affidavit at ¶ 46.
177 NYISO Final Recommendations at 33. 178 Id. at 31-33.
179 Services Tariff § 5.14.1.2.2.2. The Net EAS Model is contained within a zip folder titled
“2020-09-09-Report Final Fossil Model” available at: https://www.nyiso.com/installed-capacity-market.
From this page, the model can be obtained by navigating through the following content sections:
“Reference Documents”“2021-2025 Demand Curve Reset”“Final Models and Materials.”
Honorable Kimberly D. Bose November 30, 2020
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for the duration of the 2021-2025 DCR.180 The NYISO will use this same model in conducting the annual updates to determine the ICAP Demand Curves for the 2022/2023 through 2024/2025 Capability Years.
As previously noted, this DCR was the first to assess energy storage technology as a
potential peaking plant. Participation by energy storage in the market is fundamentally different
than fossil-fired generators. As a result, the Independent Consultant developed a separate Net
EAS Model for the energy storage technology options assessed in this DCR.181 Due to the
availability of lower cost alternatives, the NYISO does not recommend battery storage as the
peaking plant in any location for the 2021-2025 DCR.182 As a result, the NYISO does not
propose adoption of the Net EAS Model developed for energy storage resources as part of this
filing.183
1. General Overview of Net EAS Model
The Net EAS Model determines the estimated annual net EAS revenues each peaking
plant could potentially earn based on 36 months of historical data on market prices and variable
costs.184 Generally, for each hour of the historical period, the model determines whether each
peaking plant should be committed and dispatched to produce Energy or provide Operating
Reserves based on a consideration of historical energy and reserve prices (both as adjusted to
account for the tariff-prescribed level of excess conditions), variable operating costs (i.e., fuel
and emission allowance prices, non-fuel variable costs, and start-up costs), and the operational
characteristics of the peaking plant. The model considers both Day-Ahead and real-time
commitment and dispatch opportunities, while respecting the physical operating characteristics
of the peaking plant. This includes the ability of the peaking plant to buy-out of a previously
determined Day-Ahead commitment in real-time to the extent it would be economically
advantageous for the plant to do so, as well as the ability to produce Energy or provide Operating
Reserves in real-time in the absence of a prior Day-Ahead commitment. For peaking plants that
include dual fuel capability, the model also accounts for such capability through considering
whether it is less expensive to operate using natural gas or ULSD.
180 Services Tariff § 5.14.1.2.2.2.
181 Independent Consultant Final Report at 83-90; AG Affidavit at ¶ 53-58; and NYISO Final Recommendations at 38-43.
182 NYISO Final Recommendations at 59; Independent Consultant Final Report at 7; and AG Affidavit at ¶ 25 and 31.
183 For informational purposes, however, the alternative model developed for energy storage is
posted on the NYISO’s website and publicly available. This version of the model is contained within a
zip folder titled “2020-09-09-Report Final Battery Model” available at: https://www.nyiso.com/installed-
capacity-market. From this page, the model can be obtained by navigating through the following content
sections: “Reference Documents”“2021-2025 Demand Curve Reset”“Final Models and Materials.”
184 Independent Consultant Final Report at 77-83 and 90-99; AG Affidavit at ¶ 42-52; and NYISO Final Recommendations at 31-33 and 36-38.
Honorable Kimberly D. Bose November 30, 2020
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The figures below provide an overview of the commitment and dispatch logic of the proposed Net EAS Model.185
Net EAS Revenues Model Day-Ahead Commitment Logic
Energy Block
Profitable?
Yes
Reserve Profit >=
Energy Profit?
YesNo
Commit DAMCommit DAM
ReserveEnergy
No
Reserve Profit > 0?
YesNo
Commit DAMNo DAM
ReserveCommitment
Net EAS Revenues Model Real-Time Commitment and Dispatch Logic
DAM
Commitment?
EnergyNo Commitment
Reserve
RTD Reserve
More Profitable?
YesNo
Buy Out of Energy
Commitment at RTD
Price w/ Fuel Penalty
Provide
RTD Energy
More Profitable?
No
Yes
Buy Out of Reserve
Commitment at RTDSimilar logic to
Priceday-ahead using
real-time prices
to select Provide
Reserves
DispatchDispatch
dispatch Reserves
The model also accounts for any operating hour restrictions or emissions limitations
imposed on the peaking plant to comply with applicable environmental requirements.186 These
limitations are essentially applied after-the-fact. The model will first determine the optimal
dispatch of the peaking plant for a given 12-month period (i.e., September through August). If
the optimal dispatch exceeds a specified annual operating limitation, the model will then reduce
the number of hours that it determined the peaking plant would otherwise produce Energy to
ensure compliance with the specified limitation. In doing so, the model reduces the hours in
which the peaking plant would otherwise produce Energy by eliminating the hours with the
185 Independent Consultant Final Report at 81.
186 Id. at 79-80; and AG Affidavit at ¶ 50.
Honorable Kimberly D. Bose November 30, 2020
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lowest level of net Energy revenues first. The model continues eliminating hours based on
increasing values of net Energy revenues earned in each hour until it has eliminated a sufficient number of hours to ensure compliance with the specified limitation.
An adder to reflect expected revenues for Ancillary Services not accounted for in the model increases the net EAS revenues determined by the model.187 The value of this adder for the proposed peaking plants is $2.04 per kW-year. This adder accounts for likely voltage
support service (“VSS”) revenues.188
2. Gas Price Alignment Logic
The preliminary Net EAS Model developed as part of the DCR included logic that shifted forward by one day the gas price published for a specific date by S&P Global Market
Intelligence (“SPGMI”) (i.e., the data vendor proposed by the NYISO as the source of gas price data for the 2021-2025 DCR).189 This logic was based on an understanding that the gas prices published by SPGMI represented the “trade day” price (or the day before the generator would take delivery of and use the gas to produce electricity).190
Certain stakeholders raised concerns that this gas pricing alignment logic was
inappropriate and instead produced a misalignment between the gas price used for a specific electric operating day and the natural gas costs a unit would face on such operating day. In response to such concerns, the NYISO and Independent Consultant conducted an additional review of the gas price data published by SPGMI. This supplemental review confirmed that the data published by SPGMI actually represents the “flow day” price (or the day the generator would take delivery of and use the gas to produce electricity).191
Due to the incorrect understanding of the gas pricing data, the pricing alignment logic
included in the preliminary Net EAS Model for the 2021-2025 DCR was, in fact, unnecessary.
The initial gas price alignment logic incorrectly assumed that SPGMI was posting “trade day”
prices. As a result, the logic shifted the gas price forward by one day in an unnecessary attempt
187 Services Tariff § 5.14.1.2.2.2.
188 Independent Consultant Final Report at 90; AG Affidavit at ¶ 50; and NYISO Final Recommendations at 57.
189 This same logic was previously included in the Net EAS Model developed for the 2017-2021 DCR. See Docket No. ER21-130-000, New York Independent System Operator, Inc., Exigent
Circumstances Filing Requesting Authority Under Section 205 of the Federal Power Act to Address
Prospectively a Gas Pricing Logic Alignment Issue Affecting the Net Energy and Ancillary Services
Revenue Offset Values Embedded in the 2017-2021 Installed Capacity Demand Curves, Request for
Shortened Notice and Comment Period, Request for Expedited Action, Notice of Intent to Implement, and Contingent Request for Commission Action Under Section 206 of the Federal Power Act (October 16, 2020); and Docket No. ER21-130-000, supra, Letter Order (October 22, 2020).
190 NYISO Final Recommendations at 32-33 and Appendix B; and AG Affidavit at ¶ 51. 191 NYISO Final Recommendations at 33; and AG Affidavit at ¶ 51.
Honorable Kimberly D. Bose November 30, 2020
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to align the gas price with the electric market day on which the peaking plant would use such
gas.192
The Independent Consultant and NYISO updated the Net EAS Model for the 2021-2025
DCR to remove the unnecessary gas pricing alignment logic.193 The updated model uses the gas
prices published for a particular date for the same electricity market day that the peaking plant
receives delivery of such gas. For any day on which gas price data is not published by SPGMI
(e.g., weekends and holidays), the updated model utilizes the next available day on which a gas
price is published as the applicable price for the day(s) on which prices are not published by
SPGMI. For example, for a non-holiday weekend, the Net EAS Model uses the gas price
published by SPGMI on Monday as the applicable gas price for Saturday, Sunday, and Monday.
The 2021/2022 Capability Year ICAP Demand Curves proposed herein were determined using the final, updated version of the model. This version of the model, which the NYISO proposed to adopt for the 2021-2025 DCR, appropriately reflects removal of the prior,
unnecessary gas pricing alignment logic.194
3. Operating Reserve Cost for Dual Fuel Peaking Plants
The Net EAS Model includes an assumed cost for a peaking plant to take a reserve
position.195 The preliminary model developed for the 2021-2025 DCR assumed a cost to provide reserves equal to the intraday premium for acquiring natural gas, which varies from 10-30%
depending on location.
Analysis conducted by the MMU identified that the preliminary model likely overstated
the assumed cost to provide reserves, especially for peaking plant designs that include dual fuel
capability.196 The MMU analyzed historical reserve offers by dual fuel resources in Load Zones
J and K.197 Based on the MMU’s analysis, the Independent Consultant updated the final version
of the Net EAS Model for the 2021-2025 DCR to include an assumed cost to provide reserves of
$2.00 per MWh for the proposed dual fuel peaking plants (i.e., Load Zone G (Dutchess County),
Load Zone G (Rockland County), NYC, and LI).198 For gas-only peaking plants (i.e., Load
192 NYISO Final Recommendations at Appendix B.
193 NYISO Final Recommendations at 33 and Appendix B; and AG Affidavit at ¶ 51.
194 Id.
195 NYISO Final Recommendations at 37-38; Independent Consultant Final Report at 80; and AG Affidavit at ¶ 46.
196 NYISO Final Recommendations at Appendix A, p. 8-10.
197 Affidavit of Pallas LeeVanSchaick, Ph.D. at ¶ 40-44 attached hereto as Attachment VI (“MMU Affidavit”).
198 NYISO Final Recommendations at 37; Independent Consultant Final Report at 80; AG Affidavit at ¶ 46; and MMU Affidavit at ¶ 40-44.
Honorable Kimberly D. Bose November 30, 2020
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Zones C and F), the final Net EAS Model retains use of the intraday premium for determining the cost to provide reserves.199
The 2021/2022 Capability Year ICAP Demand Curves proposed herein were determined using the final, update version of the model. This version of the model, which the NYISO
proposed to adopt for the 2021-2025 DCR, reflects the updated assumptions regarding the cost for a peaking plant to provide reserves.
B. Natural Gas Pricing Assumptions
The DCR requires the selection of appropriate data sources for fuel prices.200 The
representative fuel pricing for each location remains fixed for the duration of the reset period.201 For natural gas prices, this includes both the data source from which the applicable historical
prices are determined, as well as the appropriate natural gas hub pricing point(s) for each peaking plant location. Consistent with the 2017-2021 DCR, the NYISO proposes continued use of gas pricing data from SPGMI.202
As further described herein, the proposed gas hub for each location was determined based on the consideration of multiple factors. The NYISO’s proposed gas pricing for each location is as follows: (1) Load Zone C: the Tennessee Gas Pipeline (“TGP”) Zone 4 (200 leg) hub for April through November and the Niagara hub for December through March; (2) Load Zone F: the
Iroquois Zone 2 hub; (3) Load Zone G (Dutchess County): the Iroquois Zone 2 hub; (4) Load Zone G (Rockland County): the Texas Eastern Transmission Pipeline (“TETCO”) M3 hub; (5) NYC: the Transco Zone 6 NY hub; and (6) LI: the Iroquois Zone 2 hub.203
The selection of the appropriate gas hub for each location requires careful consideration
because, for nearly all locations, there are multiple available options. Consistent with the 2017-
2021 DCR, the Independent Consultant used a multi-factor assessment to determine the
appropriate natural gas hub pricing for each location.204 The criteria considered by the
assessment were: (1) market dynamics (i.e., correlation of gas hub prices with LBMPs for the
relevant location and the extent to which the gas hub prices reflect New York electricity market
dynamics); (2) the liquidity (i.e., selected gas hubs should have sufficient historical data to assess
historical trading volumes); (3) geographic proximity (i.e., the selected gas hubs should be
located in an area that is accessible to a peaking plant in a particular location); and (4)
199 NYISO Final Recommendations at 37; Independent Consultant Final Report at 80; and AG Affidavit at ¶ 46.
200 Services Tariff § 5.14.1.2.2.2.
201 Id.
202 NYISO Final Recommendations at 57; and Independent Consultant Final Report at 90.
203 NYISO Final Recommendations at 33-36 and Appendix A, p. 14-19 and 20-23.
204 NYISO Final Recommendations at 33-36; Independent Consultant Final Report at 90-99; and AG Affidavit at ¶ 59-60.
Honorable Kimberly D. Bose November 30, 2020
Page 35
precedent/continuity (i.e., assessing the extent to which gas hub options for a particular location have been used in other NYISO-related studies and evaluations).205
Use of multiple considerations facilitates the identification of a reasonable and
representative gas hub for each location that seeks to avoid material under or over estimating the potential revenue earnings of each peaking plant. This analysis also recognizes the potential
need for trade-offs and balancing among the criteria in the selection of an appropriate gas hub. Therefore, strict reliance on a single factor is not appropriate and may result in sub-optimal
outcomes. For example, in certain locations, marginal energy prices may often reflect the costs of resources from other areas. As a result, solely assessing market dynamics and correlation to historical energy prices may not accurately capture the gas prices applicable to units in such
areas.206 Additionally, overly strict application of the geographic proximity criteria may fail to accurately capture the dynamics of the gas market and the potential availability of multiple gas supply sourcing arrangements for generators in a given location.
Notably, the selection of an appropriate gas hub for each location does not presume any
particular gas purchasing strategy by each peaking plant. Instead, the analysis seeks to identify
appropriate pricing that is designed to produce reasonable estimates of the potential energy
market revenue earnings for each peaking plant. The analysis recognizes that a generator may
have a variety of gas purchasing options available to accommodate its acquisition of the fuel
necessary to operate.207 These options could potentially include contracting arrangements with
gas marketers or other entities that hold firm gas transportation rights, short-term purchases of
firm capacity releases, and/or the potential use of interruptible gas transmission service.
1. Load Zone C
The NYISO proposes to use a combination of two different gas hubs for Load Zone C for
the 2021-2025 DCR.208 This proposal recognizes historically observed availability constraints
during the winter period that may adversely affect the use of a single hub throughout the year.
Specifically, the NYISO proposes to adopt the recommendation of the MMU that relies on: (1)
the TGP Zone 4 (200 leg) hub outside the winter period (i.e., April through November); and (2)
the Niagara hub during the winter period when availability constraints are most likely to limit
accessibility to prices consistent with the TGP Zone 4 (200 leg) hub (i.e., December through
March).
205 NYISO Final Recommendations at 33-34; Independent Consultant Final Report at 90-92; and AG Affidavit at ¶ 59-60.
206 The 2018 and 2019 State of the Market Reports identified that generators located in central New York (which includes Load Zone C) were only marginal in 20-35% of all real-time intervals during 2018 and 2019. Therefore, during the majority of intervals, resources located in other areas of the State set the prices for this region. See NYISO Final Recommendations at Appendix A, p. 18.
207 Independent Consultant Final Report at 91-92; and MMU Affidavit at ¶ 17, 22, 27-30 and 38.
208 NYISO Final Recommendations at 34-35; NYISO Affidavit at ¶ 11-14; and MMU Affidavit at ¶ 10-23.
Honorable Kimberly D. Bose November 30, 2020
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An evaluation conducted by the MMU was a primary consideration in recommending the use of the TGP Zone 4 (200 leg) hub for Load Zone C.209 The MMU’s analysis compared the expected dispatch of gas-fired generators located in Load Zone C using various potential gas hub pricing options to the actual historical operation of such units.210 The MMU’s analysis
concluded that use of TGP Zone 4 (200 leg) served as reasonably accurate predictor of historical operations. As a result, the MMU recommended TGP Zone 4 (200 leg) as an appropriate proxy for gas pricing faced by units in Load Zone C.
The NYISO’s proposal differs slightly from the Independent Consultant’s recommended
gas pricing for Load Zone C. The Independent Consultant recommended use of only the TGP
Zone 4 (200 leg) for Load Zone C.211 Subsequent to the Independent Consultant’s issuance of its
final recommendation, as reflected in the interim version of its final report issued on August 5,
2020, the MMU completed supplemental analysis evaluating whether the TGP Zone 4 (200 leg)
was appropriate for use at all times throughout the year.212 The MMU’s supplemental analysis
was conducted in response to concerns raised by certain stakeholders as to the availability of gas
from TGP Zone 4 (200 leg) during winter months. The MMU’s additional analysis identified the
presence of historical availability concerns that may prevent a peaking plant located in Load
Zone C from accessing gas from TGP Zone 4 (200 leg) during the winter months.213
Due to the potential for TGP Zone 4 (200 leg) to be unavailable to a peaking plant in
Load Zone C during the winter months, the MMU recommended use of an alternative pricing
hub for the winter period (i.e., December through March).214 Absent use of an alternative pricing
hub during the winter, the MMU noted the potential for the Net EAS Model to unnecessarily
overestimate the potential revenue earnings of a peaking plant in Load Zone C during the winter
period when it would most likely face gas prices in excess of the prices at the TGP Zone 4 (200
leg) hub.215 After reviewing various alternative pricing hubs for the winter period, the MMU
recommended the use of the Niagara hub as an appropriate alternative that avoids the potential
209 Independent Consultant Final Report at 95; AG Affidavit at ¶ 64; NYISO Final Recommendations at 34; NYISO Affidavit at ¶ 11; and MMU Affidavit at ¶ 13-15.
210 NYISO Final Recommendations, Appendix A, p. 14-15; AG Affidavit at ¶ 64; and MMU Affidavit at ¶ 13.
211 Independent Consultant Final Report at 95-96; and AG Affidavit at ¶ 64.
212 NYISO Final Recommendations at 34-35 and Appendix A, p. 15-19; NYISO Affidavit at ¶ 11; and MMU Affidavit at ¶ 16-23.
213 NYISO Final Recommendations at 34-35 and Appendix A, p. 16-18; NYISO Affidavit at ¶ 11-
13; and MMU Affidavit at ¶ 16-21.
214 NYISO Final Recommendations at 34-35; NYISO Affidavit at ¶ 13; and MMU Affidavit at ¶ 15, 20-21 and 23.
215 NYISO Final Recommendations at Appendix A, p. 16-18; and MMU Affidavit at ¶ 14-15 and
21.
Honorable Kimberly D. Bose November 30, 2020
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for materially overstating or understating the expected revenue earnings of a peaking plant in Load Zone C.216
Certain stakeholders object to the NYISO’s proposal to use the Niagara hub for Load Zone C during the winter months. These stakeholders advocate for adopting the Independent Consultant’s recommendation to use only the TGP Zone 4 (200 leg) hub for the entire year.217 These stakeholders raise concerns regarding: (1) the opportunity afforded to adequately consider the Niagara hub during the DCR; and (2) the liquidity of trading the Niagara hub.
Certain stakeholders contend that the Niagara hub was not introduced for potential
consideration until late in the DCR process, claiming this effectively limited the ability to fully
consider use of the Niagara hub in the stakeholder process required by the DCR. These
stakeholders contend that potential use of the Niagara hub was not discussed prior to the MMU’s submission of comments on August 24, 2020 in response to NYISO staff’s draft
recommendations.218
Contentions that: (1) the Niagara hub was not discussed in the stakeholder process prior
to comments submitted in response to NYISO staff’s draft recommendations; and/or (2)
stakeholders were not afforded an adequate opportunity to present positions regarding the
potential use of the Niagara hub, are not accurate. The MMU initially submitted comments
addressing potential gas pricing considerations on February 26, 2020.219 The MMU’s comments
specifically recommended consideration of the Niagara hub as a potential option for Load Zone
C.220 The Independent Consultant reviewed an assessment of potential gas hubs with
stakeholders at the March 26, 2020 ICAPWG meeting. This assessment included consideration
of the Niagara hub as a potential candidate for Load Zone C.221 On August 5, 2020, the MMU
216 NYISO Final Recommendations at 34-35; NYISO Affidavit at ¶ 12-13; and MMU Affidavit at ¶ 10-11 and 23.
217 The NYISO’s recommendation for Load Zone C results in a proposed reference point price for
the NYCA ICAP Demand Curve of $8.62 per kW-month for the 2021/2022 Capability Year. The
resulting reference point price for the 2021/2022 Capability Year ICAP Demand Curve using the
Independent Consultant’s recommended gas hub for Load Zone C was $8.22 per kW-month. See NYISO
Final Recommendations at 5; Independent Consultant Final Report at 9; and NYISO Affidavit at ¶ 27.
218 See Potomac Economics, MMU Comments on Independent Consultant Interim Final Draft
ICAP Demand Curve Reset Report and NYISO Staff DCR Draft Recommendations (August 24, 2020),
available at: https://www.nyiso.com/documents/20142/14871137/MMU-2020-DCR-Draft-Report-
Comments-08-24-2020.pdf.
219 Potomac Economics, Comments regarding the Gas Pricing Hubs used in the Net Revenue Analysis for the 2020 Demand Curve Reset (February 26, 2020), available at:
https://www.nyiso.com/documents/20142/14871137/MMU-2020-DCR-Draft-Report-Comments-08-24-
2020.pdf.
220 Id. at 2.
221 See AG, NYISO 2019/2020 ICAP Demand Curve Reset: Continued Modeling Discussions at 21-22 (presented at the March 26, 2020 ICAPWG meeting), available at:
Honorable Kimberly D. Bose November 30, 2020
Page 38
also submitted comments expressly noting that it was continuing to evaluate the Independent
Consultant’s recommendation to use the TGP Zone 4 (200 leg) hub as the gas pricing for Load
Zone C. These comments specifically informed stakeholders that the MMU intended to provide
supplemental analysis and its recommended gas pricing for Load Zone C for consideration as
part of the NYISO staff’s final recommendations.222 On August 24, 2020, the MMU submitted
comments in response to NYISO staff’s draft recommendations. In these comments, the MMU
presented its supplemental analysis regarding the appropriate gas pricing for Load Zone C and
the recommendation to use the Niagara hub for the winter period (i.e., December through
March).223
After consideration of the feedback provided in response to its draft recommendations,
NYISO staff issued its final recommendations on September 9, 2020. At the September 22, 2020
ICAPWG meeting, the NYISO reviewed its final recommendations and highlighted aspects that
differed from the Independent Consultant’s final report and NYISO staff’s draft
recommendations. The NYISO expressly noted the proposed change in gas pricing for Load
Zone C.224 Following issuance of NYISO staff’s final recommendations, stakeholders were also
afforded the opportunity to: (1) submit written feedback to the Board; and (2) present oral
comments to the Board. Stakeholders addressed the NYISO’s proposed gas pricing for Load
Zone C and the use of the Niagara hub in both written and oral comments to the Board. Based
on the foregoing, stakeholders were: (1) notified that the Niagara hub was being evaluated as a
potential candidate for Load Zone C; and (2) afforded the opportunity to present their positions
on this hub during the DCR.
Certain stakeholders also raised concerns regarding the liquidity of trading at the Niagara
hub. These stakeholders contend that level of trading activity raises concerns about its
appropriateness for use in establishing the NYCA ICAP Demand Curve.225 In response to these
concerns, the NYISO conducted supplemental analysis regarding the relative level of trading at
https://www.nyiso.com/documents/20142/11554944/Final%20AG%20DCR%20ICAPWG%2003262020.
pdf.
222 Potomac Economics, MMU Comments on Independent Consultant Initial Draft ICAP Demand
Curve Reset Report and the Forthcoming Draft of NYISO Staff DCR Recommendations at 2 and 11
(August 5, 2020), available at: https://www.nyiso.com/documents/20142/13609298/MMU-2020-DCR-
Draft-Report-Comments.pdf.
223 Potomac Economics, MMU Comments on Independent Consultant Interim Final Draft ICAP
Demand Curve Reset Report and NYISO Staff DCR Draft Recommendations at 2 and 10-15 (August 24,
2020), available at: https://www.nyiso.com/documents/20142/14871137/MMU-2020-DCR-Draft-Report-
Comments-08-24-2020.pdf.
224 NYISO, 2021-2025 ICAP Demand Curve Reset: NYISO Staff Final Recommendations at 7-10 (presented at the September 22, 2020 ICAPWG meeting), available at:
https://www.nyiso.com/documents/20142/15473217/2019-
2020%20NYISO%20Staff%20Final%20Recommendations.pdf.
225 NYISO Affidavit at ¶ 14.
Honorable Kimberly D. Bose November 30, 2020
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the Niagara hub, as well as the availability of gas price data for the Niagara hub.226 To ensure
that the analysis properly aligned with the data proposed for use in the 2021-2025 DCR, the
supplemental analysis utilized data published by SPGMI (i.e., the proposed data vendor for gas
pricing) and focused on the winter period (i.e., December through March) when the hub is
proposed for use.
As shown in the figure below, the NYISO’s supplemental analysis identified that the
trading volumes at the Niagara hub during the winter months for the historical three-year data
period used in determining the 2021/2022 Capability Year ICAP Demand Curves was
comparable and certain instances greater than trading at other gas hubs considered for Load Zone
C (i.e., TGP Zone 4 (200 leg) and Dominion North) or other locations (i.e., Iroquois Zone 2 and
Millennium).227 In addition, the NYISO’s review of gas price data confirmed that SPGMI
published a gas price for the Niagara hub on all days from December through March on which
gas prices were published for the three-year period used in determining the 2021/2022 Capability
Year ICAP Demand Curves (i.e., September 1, 2017 through August 31, 2020).228
Trading Volume Comparison for Various Gas Hubs Considered in the 2021-2025 DCR
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
DecJanFeb Mar DecJanFeb Mar DecJanFeb Mar
2017201820192020
NiagaraIroquois Z2TGP Z4 (200L)Dominion NMillennium
226 Id.
227 Id.
228 Id. Gas price indices, including SPGMI, typically do not publish daily spot gas prices on weekends and holidays.
Honorable Kimberly D. Bose November 30, 2020
Page 40
The NYISO’s supplemental analysis demonstrates that the Niagara hub exhibits sufficient
liquidity and pricing availability to support its use for the winter period (i.e., December through
March).
To appropriately account for the concerns identified by the MMU regarding the
accessibility of gas from TGP Zone 4 (200 leg) to a peaking plant in Load Zone C during the
winter months when availability constraints are most likely to arise, the NYISO proposes to use the Niagara hub as reasonable proxy for gas pricing likely to be experienced by the peaking plant during such winter months. Use of the Niagara hub during the winter months helps to reduce the potential for unnecessarily overestimating potential revenue earnings by a peaking plant in Load Zone C when gas from TGP Zone 4 (200 leg) may not be readily accessible.
2. Load Zone F
The NYISO proposes continued use of the Iroquois Zone 2 hub to represent the
appropriate gas pricing for a peaking plant in Load Zone F.229 The Commission approved use of this same gas hub for Load Zone F for the 2017-2021 DCR.230 Selection of Iroquois Zone 2 reflects strong market dynamics, liquidity, and recognition that various other studies use this hub as a proxy for Load Zone F gas costs.231 Iroquois Zone 2 also represents a geographically
appropriate selection for gas accessible to a peaking plant in Load Zone F.
It is important to note that for the 2021-2025 DCR, the NYISO proposes that a peaking plant located in Load Zone C serve as the basis for the NYCA ICAP Demand Curve.232
3. Load Zone G (Dutchess County)
The NYISO proposes to use the Iroquois Zone 2 hub as the representative gas pricing for
a peaking plant in Load Zone G (Dutchess County).233 The Iroquois Zone 2 hub represents a
reasonably accessible gas source for gas-fired generation located east of the Hudson River. The
hub also represents sufficient liquidity and consistency with electric market pricing dynamics.234
229 NYISO Final Recommendations at 35-36; Independent Consultant Final Report at 95; and AG Affidavit at ¶ 62.
230 2017-2021 DCR Filing at 29; and 2017-2021 DCR Order at P 153.
231 NYISO Final Recommendations at 35-36; and Independent Consultant Final Report at 93, 95
and 97.
232 NYISO Final Recommendations at 59 and Appendix A, p. 13-14; Independent Consultant Final Report at 116; and AG Affidavit at ¶ 25.
233 NYISO Final Recommendations at 35; Independent Consultant Final Report at 95; and AG Affidavit at ¶ 62.
234 NYISO Final Recommendations at 35; and Independent Consultant Final Report at 93, 95 and
97.
Honorable Kimberly D. Bose November 30, 2020
Page 41
The Commission previously approved use of the Iroquois Zone 2 hub for Load Zone G
(Dutchess County) in the 2017-2021 DCR based on consideration of these same factors.235
Notably, for the 2021-2025 DCR, the NYISO proposes that a peaking plant located in
Load Zone G (Rockland County) serve as the basis for the G-J Locality ICAP Demand Curve.236
4. Load Zone G (Rockland County)
The NYISO proposes to refine the approach used for the 2017-2021 DCR by separately evaluating gas hubs for each location evaluated in the lower Hudson Valley.237 The 2017-2021 DCR proposed a single hub to represent Load Zone G rather than separately evaluating gas hubs for Load Zone G (Dutchess County) and Load Zone G (Rockland County).238
The proposal to identify separate hubs for each of the locations evaluated in Load Zone G
better represents the gas pricing dynamics and pipeline system configuration in the lower
Hudson Valley. Separately evaluating the representative gas pricing for Load Zone G (Rockland
County) recognizes that locations west of the Hudson River in the lower Hudson Valley (e.g.,
Rockland County) have ready access to gas pipelines connected to nearby shale gas producing
regions that exhibit different market pricing from locations east of the Hudson River (e.g.,
Dutchess County).
The NYISO proposes use of the TETCO M3 hub as the appropriate proxy for gas pricing likely faced by a peaking plant located in Load Zone G (Rockland County).239 Notably, the use of separate hubs for each location evaluated in Load Zone G is consistent with the approach used in the 2014-2017 DCR. The 2014-2017 DCR also used Iroquois Zone 2 for Load Zone G
(Dutchess County) and TETCO M3 for Load Zone G (Rockland County).240
235 2017-2021 DCR Filing at 29-30; and 2017-2021 DCR Order at P 153-157.
236 NYISO Final Recommendations at 59; Independent Consultant Final Report at 116; and AG
Affidavit at ¶ 25. As further described in Section IV.B.4, certain stakeholders advocate for the use of an
alternative gas hub for Load Zone G (Rockland County). While the NYISO maintains that its proposal to
use TETCO M3 for Load Zone G (Rockland County) is reasonable and appropriate, use of alternative,
higher cost hubs (e.g., Iroquois Zone 2 or Algonquin Citygates) as advocated for by certain stakeholders
would result in a change to the basis for the G-J Locality ICAP Demand Curve for the 2021-2025 DCR.
Either higher priced alternative hub would result in the reference point price for Load Zone G (Rockland
County) exceeding the reference point price for Load Zone G (Dutchess County). As a result, adoption of either such alternative would result in use of Load Zone G (Dutchess County) as the basis for the G-J Locality ICAP Demand Curve. See NYISO Affidavit at ¶ 27.
237 Independent Consultant Final Report at 95.
238 2017-2021 DCR Filing at 29-30; and Independent Consultant Final Report at 95.
239 NYISO Final Recommendations at 35-36 and Appendix A, p. 20-23; Independent Consultant Final Report at 95; AG Affidavit at ¶ 63; and MMU Affidavit at ¶ 24-39.
240 See 2017-2021 DCR Filing at 29, n. 126.
Honorable Kimberly D. Bose November 30, 2020
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Although the TETCO M3 hub is not located within Rockland County, it is geographically
appropriate because of connections to other pipelines (e.g., Millennium and Algonquin) that
could accommodate deliveries of gas from TETCO M3 into Rockland County.241 TETCO M3
also exhibits sufficient liquidity and representation of market dynamics recognizing the gas
pricing differentials that can arise for different locations in the lower Hudson Valley.242
Certain stakeholders contend that the TETCO M3 hub is not an appropriate pricing
representation for Load Zone G (Rockland County) due to pipeline constraints and the potential
for very limited availability of interruptible transportation service to accommodate deliveries
from TETCO M3 into Rockland County. Such stakeholders advocate for use of either the
Iroquois Zone 2 hub or the Algonquin Citygates hub as the appropriate proxy for gas pricing in
Load Zone G (Rockland County).243 In response to these concerns, the MMU conducted a
supplemental analysis to evaluate the historical availability of capacity on the Algonquin pipeline
to facilitate deliveries from TETCO M3 into Rockland County.244 The MMU’s analysis
identified that: (1) sufficient transportation capacity is generally available throughout the year to
accommodate deliveries on the Algonquin pipeline into Rockland County; (2) the constraints
most likely to arise on Algonquin occur downstream of the portions of the pipeline that would
serve to deliver gas into Rockland County; and (3) the use of an alternative gas hub, such as the
Iroquois Zone 2 hub, would not provide a reasonable estimate of the likely expected revenue
earnings of a peaking plant in Load Zone G (Rockland County).245
Stakeholders opposing the use of the TETCO M3 hub further contend that the MMU’s
supplemental analysis does not appropriately account for the actual availability of interruptible
service on the Algonquin pipeline to accommodate deliveries into Rockland County. These
stakeholders contend that very limited interruptible service is available on the Algonquin
pipeline based on evaluations of additional nomination cycle information that includes further
nominations of firm service that would take priority over interruptible service. These arguments
appear to: (1) misunderstand the purpose of the MMU’s analysis; and (2) inaccurately assume
that the DCR requires the peaking plant to rely solely on the use of interruptible transmission
service.
As previously noted, the DCR does not assume that a peaking plant utilizes any particular
gas supply arrangement. Rather, the assessment of the appropriate proxy gas pricing for each
location recognizes that a peaking plant has a variety of options for securing natural gas. One
such option may be sole reliance on the availability of interruptible service. However, this is not
the only option that may be available. In fact, a peaking plant may reasonably pursue other
241 NYISO Final Recommendations at 35 and Appendix A, p. 20; AG Affidavit at ¶ 63; and MMU Affidavit at ¶ 25-34.
242 Independent Consultant Final Report at 93, 95 and 97; and AG Affidavit at ¶ 63. 243 NYISO Affidavit at ¶ 27.
244 NYISO Final Recommendations at 35 and Appendix A, p. 20-23; and MMU Affidavit at ¶ 26-
37.
245 NYISO Final Recommendations at Appendix A, p. 20-23; and MMU Affidavit at ¶ 26-39.
Honorable Kimberly D. Bose November 30, 2020
Page 43
arrangements to obtain gas supply, including acquisition of secondary transportation service through arrangements with gas marketers or other entities that may have already secured firm transportation and have unused portions of such rights available at various times.246
The MMU’s assessment of pipeline capacity utilization more appropriately accounts for
the potential availability of capability to accommodate gas deliveries to a peaking plant rather
than solely focusing on a single gas supply procurement option (i.e., interruptible service).247 As demonstrated by the MMU’s analysis, pipeline capacity remains available at most times to
accommodate the delivery of gas from the TETCO M3 hub to Rockland County. Therefore, use of the TETCO M3 hub as the representative gas pricing for Load Zone G (Rockland County) is
appropriate and reasonable.248
5. NYC
The NYISO proposes to retain use of the Transco Zone 6 NY hub as the appropriate
proxy for gas pricing in NYC.249 The Commission approved the use of this same hub for NYC in the 2017-2021 DCR.250 The selection of Transco Zone 6 NY recognizes that it is the
geographically appropriate hub. The hub exhibits strong liquidity and consistency with electric market dynamics in Load Zone J, and is widely used as the appropriate proxy for NYC gas
pricing across various studies.251
6. LI
The NYISO proposes to use the Iroquois Zone 2 hub as the appropriate proxy for gas
pricing on Long Island.252 The Iroquois Zone 2 hub reflects a geographically appropriate
selection of gas supply available to a peaking plant on LI.253 The hub is a sufficiently liquid
246 MMU Affidavit at ¶ 27-30.
247 MMU Affidavit at ¶ 26-39.
248 During those very limited periods when gas constraints may make gas procured at TETCO M3
uneconomic or unavailable, the NYISO’s proposal to include dual fuel capability as part of the peaking
plant design provides a readily available alternative fuel option to accommodate operation during such
periods. See NYISO Final Recommendations at Appendix A, p. 20; and MMU Affidavit at ¶ 33.
249 NYISO Final Recommendations at 36; Independent Consultant Final Report at 95; and AG Affidavit at ¶ 61.
250 2017-2021 DCR Filing at 29; and 2017-2021 DCR Order at P 153.
251 NYISO Final Recommendations at 36; Independent Consultant Final Report at 94-95 and 98; and AG Affidavit at ¶ 61.
252 NYISO Final Recommendations at 35-36; Independent Consultant Final Report at 95; and AG Affidavit at ¶ 62.
253 NYISO Final Recommendations at 35-36; and Independent Consultant Final Report at 98.
Honorable Kimberly D. Bose November 30, 2020
Page 44
pricing location that exhibits appropriate consistency with electric market pricing for Load Zone
K.254
C. Level of Excess Adjustments
The Services Tariff mandates that net EAS revenue estimates for each peaking plant
reflect the tariff-prescribed level of excess conditions.255 Consistent with the methodology
approved by the Commission for the 2014-2017 DCR and the 2017-2021 DCR, the NYISO
proposes to account for this requirement by using level of excess adjustment factors (“LOE-
AFs”).256 The net EAS Model multiplies historical energy and reserve prices by the relevant
LOE-AF values to approximate market outcomes under the tariff-prescribed level of excess
conditions.257
The LOE-AF values are determined using production cost modeling simulations to
determine projected LBMPs based on current (or “as found”) system conditions and LBMPs
under system conditions that reflect the tariff-prescribed level of excess conditions.258 The LOEAF values are determined by dividing the projected LBMPs under the tariff-prescribed level of excess conditions by the projected LBMPs under “as found” system conditions.259
Consistent with the methodology used for the 2017-2021 DCR, GE Consulting conducted
the production cost modeling using its Multi Area Production Simulation (“GE-MAPS”)
software program. The relevant LBMPs for each case were determined for the calendar years
related to this reset (i.e., 2021-2025) using the 2019 Congestion Assessment Resource
Integration Study (“CARIS”) Phase 1 base case dataset. In response to stakeholder feedback, the
NYISO adjusted the dataset to reflect: (1) changes to certain resource additions and retirements;
and (2) updated peak load forecast values based on the data set forth in the 2020 Load &
Capacity Data report.260
Certain stakeholders contend that the NYISO should also revise the 2019 CARIS Phase 1
dataset to reflect the potential impacts of the NYSDEC Peaker Rule. As further described in
Section III.C above, the new regulation, which phases in compliance obligations between 2023
254 NYISO Final Recommendations at 35-36; Independent Consultant Final Report at 94 and 98; and AG Affidavit at ¶ 62.
255 Services Tariff §§ 5.14.1.2.2 and 5.14.1.2.2.2; and NYISO Affidavit at ¶ 15.
256 2014-2017 DCR Filing at 28; 2014-2017 DCR Order at P 2 and 165; 2017-2021 DCR Filing at 34-35; and 2017-2021 DCR Order at P 163.
257 NYISO Final Recommendations at 43-45; NYISO Affidavit at ¶ 16-17; Independent Consultant Final Report at 100-101 and Appendix C; and AG Affidavit at ¶ 48-49.
258 NYISO Final Recommendations at 43-44; NYISO Affidavit at ¶ 17; Independent Consultant Final Report at 100-101; and AG Affidavit at ¶ 49.
259 Id.
260 NYISO Final Recommendations at 43-44; and NYISO Affidavit at ¶ 17-18.
Honorable Kimberly D. Bose November 30, 2020
Page 45
and 2025, affects approximately 3,300 MW of simple-cycle turbines located primarily in the
lower Hudson Valley, NYC, and LI. The rule required affected generators to submit compliance plans to the NYSDEC in March 2020. Based on the compliance plans, the NYISO expects that by May 1, 2025 approximately 1,800 MW of nameplate capacity could be unavailable to operate during the summer in order to comply with the rule’s emissions requirements.
The NYISO does not recommend adjusting the 2019 CARIS Phase 1 dataset based on the
recently submitted compliance plans for purposes of calculating LOE-AF values for the 2021-
2025 DCR.261 Incorporating the potential resource impacts reflected in the compliance plans is
likely to produce LOE-AF values that do not accurately reflect the anticipated system conditions
throughout the historical data periods used in developing the ICAP Demand Curves. For each
Capability Year, the net EAS revenue offset values used in determining the ICAP Demand
Curves reflects the most recent three years of historical data.262 For the 2021-2025 DCR, only a small portion of the data used in developing the ICAP Demand Curves for the last Capability Year (i.e., the 2024/2025 Capability Year) covered by this reset period would reflect the
potential impacts to resource availability due to the NYSDEC Peaker Rule. For the 2024/2025 Capability Year ICAP Demand Curve, only 4 months (i.e., May through August 2023) of the 36 months used would reflect expected resource unavailability resulting from the initial
implementation of the emissions requirements imposed by the NYSDEC Peaker Rule.263
Developing LOE-AF values based on potential system conditions that may exist during only 4 months of the historical dataset to be used over the course of the entire reset period would not properly reflect the system conditions expected over this period.
It is also unclear whether simply modeling the resource impacts reflected in the
compliance plans would be an accurate reflection of expected system conditions beginning on
May 1, 2023.264 The ongoing 2020 Reliability Needs Assessment (“RNA”) has identified certain
resource adequacy and transmission security violations that, in part, reflect the potential impacts
on resource availability based on the compliance plans submitted in response to the NYSDEC
Peaker Rule.265 Potential solutions to the identified reliability concerns have not yet been
determined and could ultimately affect the expected future system conditions.266 Notably, there
261 NYISO Final Recommendations at 44-45 and Appendix A, p. 11-13; and NYISO Affidavit at
¶ 18-21.
262 Services Tariff § 5.14.1.2.2.2.
263 NYISO Final Recommendations at 45 and Appendix A, p. 12-13; and NYISO Affidavit at ¶
20-21.
264 NYISO Final Recommendations at 44-45 and Appendix A, p. 12; and NYISO Affidavit at ¶
19-20.
265 See NYISO Affidavit at ¶ 20; and NYISO, 2020 RNA Report at 17, 21 and 23-25 (presented at the October 28, 2020 Management Committee meeting), available at:
https://www.nyiso.com/documents/20142/16333532/06%202020%20RNA%20Presentation.pdf.
266 See NYISO Affidavit at ¶ 20; and 2020 RNA Report at 35 (presented at the October 28, 2020 Management Committee meeting), available at:
https://www.nyiso.com/documents/20142/16333532/06%202020%20RNA%20Presentation.pdf.
Honorable Kimberly D. Bose November 30, 2020
Page 46
are also projects currently proceeding through the NYISO’s interconnection process that could serve to replace capacity of the affected generators.267 In addition, the NYSDEC Peaker Rule includes allowance for an affected resource to remain in service temporarily beyond the specified compliance deadlines if the resource is needed to avoid a reliability issue pending the
implementation of a permanent solution to such reliability need.268
Based on these considerations, the NYISO’s proposal to exclude the potential impacts of
the compliance plans submitted in response to the NYSDEC Peaker Rule from the modeling
assumptions used for determining LOE-AF values is reasonable and appropriate for the 2021-
2025 DCR.
D. Use of Historical Market Data
Certain stakeholders contend that the ICAP Demand Curves for the 2021-2025 DCR
should exclude historical data from the 12-month period of September 1, 2019 through August 31, 2020. These stakeholders advocate for eliminating the use of data from this period due to the energy market impacts of the ongoing COVID-19 pandemic.
The Services Tariff does not provide the NYISO authority to discard historical data
periods required to be used in developing the ICAP Demand Curves. Specifically, Section
5.14.1.2.2.2 mandates the that the NYISO determine the estimated energy market revenues
earnings for each peaking plant using the most recent three years of data for the period ending
August 31st of the calendar year immediately prior to the date on which the ICAP Demand
Curves become effective. For purposes of the 2021/2022 Capability Year, this provision
requires use of historical data for the period from September 1, 2017 through August 31, 2020.
Similarly, the provision also mandates use of data from the September 1, 2019 through August
31, 2020 period in determining the ICAP Demand Curves for 2022/2023 and 2023/2024
Capability Years.269
In addition, excluding certain data periods undermines the purpose of implementing the
historical method for estimating potential market revenue earnings by each peaking plant.270 The
implementation of a historical methodology was designed to improve transparency,
predictability, and reflect the impacts of actual market conditions in estimating the potential
energy market revenue earnings for each peaking plant. The impacts of the ongoing COVID-19
267 These projects did not meet the necessary requirements for inclusion in the 2020 RNA base case. See NYISO Affidavit at ¶ 20.
268 See 6 NYCRR Part 227-3.6; and NYISO Affidavit at ¶ 20.
269 The applicable historical data period used in determining the 2022/2023 Capability Year ICAP
Demand Curves is September 1, 2018 through August 31, 2021. The 2023/2024 Capability Year ICAP
Demand Curves require use of historical data for the period from September 1, 2019 through August 31,
2022.
270 See NYISO Final Recommendations at 45-46; DCR Process Enhancements Filing at 5-7; and DCR Process Enhancements Order at P 16.
Honorable Kimberly D. Bose November 30, 2020
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pandemic on energy market outcomes are actual events that should be reflected in the data used for establishing the ICAP Demand Curves. Other events, such as severe cold weather events and heat waves, can have material impacts on market outcomes. It is important to recognize that these types of events have occurred in the past and been incorporated in the estimated revenue earnings for peaking plants (e.g., the polar vortex during the 2013-2014 winter, and the bomb cyclone and extended Northeast cold snap during the 2017-2018 winter).
The NYISO and stakeholders explicitly considered the potential for relatively short
duration conditions to impact market outcomes and projections of potential revenue earnings.
The requirement to develop estimated revenue earnings using three years of historical data was
specifically designed to help mitigate the potential for undue impacts from short duration
events.271 Developing these estimates using three years of data aids in reducing the impacts of
shorter-term market fluctuations that may otherwise unnecessarily influence the resulting
projections.
V.ICAP Demand Curve Parameters
The key parameters necessary for establishing the ICAP Demand Curves are: (i) the
maximum allowable price of capacity; (ii) the reference point price; and (iii) the point at which the price of capacity declines to zero (commonly referred to as the zero-crossing point).
A. Levelized Fixed Charge and Financial Parameters
The Services Tariff requires that the DCR assess “the current localized levelized
embedded cost of a peaking plant” for each ICAP Demand Curve.272 This requires the
translation of the estimated up-front capital investment costs for each peaking plant, including
property tax and insurance, into an annualized level. Among other factors, such as depreciation,
this translation accounts for: (i) the assumed weighted average cost of capital (“WACC”)
required by a developer of the peaking plant to recover its up-front investments costs, plus a
reasonable return on that investment; (ii) the term in years over which the developer is assumed
to recover its up-front investment costs (commonly referred to as the “amortization period”); and
(iii) the applicable tax rates.273 The WACC is derived from a series of financial parameters
related to the development of the peaking plant, including the required return on equity (“ROE”),
the cost of debt (“COD”), and the capital structure for the project (as reflected in the ratio of debt
to equity [“D/E ratio”]).
The Independent Consultant developed the parameters necessary to translate the up-front
investment costs of the peaking plant for each ICAP Demand Curve into an annualized level
based on an assessment of relevant data and information, as well as its reasoned judgment and
271 DCR Process Enhancements Filing at 7.
272 Services Tariff § 5.14.1.2.2.
273 NYISO Final Recommendations at 25-29; Independent Consultant Final Report at 60-74; and AG Affidavit at ¶ 65.
Honorable Kimberly D. Bose November 30, 2020
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experience.274 The Independent Consultant designed the parameters to reflect the particular financial risks faced by a developer given the nature of the peaking plant and the New York electricity market context.275 The Independent Consultant selected the parameters in an integrated fashion due to the interrelationship of the various parameters.276
The NYISO proposes to adopt the parameter values recommended by the Independent Consultant.277 The Independent Consultant’s recommended WACC is 9.54%.278 The
Independent Consultant calculated the recommended WACC based on the following
assumptions: (1) ROE of 13%; (2) COD of 6.7%; and (3) D/E ratio of 55/45.279
1. Return on Equity
The NYISO proposes to adopt the Independent Consultant’s recommended ROE of
13%.280 The Independent Consultant determined the proposed ROE based consideration of
various data sources reflecting different potential financing structures for developing a new
peaking plant.
The Independent Consultant utilized these various data sources to identify a range of
potential ROE values. The data sources included ROE values for publicly traded independent
power producers (“IPPs”) based on the capital asset pricing model (“CAPM”). This analysis
identified ROE values ranging up to 10.5%.281 The asset portfolios of the companies evaluated
include regulated utilities and generation assets, as well as power generation projects with multi-
year power purchase agreements.282 Accordingly, the ROE values for these companies may not
fully account for the risk of developing a new peaking plant in New York. Therefore, the
Independent Consultant expanded its analysis to consider data and information regarding
potential ROE values required to support a stand-alone project finance approach to developing a
new peaking plant in New York. The additional information identified ROE values for a stand-
alone project finance structure ranging from approximately 12% to 20%.283 Lastly, the
274 Independent Consultant Final Report at 60-61; and AG Affidavit at ¶ 65-67.
275 Id.
276 Id.
277 NYISO Final Recommendations at 25-29.
278 NYISO Final Recommendations at 25; Independent Consultant Final Report at 70-71; and AG Affidavit at ¶ 25, 70-73 and 79-82.
279 NYISO Final Recommendations at 25; Independent Consultant Final Report at 63-71; and AG Affidavit at ¶ 25, 65-67 and 70-82.
280 NYISO Final Recommendations at 26; Independent Consultant Final Report at 67-69; and AG Affidavit at ¶ 70-73 and 76-77.
281 Independent Consultant Final Report at 67-68; and AG Affidavit at ¶ 76.
282 Id.
283 Independent Consultant Final Report at 68; and AG Affidavit at ¶ 76.
Honorable Kimberly D. Bose November 30, 2020
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Independent Consultant considered ROE values recently approved by the Commission as part of
similar capacity market valuations in neighboring markets. These values ranged from 12.8% to
13.8%.284
Certain stakeholders advocate for use of a higher ROE value contending that the
recommended ROE does not appropriately account for the risks of merchant generation
investment in New York. Other stakeholders contend that the recommended ROE value is
inflated based on consideration of typical ROEs for regulated utilities and a reasonable adder to such values to account for the additional risk attributable to merchant development.
The recommended value reflects a balance between the lower bound of the values
observed for IPPs and the higher end of the range observed for stand-alone project finance
values.285 As a result, the recommended 13% value provides for a reasonable and appropriate balancing of the range of ROE values observed.
2. Cost of Debt
The Independent Consultant recommended use of a 6.7% COD.286 The NYISO proposes to adopt this recommendation as a reasonable and appropriate value based on the analysis
conducted by the Independent Consultant.287
Certain stakeholders advocate for a higher COD value contending that the recommended value does not adequately account for the risk of investment in a new gas-fired generator in New York. These stakeholders also contend that the recommended value does not account for the cost of hedging instruments that a developer would likely be required to execute to obtain financing. Other stakeholders, including the MMU, recommend use of a lower COD value based on
consideration of recent market data.
The Independent Consultant based its recommended value on market data regarding the
debt cost for generic B-rated corporate debt, as well as consideration of debt costs incurred by
certain IPPs over the past three years.288 The COVID-19 pandemic has created significant
volatility in the financial markets. This volatility has resulted in significant changes in the cost
debt over the past year. For example, the debt costs for B-rated firms rose to more than 12% in
March 2020 before declining to approximately 6.6% in July 2020 when the Independent
Consultant finalized its recommendations.289 The Independent Consultant recognized that the
debt costs could potentially decline further as the financial markets continue to adjust to the
284 Independent Consultant Final Report at 68.
285 Independent Consultant Final Report at 67-69; and AG Affidavit at ¶ 76-77. 286 Independent Consultant Final Report at 65-67; and AG Affidavit at ¶ 70-75. 287 NYISO Final Recommendations at 26.
288 Independent Consultant Final Report at 65-67; and AG Affidavit at ¶ 74-75.
289 Independent Consultant Final Report at 65 and 67; and AG Affidavit at ¶ 75.
Honorable Kimberly D. Bose November 30, 2020
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ongoing pandemic. In fact, the Independent Consultant has noted that the current debt cost for generic B-rated corporate debt is approximately 5.7%.290
The Independent Consultant also considered available information regarding debt costs incurred by certain publicly traded IPPs. The available information identified a range of debt costs from approximately 4% to 8%.291
Based on consideration of the range of COD values that may be appropriate, the
Independent Consultant ultimately selected that recommended value of 6.7%.292 The
Independent Consultant’s recommendation to use a value slightly above current market values for generic B-rated corporate debt includes consideration of many factors. These considerations include the risk profile for developing a new peaking plant in New York, potential financing
approaches including the non-recourse nature of stand-alone project finance debt, and an implicit consideration of costs that may be incurred to secure financing for a new peaking plant in New York such as the execution of hedges.293
3. Debt-to-Equity Ratio
The NYISO proposes to adopt the Independent Consultant’s recommended D/E ratio of 55/45 for the 2021-2025 DCR.294 This is the same D/E ratio approved by the Commission for the 2017-2021 DCR.295
The recommended D/E ratio recognizes that the appropriate capital structure for a project can vary depending on consideration of several factors, including the nature and certainty of
expected project revenue streams, the structure of a project’s financing, and the nature of the
capital supporting investment in the project.296 The recommendation considered various
potential capital structures that could reasonably support the development of a new peaking plant in New York. The data and information assessed by the Independent Consultant included
corporate level capital structures for certain IPPs, assumptions of capital structure used in other studies and evaluations, and consideration of the relative cost of debt.297 This information
identified D/E ratios ranging from 30/70 to 65/35.
290 AG Affidavit at ¶ 75.
291 Independent Consultant Final Report at 65-66; and AG Affidavit at ¶ 75.
292 Independent Consultant Final Report at 65; and AG Affidavit at ¶ 75.
293 NYISO Final Recommendations at 26-27; Independent Consultant Final Report at 65-67; and AG Affidavit at ¶ 75.
294 NYISO Final Recommendations at 26; Independent Consultant Final Report at 69-70; and AG Affidavit at ¶ 25 and 78.
295 2017-2021 DCR Filing at 36-38; and 2017-2021 DCR Order at P 179 and 181.
296 Independent Consultant Final Report at 69; and AG Affidavit at ¶ 78.
297 Independent Consultant Final Report at 69-70; and AG Affidavit at ¶ 78.
Honorable Kimberly D. Bose November 30, 2020
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The Independent Consultant’s recommended 55/45 D/E ratio represents a reasonable
balancing of various considerations as informed by the range of potential capital structures
observed. The recommended value acknowledges the generally observed trend toward lower debt leverage at the corporate level by IPPs, and the relative lack of longer-term certain revenue streams for a new merchant peaking plant that primarily derives revenues through participation in competitive wholesale markets.298
4. Amortization Period
The amortization period represents the term (in years) over which a merchant investor
expects to recover its upfront capital costs to develop a new peaking plant in New York, together with a reasonable return on such investment. The NYISO proposes to adopt the 17-year
amortization period recommended by the Independent Consultant for the peaking plants
proposed herein.299
The recommended amortization period reflects a reduction from the 20-year amortization period approved by the Commission for the 2017-2021 DCR.300 A primary consideration for
using a 17-year amortization period is the recent enactment of the Climate Leadership and
Community Protection Act (“CLCPA”).301 The CLCPA requires electricity demand in New
York be served by 100% zero-emission resources by January 1, 2040. The proposed 17-year
amortization period represents the average period of years between the beginning of each
Capability Year encompassed by the 2021-2025 DCR and the January 1, 2040 zero-emission
deadline established in the CLCPA.302
The Independent Consultant and the NYISO carefully considered divergent stakeholder feedback regarding the appropriate means for addressing the CLCPA’s rules regarding fossil fuel use for electricity generation beyond 2040.303 Certain stakeholders recommended a 15-year
amortization period reflecting the fact that new generation projects currently under consideration in New York would be unlikely to enter into service until the later portion of the 2021-2025 reset period. Other stakeholders, including the MMU, recommended retaining a 20-year amortization period in light of the potential for fossil units to undertake future retrofitting or other
modifications to convert to alternative zero-emission fuels or otherwise operate on a zero-
emission basis in compliance with the CLCPA.
298 NYISO Final Recommendations at 26; Independent Consultant Final Report at 69-70; and AG Affidavit at ¶ 78.
299 NYISO Final Recommendations at 27-29; Independent Consultant Final Report at 61-63; and AG Affidavit at ¶ 25 and 68-69.
300 2017-2021 DCR Filing at 36-38; and 2017-2021 DCR Order at P 179.
301 Chapter 106 of the Laws of the State of New York of 2019; and AG Affidavit at ¶ 69.
302 NYISO Final Recommendations at 27-28; Independent Consultant Final Report at 62; and AG Affidavit at ¶ 69.
303 NYISO Affidavit at ¶ 28.
Honorable Kimberly D. Bose November 30, 2020
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The proposed amortization period does not reflect any supposition that all existing fossil-
fired generation will cease operation as of January 1, 2040. Likewise, the proposed 17-year
amortization period does not presume that potential retrofitting options will be unavailable or not
pursued if economically rational. Rather, the NYISO recognizes that achievement of the
CLCPA’s zero-emission generation requirement in a manner that balances the ultimate costs to
consumers and maintaining reliability will require evolution of the resource mix to include
flexible assets capable of operating in compliance with the CLCPA’s zero-emission requirement.
Consistent with Commission precedent, however, the NYISO must consider the current
state of the CLCPA and regulatory constructs developed to implement its requirements. The
Commission has consistently held that determinations in each DCR must take account of laws
and regulations as currently effective and avoid speculation as to potential future changes in such laws and regulations.304
Although the CLCPA establishes the requirement to transition to zero-emission electric
supply by January 1, 2040, it does not does not define eligibility for compliance with this
requirement. Instead, the CLCPA requires development and refinement of the regulations and
program rules for achieving the 2040 zero-emission requirement over the coming years. At this
time, New York has not implemented rules or regulations to specifically define the resource
types, fuels, or retrofitting options eligible for operation in compliance with the 2040 zero-
emission requirement. As a result, there is currently no basis upon which to assume potential
retrofitting or fuel conversion to achieve compliance with the requirements of the CLCPA
beginning in 2040.305
Given the absence of eligibility rules at present, assuming fuel conversion options,
retrofits, or other modifications to permit a fossil-fired generator, such as the peaking plants
proposed herein, to operate as a zero-emission resource beginning in 2040 would require the
NYISO to speculate what may in the future be defined as compliant with the requirements of the CLCPA.306 Reliance on such speculation would directly contradict the Commission’s prior
mandates regarding allowable considerations during each DCR.
Consideration of the potential timeframe for market entry of current projects under
consideration in New York likewise does not undermine the proposed 17-year amortization
period. The peaking plant used in establishing the ICAP Demand Curves is a hypothetical
resource. The DCR implicitly requires that this hypothetical resource be in-service as of May 1, 2021 in order to establish the ICAP Demand Curves for the first Capability Year covered by the 2021-2025 DCR (i.e., the 2021/2022 Capability Year).
304 See, e.g., 2017-2021 DCR Order at P 61; and 2014-2017 DCR Order at P 74.
305 NYISO Final Recommendations at 28; Independent Consultant Final Report at 61-62; and AG Affidavit at ¶ 69.
306 AG Affidavit at ¶ 69.
Honorable Kimberly D. Bose November 30, 2020
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Based on the consideration of all these factors, the use of a 17-year amortization period for the peaking plants proposed herein is appropriate and reasonable for the 2021-2025 DCR. As additional data and information becomes available over the coming years regarding resources, technologies, and fuels eligible for operation in compliance with the CLCPA’s zero-emission requirement for 2040, the NYISO will consider such information in future resets.307
B. Reference Point Price
The reference point price is determined, in part, by subtracting the relevant net EAS
revenue estimate for a peaking plant from the levelized embedded cost value of the same plant.
The resulting value is commonly referred to as the “net cost of new entry” or “Net CONE.” The
NYISO uses the ICAP Demand Curves in the monthly ICAP Spot Market Auctions. Therefore,
the NYISO must translate the annual Net CONE values into monthly values for use in the
auctions.
As required by the Services Tariff, the NYISO calculated the resulting reference point prices for each ICAP Demand Curve for the 2021/2022 Capability Year.308 These calculations account for the requirements that the reference point prices: (1) reflect the tariff-prescribed level of excess conditions; and (2) account for seasonal differences in capacity availability (commonly referred to as the winter-to-summer ratio or “WSR”).309
The resulting calculations for the 2021/2022 Capability Year are contained in a
spreadsheet developed by the Independent Consultant and posted on the NYISO’s website (the spreadsheet is commonly referred to as the “Demand Curve Model”).310 This spreadsheet
includes the data inputs and calculations necessary to determine: (1) the levelized annual cost to construct each peaking plant; (2) the annual Net CONE value for each peaking plant; and (3)
translation of the annual Net CONE value for each peaking plant into a monthly reference point price. The NYISO will use the spreadsheet model to perform these calculations as part of the
tariff-prescribed annual updates to determine the ICAP Demands Curves for the 2022/2023
through 2024/2025 Capability Years.
307 NYISO Final Recommendations at 28.
308 NYISO Final Recommendations at 46-53.
309 See Services Tariff §§ 5.14.1.2.2 and 5.14.1.2.2.3; and NYISO Installed Capacity Manual §
5.5. The WSR accounts for the fact that differences in capacity availability during the Summer Capability
Period and Winter Capability Period contribute to differences in capacity prices throughout the year. To
provide for revenue adequacy for the peaking plant when market entry is needed to maintain the
applicable minimum capacity requirements, the NYISO uses the WSR to account for these seasonal
differences.
310 The Demand Curve Model related to the NYISO’s proposal is an excel file titled “Demand
Curve Model - 2020.10.21 (NYISO Staff Final Recommendations Updated 2021-2022 GDP)” available
at: https://www.nyiso.com/installed-capacity-market. From this page, the model can be obtained by
navigating through the following content sections: “Reference Documents”“2021-2025 Demand Curve Reset”“Final Models and Materials.”
Honorable Kimberly D. Bose November 30, 2020
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C. Maximum Clearing Price
The Services Tariff establishes the maximum allowable price of capacity for each ICAP Demand Curve at a value equal to 1.5 multiplied by the localized levelized embedded cost of each peaking plant (as translated into a monthly value).311 The NYISO proposes enhancements to the methodology for translating the annual levelized embedded cost value for each peaking plant to a monthly value.312
The NYISO’s proposed enhancements are intended to provide for improved consistency with the translation of the annual Net CONE values to monthly values. To provide for improved alignment, the NYISO proposes to account for: (1) the tariff-prescribed level of excess
conditions; and (2) the applicable WSR values when translating the annual levelized embedded cost value for each peaking plant to a monthly value.313
D. Zero-Crossing Point
The NYISO proposes to retain the current zero-crossing point values for the 2021-2025
DCR.314 The current zero-crossing point values are as follows: (1) 112% of the applicable
minimum capacity requirement for the NYCA ICAP Demand Curve; (2) 115% of the applicable
minimum capacity requirement for the G-J Locality ICAP Demand Curve; (3) 118% of the
applicable minimum capacity requirement for the NYC ICAP Demand Curve; and (4) 118% of
the applicable minimum capacity requirement for the LI ICAP Demand Curve.315
VI.Annual Updates
The Services Tariff requires that each DCR develop: (1) the proposed ICAP Demand
Curves for the first Capability Year covered by the reset period; and (2) the methodologies,
inputs, and assumptions used in determining the ICAP Demand Curves for the remaining three
Capability Years covered by the reset period pursuant to the tariff-prescribed annual update
procedures.316
The annual update process consists of updates to the following parameters each year: (i)
adjusting the levelized localized embedded cost of the peaking plant for each ICAP Demand
311 Services Tariff §§ 5.14.1.2 and 5.14.1.2.2.3; and NYISO Affidavit at ¶ 22.
312 NYISO Final Recommendations at 5 and 47; and NYISO Affidavit at ¶ 22-23.
313 Id.
314 See Services Tariff § 5.14.1.2.2; NYISO Final Recommendations at 51; and Independent Consultant Final Report at 109.
315 See NYISO Final Recommendations at 51; 2017-2021 DCR Filing at 39-40; and 2017-2021 DCR Order at P 17, n. 27.
316 See Services Tariff § 5.14.1.2.2; DCR Process Enhancement Filing at 9-16; and DCR Process Enhancements Order at P 27 and 29-30.
Honorable Kimberly D. Bose November 30, 2020
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Curve based on a composite escalation factor;317 (ii) determining new net EAS revenue estimates
for each peaking plant using updated variable cost and market price information;318 (iii)
determining updated WSR values;319 and (iv) determining the revised values of the ICAP
Demand Curves utilizing the updated values described above.320 The Services Tariff requires
that the NYISO post the results of annual updates to its website on or before November 30th of
the calendar year prior to the commencement of the Capability Year for which the updated ICAP
Demand Curves apply.321
A. Annual Update of Peaking Plant Costs
The levelized localized embedded cost of each peaking plant is updated annually using a
statewide, technology specific composite escalation factor.322 The composite escalation factor
measures the cost-weighted average change over time of certain inflation indices that relate to
the costs of building a peaking plant. The costs of each peaking plant are broken down into the
following four components to derive the technology specific weighting factors applicable to each
component: (1) changes in construction material costs (“materials component”); (2) changes in
turbine generator costs (“turbine component”); (3) changes in labor costs (“labor component”);
and (4) changes in the general cost of goods and services (“general component”).
For the 2021-2025 DCR, the NYISO essentially proposes the use of two different
technologies to serve as the peaking plant. For the NYCA ICAP Demand Curve, the NYISO
proposes use of the alternative GE 7HA.02 model that is tuned to emit 15 ppmv of NOx at 15% O2 (“GE 7HA.02 (15 ppm)”). For the G-J Locality, NYC, and LI ICAP Demand Curves, the NYISO proposes use of the standard GE 7HA.02 model that is tuned to emit 25 ppmv of NOx at 15% O2 (“GE 7HA.02 (25 ppm)”). The NYISO will calculate a separate composite escalation factor using differing component weighting factors for each technology.
The table below identifies the proposed data sources and weighting factors for each technology.323
317 Services Tariff § 5.14.1.2.2.1.
318 Services Tariff § 5.14.1.2.2.2.
319 Services Tariff § 5.14.1.2.2.3.
320 Id.
321 Services Tariff § 5.14.1.2.2. For example, the updated ICAP Demand Curves for the
2022/2023 Capability Year will be posted to the NYISO’s website on or before November 30, 2021.
322 See Services Tariff § 5.14.1.2.2.1; and Docket No. ER20-1049-000, New York Independent System Operator, Inc., Proposed Enhancements to the ICAP Demand Curve Annual Update Procedures (February 21, 2020); and Docket No. ER20-1049-000, supra, Letter Order (April 3, 2020).
323 NYISO Final Recommendations at 54-56; and Independent Consultant Final Report at 122-
124.
Honorable Kimberly D. Bose November 30, 2020
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Weighting Factor
Cost
Component
Index Value
DataGE 7HA.02GE 7HA.02
Interval (25 ppm) (15 ppm)
BLS Quarterly Census of Employment
and Wages, New York - Statewide,
Labor
Materials
Turbine
General
NAICS 2371 Utility System
Construction, Private, All
Establishment Sizes, Average Annual
Pay
BLS Producer Price Index for
Commodities, Not Seasonally Adjusted,
Intermediate Demand by Commodity
Type (ID6), Materials and Components
for Construction (12)
BLS Producer Price Index for
Commodities, Not Seasonally Adjusted,
Machinery and Equipment (11),
Turbines and Turbine Generator Sets
(97)
Bureau of Economic Analysis: Gross
Domestic Product Implicit Price
Deflator, Index 2009 = 100, Seasonally
Adjusted
Annually27%24%
Monthly23%19%
Monthly26%32%
Quarterly24%25%
Section 5.14.1.2.2.4.11 of the Services Tariff requires that the NYISO calculate and
report the most recent, unweighted 12-month percentage change for the general component. This value is relevant for certain aspects of the NYISO’s buyer-side Installed Capacity market mitigation measures. The 12-month percentage change in the general component using finalized data published by the applicable index as of October 1, 2020 is 0.55%.
B. Annual Update of Net EAS Revenue Projections
The NYISO refreshes the net EAS revenue projections for each peaking plant as part of the annual update process. The Services Tariff requires that the NYISO utilize the same Net EAS Model used to determine the net EAS revenue projections for the 2021/2022 Capability Year, updating the model to replace the oldest twelve month period in the underlying dataset with the most recent twelve month period ending in August.324
324 Services Tariff § 5.14.1.2.2.2. For example, for the annual update to determine ICAP Demand Curve values for the 2022/2023 Capability Year, the net EAS revenue projection will be based on cost and pricing data for the period from September 1, 2018 through August 31, 2021.
Honorable Kimberly D. Bose November 30, 2020
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The table below summarizes the proposed data inputs and assumptions for the 2021-2025
DCR.325
Data Input Value/Source
Factor
Net EAS Model
NYCAG-J LocalityNYCLI
The Net EAS Model is contained within a zip folder titled “2020-09-
09-Report Final Fossil Model” available at:
https://www.nyiso.com/installed-capacity-market. From this page, the model can be obtained by navigating through the following content sections: “Reference Documents”“2021-2025 Demand Curve
Reset”“Final Models and Materials”
Peaking Plant
SCR Emissions Control Technology
Location
GE 7HA.02GE 7HA.02
(15 ppm)(25 ppm)
NoYes
Load Zone G
Load Zone C(Rockland
County)
GE 7HA.02GE 7HA.02
(25 ppm)(25 ppm)
YesYes
Load Zone JLoad Zone K
Net Output
Energy Prices (day-ahead and real-time)
Operating Reserves Prices
(day-ahead and real-time)
Level of Excess Adjustment
Factors
Ancillary Services Adder for
Revenues Not Determined by
Net EAS Model ($/kW-yr.)
Peaking Plant Primary Fuel
Type
Peaking Plant Secondary Fuel Type (if any)
See Independent Consultant Final Report at Appendix A
This data is publically available on the NYISO website
This data is publically available on the NYISO website
See Independent Consultant Final Report at Appendix C
$2.04$2.04$2.04$2.04
Natural GasNatural GasNatural GasNatural Gas
N/A ULSD ULSD ULSD
Fuel Tax Adder - GasN/AN/A6.9%1.0%
Fuel Tax Adder - ULSD Transportation Cost Adder -
Gas ($/MMBtu)
Transportation Cost Adder -
ULSD ($/MMBtu)
Real-time Intraday Gas Premium/Discount
N/AN/A
$0.27$0.27
N/A$1.50
10% 10%
4.5%N/A
$0.20$0.25
$1.50$1.50
20% 30%
325 NYISO Final Recommendations at 56-58; and Independent Consultant Final Report at 125-
126. In certain circumstances, these factors will represent a value that will remain fixed for the four-year reset period. In other instances, these factors will relate to a data source that will be used for determining applicable market price or cost information used by the model.
Honorable Kimberly D. Bose November 30, 2020
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Data Input Value/Source
Factor
Fuel Pricing Point - Gas
Fuel Price Data Source - Gas
NYCAG-J Locality
December-
March:
Niagara
-and-
TETCO M3
April-
November: TGP Z4
(200L)
S&P Global Market Intelligence
New York
NYCLI
Transco Z6 NYIroquois Z2
New YorkNew York
Fuel Pricing Point - ULSD
Fuel Price Data Source -
ULSD
Peaking plant Variable
Operating and Maintenance
N/A
N/A
HarborHarborHarbor
New York Harbor ULSD No.2 spot prices from U.S. EIA, available at:
https://www.eia.gov/dnav/pet/hist/EER_EPD2DXL0_ PF4_Y35NY_DPGD.htm
Costs (including Levelized
Major Maintenance Costs)
Peaking plant CO2 Emissions
Rate
CO2 Emission Allowance
Cost
Peaking plant NOx Emissions
Rate
NOx Emission Allowance
Cost
Peaking plant SO2 Emissions
Rate
SO2 Emission Allowance
Cost
NYISO Rate Schedule 1
Charges for Injection Billing
Units
See Independent Consultant Final Report at Appendix A
See Independent Consultant Final Report at Appendix A
RGGI Regional Allowance Auction Results from RGGI, Inc., available at: https://www.rggi.org/auctions/auction-results
See Independent Consultant Final Report at Appendix A S&P Global Market Intelligence
See Independent Consultant Final Report at Appendix A S&P Global Market Intelligence
This data is publically available on the NYISO website
C. Annual Update of ICAP Demand Curve Parameters
The NYISO will utilize the updated levelized embedded cost values and annual net EAS revenue projections to derive the updated values of the ICAP Demand Curves.326
326 Services Tariff § 5.14.1.2.2.3.
Honorable Kimberly D. Bose November 30, 2020
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The reference point is set at the annual Net CONE value for each peaking plant,
translated into a monthly value that accounts for seasonal differences in capacity availability and the tariff-prescribed level of excess conditions.327 Calculations of the reference point value will use annually updated WSR values. The applicable capacity ratings for each peaking plant used in calculating the reference point price were determined during the DCR and will remain fixed
for the 2021-2025 DCR.
The maximum value of each ICAP Demand Curve is set at an amount equal to the monthly value of the updated levelized embedded cost for the applicable peaking plant, multiplied by 1.5.328
For the 2021-2025 DCR, the NYISO proposes continued use of the currently effective zero-crossing point values for each ICAP Demand Curve.
The table below summarizes the proposed data inputs for calculating the ICAP Demand Curve parameters for the 2021-2025 DCR.329
Data Input Value
FactorType of ValueNYCA
G-J
Locality
NYCLI
ICAP Demand Curve Parameter Values
Fixed for Reset
Zero-crossing pointPeriod112%115%118%118%
Reference Point Price Calculation
Peaking Plant Net
Degraded Capacity
(ICAP MW)
Peaking Plant Summer Capability Period
(DMNC MW)
Peaking Plant Winter Capability Period
(DMNC MW)
Fixed for Reset
Period
Fixed for Reset
Period
Fixed for Reset
Period
326.7347.0348.8348.8
329.3348.2348.5351.1
344.7369.9374.1373.0
327 Services Tariff § 5.14.1.2.2.3; and NYISO Installed Capacity Manual § 5.5.
328 As further described in Section V.C, the NYISO proposes certain enhancements to the
translation of the annual levelized embedded cost for each peaking plant to a monthly value for use in calculating the maximum clearing price value.
329 NYISO Final Recommendations at 50 and 58; and Independent Consultant Final Report at 122 and Appendix A.
Honorable Kimberly D. Bose November 30, 2020
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Data Input Value
FactorType of ValueNYCA
G-J
Locality
NYCLI
Level of Excess
Fixed for Reset
Period
100.9%102.5%103.5% 106.5%
WSR Values
UpdatedThese values are updated annually and will be
Annually publically available on the NYISO website
VII.Description of the Proposed Tariff Revisions
The NYISO proposes to revise the table in Section 5.14.1.2 of the Services Tariff to: (1) include the proposed parameters of the ICAP Demand Curves for the 2021/2022 Capability
Year, as well as the timing for the posting of ICAP Demand Curves for the 2022/2023 through 2024/2025 Capability Years that will be determined as part of the annual updates encompassed by the 2021-2025 DCR; and (2) remove data entries for the 2016/2017, 2017/2018, 2018/2019, and 2019/2020 Capability Years that are no longer relevant. The NYISO also proposes to update the table in Section 5.14.1.2.2.3 of the Services Tariff with the relevant data values proposed for the 2021/2022 Capability Year ICAP Demand Curves.
VIII.Effective Date
The NYISO respectfully requests that the Commission issue an order on or before
January 29, 2021 (i.e., sixty days after filing) accepting: (1) the proposed 2021/2022 Capability Year ICAP Demand Curves; and (2) the annual update methodologies and inputs to determine the ICAP Demand Curves for the 2022/2023, 2023/2024, and 2024/2025 Capability Years. The NYISO also requests an effective date of January 30, 2021 (i.e., the day following the end of the statutory 60-day notice period) for the tariff revisions proposed herein.
Timely Commission action is necessary to: (i) ensure the NYISO’s ability to proceed with the necessary steps to conduct the ICAP auctions for the upcoming 2021 Summer
Capability Period; and (ii) provide marketplace certainty as to the ICAP Demand Curves that will apply beginning with the 2021 Summer Capability Period. The NYISO’s processes and procedures to begin preparation for the 2021 Summer Capability Period ICAP auctions
commence in February 2021. The NYISO needs certainty with respect to the ICAP Demand Curves that will apply for the 2021/2022 Capability Year to facilitate timely completion of its auction-related administrative duties.
IX.Stakeholder Process
The NYISO conducted the DCR for the 2021-2025 period in accordance with the
requirements of Section 5.14.1.2.2 of the Services Tariff. Pursuant to Section 5.14.1.2.2.4.11 of
the Services Tariff, this filing represents the results of the 2021-2025 DCR approved by the
Honorable Kimberly D. Bose November 30, 2020
Page 61
Board for filing with the Commission. The proposal includes: (1) the proposed ICAP Demand Curves for the 2021/2022 Capability Year; and (2) the methodologies and inputs to be used in conducting the tariff-prescribed annual updates to determine the ICAP Demand Curves for the 2022/2023, 2023/2024, and 2024/2025 Capability Years.
X.Communications and Correspondence
Please direct all communications and service in this proceeding to:
Robert E. Fernandez, Executive Vice President & General Counsel Karen G. Gach, Deputy General Counsel
Raymond Stalter, Director, Regulatory Affairs
*Garrett E. Bissell, Senior Attorney
New York Independent System Operator, Inc.
10 Krey Boulevard
Rensselaer, New York 12144
Telephone: 518-356-6000
Email: gbissell@nyiso.com
*Person designated for receipt of service.
XI.Service
The NYISO will send an electronic link to this filing to the official representative of each
of its customers, each participant on its stakeholder committees, the New York State Public
Service Commission, and the New Jersey Board of Public Utilities. The NYISO will also post
the complete filing on its website at www.nyiso.com.
Honorable Kimberly D. Bose November 30, 2020
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XII.Conclusion
The NYISO respectfully requests that the Commission: (i) issue an order accepting the results of the 2021-2025 DCR as proposed herein on or before January 29, 2021 (i.e., sixty days after filing); and (ii) establish an effective date of January 30, 2021 (i.e., the day following the end of the statutory 60-day notice period) for the proposed tariff revisions.
Respectfully submitted,
/s/ Garrett E. Bissell
Garrett E. Bissell
Senior Attorney
New York Independent System Operator, Inc.
cc:Jignasa Gadani
Jette Gebhart
Leanne Khammal Kurt Longo
John C. Miller
David Morenoff
Larry Parkinson
Douglas Roe
Frank Swigonski
Eric Vandenberg
Gary Will
