83C Round II Quantitative Evaluation Report Long-Term Contracts for Offshore Wind Energy Projects Pursuant to Section 83C of Chapter 169 of the Acts of 2008

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 1 of 210

Final Report

83C Round II Quantitative Evaluation Report Long-term Contracts for Offshore Wind Energy Projects Pursuant to Section 83C of Chapter 169 of the Acts of 2008

Prepared for:

Eversource Energy National Grid Unitil Corporation

February 7, 2020

Tabors Caramanis Rudkevich 75 Park Plaza Boston, MA 02166 (617) 871-6900 www.tcr-us.com D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 2 of 210

DISCLAIMER

83C Round II Quantitative Evaluation Report has been prepared by Tabors Caramanis Rudkevich, INC (TCR) for the Massachusetts Electric Distribution Companies (EDCs), Eversource Energy, National Grid US and Unitil for the sole purpose of providing the quantitative analyses to allow the EDCs to evaluate the proposals that they receive in response to the 83C Part II RFPs. The information provided herein deals with the analysis, methodology and results of the proposal quantitative evaluations. Any other use of the materials without the explicit permission of the EDCs is strictly prohibited. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 3 of 210 TABLE OF CONTENTS

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Table of Contents ...... 1 Section 1. Summary and Overview ...... 2 Section 2. Evaluation Costs and Benefits ...... 5 2.1: Analytical Approaches to Quantitative Evaluation of Proposal Cases ...... 5 2.2: Metrics Used in Quantitative Evaluation of Proposal Cases ...... 5 2.2.1: Direct Costs and Benefits ...... 6 2.2.2: Indirect Costs and Benefits...... 6 2.2.3: Net Benefit (Cost) ...... 7 2.2.4: Quantitative Workbooks...... 7

Section 3. Market Simulations – 83C II Base Case and Proposal Cases ...... 9 3.1: 83C II Base Case and 83C II Proposal Cases ...... 9 3.2: ENELYTIX Simulation Model ...... 9 3.3: Major Input Assumptions Used to Model 83C II Base and Proposal Cases ...... 10 3.3.1: Modeling Input Assumption Categories with differences between the 83C II Base Case and each Proposal Case ...... 11 3.3.2: Modeling Input Assumption Categories with no differences between the 83C II Base Case and each Proposal Case ...... 12

Section 4. Proposal Evaluation – Quantitative Workbook ...... 15 4.1: GHG Inventory Worksheet ...... 15 4.2: Proposal Metrics Worksheet ...... 16 Section 5. Scoring and Ranking of Proposal Cases ...... 17

Stage Two Proposal Scores and Ranking ...... 18 Protocol for 83C II Quantitative Metric Calculations, Stage 2 ...... 20 83C II Base Case Results ...... 23 83C II Base Case Assumptions and Description of ENELYTIX simulation model ...... 24 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 4 of 210 Section 1. Summary and Overview

The Massachusetts (“MA”) electric distribution companies (“EDCs”) issued a Request for Proposals (“RFP”) on May 23rd2019 for long term contracts from offshore wind energy projects. The EDCs solicited bids (“Proposals”) for projects (“Projects”) providing such supplies of wind energy and renewable energy certificates (“RECs”) to comply with Section 83C of the Massachusetts Green Communities Act. This RFP (“83C Round II” or “83C II”) is the second round of the multi-phase procurement totaling 1,600 megawatts (“MW”) of offshore wind. The first round of this procurement (“83C I”) resulted in the Massachusetts EDCs entering into long term contracts for 800 MW offshore wind through a similar RFP process initiated in June 2017. The Massachusetts EDCs selected Tabors Caramanis Rudkevich (“TCR”) as Evaluation Team Consultant to help them evaluate certain costs and benefits1 of the proposals received in response to the RFP. This report summarizes the analyses TCR prepared to evaluate such costs and benefits, and the results of those evaluations.

The 83C II RFP required bidders to submit proposals for at least 400 MW of generation capacity with two pricing options. The first option was a generator lead line (“GLL”) proposal that would include the delivery infrastructure required to support the bid generation capacity; the second pricing option was a similar GLL proposal with a Commitment Agreement (“CA”) which is a commitment for the bidders to negotiate in good faith and use commercially reasonable efforts to enter into a voluntary agreement with third-party developers regarding interconnection to and future expansion of the delivery infrastructure. The 83C II RFP also gave bidders the option of submitting proposals of no less than 200 MW and no greater than 800 MW2. However, each optional proposal also had to include both a GLL pricing and a CA pricing option.

The 83C II RFP Evaluation Team reviewed and evaluated the Project bids using a process described in testimony sponsored by the EDCs in this proceeding. As part of this process, TCR performed the Stage Two Quantitative Analysis of each Proposal as well as certain discrete analyses requested by the Evaluation Team at various points in the evaluation. TCR performed these analyses by creating a scenario or “case” for each Proposal (“Proposal Case”) and a common “counterfactual” case (“83C II Base Case”) which provides projections under a future in which the EDCs do not acquire wind energy under long-term contracts from any of the Proposals received in response to the 83C II RFP. TCR evaluated the costs and benefits of each Proposal Case using inputs from that Proposal and results from modeling the operation of the New England and New York energy markets3 assuming the specific Proposal being modeled is chosen, as well as results from the modeling of the 83C II Base Case.

1 The costs and benefits TCR analyzed were a subset of the overall costs and benefits associated with the 83C II RFP bids. Costs and benefits considered less amenable to quantification were analyzed in the Qualitative Analysis portions of the evaluation process. In this report, we use “costs and benefits” and similar terms to refer to the subset of costs and benefits TCR quantified using its tools and methods. 2 Bidders were allowed to propose minor variations in proposed contract size based on expected turbine size and potential changes to expected turbine size. 3 TCR uses a simplified approach to modeling the New York system and does not use the ENELYTIX capacity expansion module to simulate capacity expansion, RPS compliance or emission targets for the New York ISO footprint. Please refer to appendix D for details on modeling assumptions for New England and New York markets. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 5 of 210 Based on the results of these Stage Two analyses, the Evaluation Team determined that it was not necessary to conduct Portfolio Stage Three Model runs. However, during the Stage Three analysis, TCR ran two sensitivity cases on the Stage Two top-ranked Proposal to assess the impact of the winter fuel switch mechanism on the calculated quantitative metrics4. The two sensitivity cases offer a set of alternative projections and metrics under scenarios having no fuel switches (Sensitivity 1 – winter fuel switch disabled) and lower fuel switches (Sensitivity 2 – retirement date of Millstone 2 is assumed to be delayed to 2045). The results of these sensitivity cases confirmed the correct implementation of the fuel switch mechanism and that the impact on quantitative metrics was reasonable. For further discussion and results of the sensitivity cases please see the Addendum to the 83C II Quantitative Metric Calculations, attached as Appendix B-2.

Appendix A summarizes the results of TCR’s Stage Two Quantitative Analyses of each Proposal Case, the quantitative scores based on those results, the qualitative scores developed by the 83C II Qualitative Team, and ranking of each Proposal based on the total of the quantitative and qualitative scores5.

The TCR Quantitative Analyses used metrics for the two categories of costs and benefits specified in the RFP, i.e. Direct Contract Costs and Benefits (“Direct Costs and Benefits”) and Other Costs and Benefits to Retail Consumers (“Indirect Costs and Benefits”). Section 2 of this Report describes those metrics.

TCR developed values for each of these metrics in 2019 constant dollars (“2019$”) for each Proposal by year over a forecast evaluation period of 2022 to 20476 (“evaluation period” or “valuation horizon”). TCR developed values for the Direct Cost and Benefit metrics of each Proposal using data from the Proposal itself, from the outputs of TCR’s Proposal Case simulation modeling and from the Proposal Case Greenhouse Gas (“GHG”) Inventory calculation carried out in the Quantitative Workbook of each Proposal Case.7

TCR developed values for the Indirect Cost and Benefit metrics of each Proposal by comparing outputs of its simulation modeling of each Proposal Case to the outputs of its simulation modeling of the 83C II Base Case, as well as from the comparison of their respective GHG Inventory calculations in its Quantitative Workbook for each Proposal Case

4 Subsequent to the 83C Round I evaluation, TCR developed an improved methodology for assessing the impact of fuel switching on dual- fuel generators during winter periods in which natural gas prices take on extreme high values. The winter fuel switch mechanism resulted in (a) a material increase in forecasted energy prices across New England during the winter months in absence of the additional generation capacity represented by the offshore wind Projects, , and (b) a resulting Indirect Energy Price impact metric which was significantly greater than what was seen in the prior 83C I evaluations, where the winter fuel switch was not considered. For further discussion of the fuel switching mechanism, please see Appendix D.1. 5 TCR produced two sets of scoring and rankings corresponding with two sets of scores provided by the 83C II Qualitative Team to TCR. The first set of scores is identified as ‘DEUI’ representing the scores awarded by the DOER, Eversource, and Until, and a second set of scores identified as ‘NG’ representing the scores awarded by National Grid. Note that the two different scoring approaches resulted in no material impact on the overall ranking of Projects or the top ranked Proposal. 6 This evaluation period ensures that all proposal and proxy units are evaluated over the entirety of their respective PPA periods. Quantitative metric calculations from 2022 through 2046 are based on ENELYTIX simulation results. Calculations for 2047 are extrapolated assuming that they remain at their 2046 levels. 7 The DOER provided the general principles and methodology for calculating the value of the incremental contribution ($/MWh) to GWSA compliance. TCR implemented the methodology, and, as specified in the 83C II quantitative protocol, used $17.22/MWh as the unit value. This value is the $16.51/MWh unit value established in the 83D evaluation to calculate the GWSA compliance value of this contribution, adjusted for inflation. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 6 of 210 Section 3 of this Report describes TCR’s simulation of the 83C II Base Case as well as the Proposal Cases. Appendix C provides 83C II Base Case results in detail. Appendix D provides detailed descriptions of the assumptions TCR used to model the 83C II Base Case and the Proposal Cases, as well as the ENELYTIX platform used to do that simulation modeling. Section 4 describes the Quantitative Workbook for each Proposal Case.

As the EDC testimony describes, bid scoring was based on a 100-point scale under which a Proposal Case could receive a maximum of 75 points based upon the results of its Quantitative Analysis performed by TCR and a maximum of 25 points based upon the results of a separate Qualitative Analysis performed by a separate set of members of the Evaluation Team (“83C II Qualitative Team”). See Appendix B.1 for the Quantitative Protocol describing the point allocation/scaling methodology. TCR developed the Quantitative Analysis scores assigned to each Proposal Case based upon the results of the analyses described in this Report. TCR added these Quantitative Analysis scores to the Qualitative Analysis scores provided to it by the 83C II Qualitative Team to calculate the total score of each Proposal Case. TCR then ranked each Proposal Case from high to low according to the total scores. Section 5 describes this scoring and ranking. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 7 of 210 Section 2. Evaluation Costs and Benefits

This section summarizes the analytical approach and metrics TCR used to measure each category of costs and benefits and to develop values for each of those metrics.

The 83C II RFP process evaluated two quantitative categories of costs and benefits - Direct Contract Costs and Benefits (“Direct Costs and Benefits”) and Other Costs and Benefits to Retail Consumers (“Indirect Costs and Benefits”). Prior to opening the 83C II bids, the Evaluation Team developed a Protocol for 83C II Quantitative Metric Calculations, Stage 2 (“83C II Quantitative Protocol”). That protocol, provided in Appendix B, specifies the analytical approach and metrics to be used for the quantitative evaluation of those two costs and benefits. TCR evaluated the quantitative costs and benefits of each Proposal according to that protocol, whose results are reflected in Appendix A.

2.1: Analytical Approaches to Quantitative Evaluation of Proposal Cases The 83C II Quantitative Protocol, specifies that each proposal be evaluated “…based on the simulated energy and RECs from 800 MW of offshore wind capacity consisting of the capacity specified in the bid for the offshore wind project plus, as needed, a proxy unit sized to supplement the bid capacity to total to the 800 MW.” That specification reflects the fact that an individual bidder responding to the 83C II RFP had the option to submit multiple Proposals, with capacities ranging in size from 200 MW to 800 MW. The Evaluation Team concluded that the most accurate, realistic, and fair way to compare Proposals of different sizes was to assume a common end-state size, in this case 800 MW8.

TCR thus evaluated each Proposal as being part of a total of 800 MW of offshore generating capacity and associated transmission facilities. The majority of the Proposals were approximately 800 MW as bid. Where Projects bid were less than approximately 800 MW, a proxy unit was sized to supplement the bid capacity to achieve a total of 800 MW.

Under this analytical approach, TCR used ENELYTIX to model each Proposal Case as having a total of 800 MW of new offshore generating capacity. TCR modeled that total of 800 MW as two “tranches” or “Phases” of offshore generation capacity, each with a different commercial operation date (“COD”). Tranche 1 was the Project as bid and Tranche 2 was the proxy unit if needed. TCR used the 83C II Quantitative Workbook to evaluate each Proposal under a capacity buildout of 800 MW.

2.2: Metrics Used in Quantitative Evaluation of Proposal Cases The 83C II Quantitative Protocol, specifies the “…core quantitative measure of comparison” as “…the levelized net unit benefit per MWh of the project expressed in 2019 dollars”. For each Proposal Case, TCR developed the value for each component direct and indirect metric described in this section, by year, over the evaluation period in 2019$. It then calculated the present value for each metric using a real discount rate of 5.05%. The real discount rate was based on the EDCs’ load-weighted average cost of

8 This approach also recognized that the portion of the legislative 83C wind procurement requirement remaining after completion of the 83C I procurement was 800 MW, and thus that 800 MW would eventually be procured and built irrespective of what portion of this amount was represented by the particular Proposal being considered. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 8 of 210 capital of 7.15% (nominal) and an agreed assumed inflation rate of 2.00%. Finally, it calculated a levelized unit value ($/MWh) for each metric as the present value divided by the present value of the annual energy from the Proposal Case.

2.2.1: Direct Costs and Benefits TCR measured the Direct Costs and Benefits of each Proposal Case9 by calculating the values of each of the following metrics:

i. Total Direct Costs include the Direct Cost of Energy, the Direct Cost of Renewable Portfolio Standard (“RPS”) Class 1 eligible RECs, and the Remuneration Cost. The Direct Cost of Energy was calculated from the Proposal price for energy multiplied by the annual quantity of delivered energy for each year over the proposed contract term. The Direct Cost of RPS Class 1 eligible RECs was calculated from the Proposal price for RECs multiplied by the annual quantity of RECs for each year over the proposed contract term. The Remuneration cost was calculated as a fixed percentage10 of the Direct cost of Energy plus the Direct Cost of RPS Class 1 eligible RECs. The resulting levelized unit value for Total Direct Costs of the Proposal is reported as “Subtotal - Direct Cost of Proposal Energy + RECs (2019$/MWh)” in Column H of Appendix A. ii. Total Direct Benefits include the Direct Benefit of Energy and the Direct Benefit of RECs and the Direct Benefit of Clean Energy Certificates (“CECs”).11 The Direct Energy Benefit is the market value of the energy deliveries from the Project over the proposed contract term, based upon the forecast market energy prices at the delivery point under the Proposal Case. The Direct Benefit of RECs and CECs is the avoided cost of using these products from the Proposal Case to meet RPS + CES requirements12, valued at the Base Case market prices of RECs plus the forecast market value in the proposal case of any RECs and CEC delivered to the EDCs that are surplus to RPS + CES requirements, if applicable. The resulting levelized unit value for Total Direct Benefits of the Proposal is reported as “Subtotal - Direct Benefit of Proposal Energy + RECs (2019$/MWh)” in Column J of Appendix A The resulting Net Direct Benefit (Cost) is the sum of the above Direct Costs and Direct Benefits. The levelized unit values of the Net Direct Benefit (Cost) are reported in Column K of Appendix A for the Proposals.

2.2.2: Indirect Costs and Benefits TCR measured the Indirect Benefits of each Proposal Case by calculating the values of each of the metrics described below.13

9 The costs and benefits of Proposals whose projects were less than 800 MW include costs and benefits of the proxy unit. 10 TCR calculated the remuneration costs as being 2.75% of the direct costs based upon the 83C legislation if ultimately approved by the Department of Public Utilities. 11 The 83C II Quantitative protocol includes a provision for including projected revenues from the sale of transmission capacity as a Direct Benefit, but as none of the Proposals offered incremental transmission capacity that could provide an additional source of revenue, this was not included in this analysis. 12 RECs from the Project automatically qualify as CECs under the MA CES 13 Consistent with 83C I, the 83C II Quantitative protocol did not include a Capacity Price Indirect Benefit metric because the 83C II Steering Committee determined that projections for this metric would not be reliable. Capacity market price changes resulting from any particular resource addition are difficult to forecast with precision and can be highly dependent on other factors and assumptions. In addition, ISO-NE changes to Forward Capacity Market (FCM) rules have reduced the ability of state sponsored resources such as those D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 9 of 210 i. Indirect Energy Price Benefits are the savings over the evaluation period from changes to wholesale energy market costs paid by EDC load in Massachusetts, i.e. from changes to Locational Marginal Prices ("LMP") in Massachusetts in the Proposal Case relative to energy market costs paid by EDC load in Massachusetts in the 83C II Base Case. This metric first calculates the gross annual savings associated with Massachusetts EDCs retail load i.e. net energy for Massachusetts load less the load served by Municipal Light Plants (“MLPs”). It then calculates the change in aggregate market value of energy from all existing EDC long-term contracts in the 83C II Proposal Case being analyzed compared to the 83C II Base Case. Finally, the metric calculates the net impact as the gross savings on EDC retail load less the change in revenues from EDC long-term contracts.

ii. Indirect REC Price Benefits are the savings over the evaluation period from changes to the costs paid by Massachusetts EDCs for Class 1 RECs based on expected market prices in the Proposal Case relative to the 83C II Base Case This metric calculates the savings associated with RECs obtained by the Massachusetts EDCs to meet the state RPS requirements incremental to the RECs delivered by the Proposal and through existing long-term contracts.

iii. The Global Warming Solutions Act (“GWSA”) compliance Benefit is the value of the Proposal’s incremental contribution towards meeting the Massachusetts GWSA, i.e., incremental to compliance with the RPS and the CES in the Proposal Case relative to the 83C II Base Case.

iv. Additional Benefit under Conditions of Extreme Winter Gas Prices. This metric measures the additional market value14 of the Proposal energy under conditions of extreme high and low winter gas prices. The metric relies on two separate modeling scenarios of each Proposal Case for a specified year (2029/2030) wherein the fuel prices in the months of December, January and February (“winter period”) are adjusted to 15-year historic high and historic low prices respectively. The resulting net percentage change in annual revenues resulting from the two scenarios is applied to the Proposal Case assuming a 1 in 20-year probability of occurrence, i.e., occurring once during the evaluation period.

The resulting Total Indirect Benefit is the sum of the above Indirect Benefits. The levelized unit values of the Total Indirect Benefit for each Proposal are reported in Column L of Appendix A.

2.2.3: Net Benefit (Cost) TCR calculated the Net Benefit (Cost) of each Proposal. The levelized unit value of this metric is the core measure for comparison under the 83C II Quantitative Protocol. Appendix A Column M reports this value, in $/MWh.

TCR also calculated the Net Benefit (Cost) in absolute terms ($). This value equals the present value of the Total Direct Benefits and Total Indirect Benefits less the present value of the Total Direct Costs. Appendix A Column N reports this metric.

2.2.4: Quantitative Workbooks TCR developed the values of these metrics in a Quantitative Workbook for each Proposal.

procured pursuant to Section 83C to impact capacity clearing prices significantly in the near-term. The Steering Committee determined that the most reliable and conservative approach would be to exclude capacity benefits from the analysis of all Projects. 14 This benefit is not captured in the other direct and indirect benefit calculations, since those metrics are developed under projections assuming normal weather conditions. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 10 of 210 • TCR developed values for the Direct Cost and Benefit metrics of each Proposal Case from the bids submitted for each Proposal, from the outputs of its simulation modeling of each Proposal Case, outputs from its simulation modeling of the 83C II Base Case, as well as from its quantitative evaluation workbook for each Proposal Case. • TCR developed values for the Indirect Cost and Benefit metrics of each Proposal Case by comparing outputs of its simulation modeling of each Proposal Case to the outputs of its simulation modeling of the 83C II Base Case, as well as from its quantitative evaluation workbook for each Proposal Case. Section 3 describes TCR’s simulation of the 83C II Base Case as well as the Proposal Cases. Section 4 describes TCR’s quantitative evaluation workbook for each Proposal Case.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 11 of 210 Section 3. Market Simulations – 83C II Base Case and Proposal Cases

TCR developed values for many of the metrics used in the calculations of Direct Costs and Benefits as well as Indirect Costs and Benefits from the outputs of its simulation modeling of the 83C II Base Case and each Proposal Case. This section describes the basic differences between the 83C II Base Case and the Proposal Cases. It then describes the ENELYTIX platform TCR used to model each of those Cases and the major input assumptions TCR used in that modeling.

3.1: 83C II Base Case and 83C II Proposal Cases The 83C II Base Case provides a “but for” or “counterfactual” projection of carbon emissions as well as energy costs associated with Massachusetts electricity consumption under a future in which the EDCs do not acquire wind energy under long-term contracts from any of the Proposals received in response to the 83C II RFP.15

Each Proposal Case provides a projection of carbon emissions and costs associated with Massachusetts electricity consumption under a future in which the EDCs acquire the wind energy bid by that Proposal (and a proxy unit, if needed) under a long-term contract. TCR used the results from each Proposal Case as well as certain inputs from the 83C II Base Case to measure the Direct Costs and Benefits of that Proposal described in Section 2, i.e., these Cases provide the projections of carbon emissions and costs with the Proposal in service.

TCR reflected the difference between the 83C II Base Case and each Proposal Case in its modeling by using input assumptions corresponding to each case for generation capacity additions and for transmission system upgrades/changes where these were affected by such generation capacity additions. Subsection 3.3 summarizes each major category of input assumptions TCR used in its modeling and describes the differences in input assumptions between the 83C II Base Case and each Proposal Case. Appendix D provides detailed descriptions of the assumptions TCR used to model the 83C II Base Case and the Proposal Cases, as well as of the ENELYTIX platform TCR used for its simulation modeling.

The differences in these input assumptions lead to differences in results between the Base Case and each Proposal Case. Appendix C provides key results from the ENELYTIX modeling of the 83C II Base Case.

3.2: ENELYTIX Simulation Model TCR used the ENELYTIX computer simulation software tool to simulate the operation of the New England wholesale markets for energy and ancillary services and RECs under the 83C II Base Case and for each Proposal Case. ENELYTIX develops internally consistent, detailed projections of prices in each

15 The 83C II Base Case is not a plan for the Massachusetts electric sector and should not be viewed as such. TCR used the results from the 83C II Base Case as a common reference point against which to measure the Indirect Costs and Benefits of each Proposal described in Section 2, i.e., the 83C II Base Case provides the projections of carbon emissions and costs without any of the Proposals in service. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 12 of 210 of those markets as well as of the key physical parameters underlying those prices such as capacity additions and retirements, energy generation by source, carbon emissions and fuel burn. TCR conducted a separate ENELYTIX computer run for the Base Case and for each Proposal Case being analyzed.

ENELYTIX developed its projections through the interaction of the Capacity Expansion module and the Energy and Ancillary Services (“E&AS”) module.16

The Capacity Expansion module determines an optimal electric system expansion in New England over a long-term planning horizon. Its objective function is to minimize the net present value of the total cost, i.e., capital, fuel and operating, of the generation fleet serving the wholesale market within the ISO-NE electrical footprint subject to resource adequacy, operational and environmental constraints. Resource adequacy constraints are specified in terms of installed capacity requirements (“ICR”) for the ISO-NE system as whole and for reliability zones within ISO-NE. Environmental constraints include requirements for state-by-state procurement of electric energy generated by renewable resources, as well as state and regional emissions limits. The module represents each state’s year-by-year Class 1 RPS requirements, Massachusetts CES requirements, state-specific RPS resource eligibility, limitations on REC banking and borrowing, and alternative compliance payment (“ACP”) prices.

The Energy and Ancillary Services (“E&AS”) module simulates the Day-Ahead and Real-Time market operations within the footprint of the ISO-NE and New York Independent System Operator (“NYISO”) power systems and markets. This module implements chronological simulations of the Security Constrained Unit Commitment (“SCUC”) and Economic Dispatch (“SCED”) processes, as well as the structure of the ancillary services in ISO-NE and NYISO markets.

The two modules use the Power System Optimizer (“PSO”) market simulator developed by Polaris Systems Optimization, Inc.17 In addition the two modules rely on data obtained from ISO-NE and NYISO including the economic and operational characteristics of existing generating units, representation of the electric transmission system, and projection of future electricity demand.

3.3: Major Input Assumptions Used to Model 83C II Base and Proposal Cases TCR used ten major categories of input assumptions18 to model the 83C II Base Case and each of the Proposal Cases in ENELYTIX. They were Generating Unit Capacity Additions, Transmission, Load Forecast, Installed Capacity Requirements, RPS Requirements, Massachusetts CES and annual cap on Carbon Emissions, Emission Allowance Prices, Generating Unit Retirements, Generating Unit Operational Characteristics and Fuel Prices. Of those, the only three categories in which there were input assumption differences between the 83C II Base Case and each Proposal Case were Generating Unit Capacity Additions, Generating Unit Retirements and Transmission.

16 TCR did not use the Forward Capacity Market module of ENELYTIX because the 83C Quantitative Protocol did not require a projection of capacity prices. 17 www.psopt.com. 18 TCR uses the term ‘Assumptions’ to refer to inputs to the modeling process that are exogenous to the model, and often calculated from data available from sources such as ISO-NE, EIA’s Annual Energy Outlook or other proprietary datasets such as S&P Market Intelligence Platform. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 13 of 210 This subsection summarizes each of the major categories of input assumptions TCR used in modeling ISO-NE and describes the differences in those input assumptions between the 83C II Base Case and each Proposal Case. TCR used the input assumptions in the remaining seven categories to model both the 83C II Base Case and each of the Proposal Cases. Appendix D provides detailed descriptions of the assumptions for ISO-NE and for the NYISO that TCR used to model the 83C II Base Case and the Proposal Cases.

3.3.1: Modeling Input Assumption Categories with differences between the 83C II Base Case and each Proposal Case Three categories of modeling input assumptions that were different between the 83C II Base Case and each Proposal Case were Generating Unit Capacity Additions, Generating Unit retirements, and Transmission.

Generating Unit Capacity Additions (Existing / Scheduled and Optional). This category consists of two groups of resources. Existing / Scheduled resources are the generating resources input to ENELYTIX assumed to be in-service during the evaluation period based on external source materials. Optional resources are categories of generic generating resources that ENELYTIX has the option to choose to add during the study horizon, as determined by its internal calculations, to meet resource adequacy, energy and environmental constraints existing within the simulation model at various times at least cost.

The only existing / scheduled generating unit capacity addition assumptions that differed between the 83C II Base Case and each Proposal Case were the Tranche 1 and Tranche 2 generating capacity resource(s) from the particular Proposal Case. The remaining existing / scheduled generating unit capacity addition assumptions were common to the 83C Base Case and each Proposal Case over the evaluation horizon. Those capacity additions include:

• The New England Clean Energy Connect (“NECEC”) Hydro and Vineyard Wind projects selected through the 83D and 83C I RFP process; • Existing generating units listed in the 2019 ISO New England Forecast Report of Capacity, Energy, Loads, and Transmission (“CELT Report”); • Projects that had cleared the most recent Forward Capacity Auction (FCA13); • Distributed photovoltaic (PV) capacity at levels in the ISO-NE’s Final 2019 PV Forecast through 2027 and thereafter at levels extrapolated from the ISO-NE PV Forecast19 which includes PV installed under the Solar Massachusetts Renewable Target (SMART) Program; • Renewable generation projects that either have existing long-term contracts with the EDCs, or that have been selected to negotiate contracts with the EDCs as of June 15, 201920; • Imports of Class 1 eligible REC into ISO-NE from neighboring control areas at their 2015 levels (the most recent year such data are available); For the 83C II Base Case and the Project Cases ENELYTIX had the option of choosing to simulate additions of generating capacity from other (i.e., non-83C II) renewable and fossil fuel resources in order to satisfy resource adequacy, energy and environmental constraints assumed to be in effect over

19 ISO New England Final 2019 PV Forecast, April 29, 2019. 20 Refer to Appendix D.1 for a detailed list of renewable projects included in the 83C II Base Case and all Proposal Cases D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 14 of 210 the evaluation period. ENELYTIX evaluated the economics of each of these possible resources with the assumption that they would be developed and financed on a merchant basis, i.e. without long-term purchase power agreements. Even if these resources were assumed to have long-term power sales agreements, the expectation is that the pricing terms of such agreements would reflect similar future economic fundamentals. Due to similarities in size and timing of Proposals, all 83C II Proposal Cases share a common set of optional generating unit capacity additions. These additions are distinct from the optional generating unit capacity additions in the 83C II Base Case. (Refer to Appendix B for additional details on the generic capacity expansion assumptions.)

Generating Unit Retirements. This category, like generating unit additions, consists of two groups of assumptions. First, there are the specific generating capacity units input to ENELYTIX as retiring prior to, or during, the evaluation period. These are the generating units that are scheduled to have retired prior to the beginning of the evaluation period (January 2022) plus the ISO-NE approved scheduled retirements as of June 2019 over the evaluation period. Second, within the economic simulations of ENELYTIX, existing generating units are retired when they are no longer cost effective ENELYTIX determines within the simulation whether it is cost efficient to keep an existing unit online, to retire the unit, or to replace it with a more efficient unit or with a resource that is needed to meet environmental constraints. All model selected retirements for the 83C II Base Case are assumed to be carried forward to the 83C II Proposal Cases, and all 83C II Proposal Cases share a common set of model selected retirements that are incremental to the 83C II Base Case.

Transmission. ENELYTIX provides a detailed representation of the transmission topology and electric characteristics of transmission facilities within ISO-NE and the NYISO. The Evaluation Team and TCR worked together to ensure that the ENELYTIX model correctly reflected the transmission upgrades associated with each Proposal that were not required for the 83C II Base Case. These included transmission topology and contingency sets for additional contingency constraints that might be affected by power injections from 83C II Proposals.

Aside from those differences, the remaining transmission input assumptions were common to the 83C II Base Case and each Proposal Case over the evaluation horizon. ENELYTIX modeled the ISO-NE transmission system based on the 2020 SUMMER Peak case and the NYISO system based on the 2019 Market Monitoring Working Group power flow case. For the 83C II Base Case, and each Proposal Case, TCR worked with the Evaluation Team to identify the relevant transmission constraints to assume and monitor. These included all major ISO-NE interfaces and frequently binding constraints assembled by the Evaluation Team using historical data from 2012 through June 15, 2019, transmission changes associated with large clean energy projects procured through recent RFP processes, and contingency analyses performed by the Evaluation Team and TCR.

3.3.2: Modeling Input Assumption Categories with no differences between the 83C II Base Case and each Proposal Case The remaining seven categories of modeling input assumptions that are common to the Base Case and each Proposal Case are Load Forecast, Installed Capacity Requirements, RPS Requirements, Massachusetts CES and cap on Carbon Emissions, Emission Allowance Prices, Generating Unit Operational Characteristics and Fuel Prices.

Load Forecasts. The load forecast inputs to ENELYTIX are annual energy and peak load before (“Gross”) and after the impacts of reductions due to passive demand response (“PDR”), i.e. “Gross- D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 15 of 210 PDR”. TCR drew these forecasts through 2028 from the CELT Report. It developed the forecasts for 2029 through 2046 through separate extrapolations of the Gross and PDR components. TCR also developed a forecast of energy requirements net of the impacts of reductions from behind the meter PV (“BTMPV” or “BMPV”). This forecast, which corresponds to the obligation for retail metered load, is referred to by ISO-NE as Net Energy Load (“NEL”) and as ‘“Gross-PV-PDR.’” TCR used this forecast to estimate annual state RPS obligations and MA CES obligations, both of which are inputs to ENELYTIX. In order to simulate the ISO-NE market on an hourly basis, TCR developed hourly load forecasts for each ISO-NE zone. It developed these based upon its forecasts of annual energy and summer/winter peaks and on 2012 historical load shapes to be consistent with calendar 2012 NREL wind generation profiles, the most recent detailed data available from NREL for New England.

Installed Capacity Requirements. ICR forecast inputs to ENELYTIX include the system-wide requirement as well as local sourcing requirements (“LSR”) for import constrained zones. TCR developed its forecasts of these requirements based on its analyses of ISO-NE studies21. The forecast of system-wide ICR assumes that import capacity under the existing supply agreement with Hydro Quebec will remain at the 2022/23 level of 969 MW22 estimated by ISO-NE, that imports from other external control areas including New York, New Brunswick, and Highgate will provide an additional 1,368 MW, and resources within New England will provide 512 MW of Active Demand Response (“ADR”).

RPS Requirements. ENELYTIX models the Class 1 RPS requirements of each New England state23 except Vermont, which does not have an equivalent Class 1 RPS requirement.24 The RPS requirement input to ENELYTIX for each state equals the forecast load of Load Serving Entities (“LSEs”) obligated to comply with that state’s RPS multiplied by that state’s annual Class 1 RPS percentage target. The forecast load of LSEs is the forecast Gross-PV-PDR load for each state reduced by the load exempt from the RPS in that state. Additional RPS inputs to ENELYTIX are state-specific resource eligibility, limitations on certificate banking and borrowing, and ACP prices.

Massachusetts CES and Cap on Carbon Emissions. ENELYTIX models regulation 310 CMR 7.74, a cap on carbon emissions from electric generating units (“EGU”) located in Massachusetts and regulation 310 CMR 7.75, the CES. The CES requirement input to ENELYTIX equals the forecast load of LSEs obligated to comply with the CES multiplied by the Massachusetts annual CES percentage target. The CES ACP for 2018-2020 is 75% of the Massachusetts RPS ACP, and 50% of the RPS ACP thereafter.

Emission Allowance Prices. TCR developed its CO2 allowance price assumptions based upon a review of Regional Greenhouse Gas Initiative (RGGI) projections from its 2016 Program Review. The allowance prices assumed for CO2 emissions follow a trajectory starting in 2017 at the allowance price of RGGI’s “Model Rule Policy, No National Program” scenario to 2031, and continuing along the same curve to

21 ISO-NE History of historical ICR and related values (https://www.iso-ne.com/static- assets/documents/2016/12/summary_of_historical_icr_values.xlsx), ISO-NE Regional System Plan (https://www.iso-ne.com/system- planning/system-plans-studies/rsp), ISO-NE Calculation of ICR and local resource requirements (https://www.iso-ne.com/markets- operations/markets/forward-capacity-market/fcm-participation-guide/installed-capacity-requirement) 22 This estimate represents the baseline level of imports from Hydro Quebec that are assumed to be available at FCA 13 levels. TCR assumes incremental capacity will be added with the NECEC project beginning 2023 onward. 23 The Evaluation Team reviewed but did not include changes to RPS legislation in Maine “An Act to Reform Maine’s Renewable Portfolio Standard,” LD1494, passed on June 26, 2019, which occurred after the assumptions cut-off date. 24 TCR did not model New York RPS requirements and compliance. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 16 of 210

2046. TCR developed its NOx and SO2 allowance price assumptions for NYISO based on emission limits under the Federal Cross State Air Pollution Rule (“CSAPR”).25 Appendix D describes the additional TCR allowance price assumptions for NYISO

Generating Unit Operational Characteristics. TCR develops assumptions for the key physical and cost operating parameters of all the types of generating units and resources that ENELYTIX models. These include thermal units, nuclear units, hydro, pumped storage hydro, wind and solar PV.

Fuel Prices. TCR developed forecasts of monthly spot gas prices for each gas-fired unit in New England based upon the spot prices at the market hub which serves the unit. The four relevant hubs are Algonquin, Tennessee Zone 6, Tennessee Dracut and Iroquois Zone 2. The forecasts are based upon projections of Henry Hub prices plus projections of basis differential to each hub from the Henry Hub. The projection of annual Henry Hub prices is a blend of forward prices as of June 15, 2019 from OTC Global Holdings available from S&P Global and the Reference Case forecast from the Energy Information Administration (“EIA”) Annual Energy Outlook 2019 (“AEO 2019”). The basis differentials are obtained from the forward prices and assumed to be held constant based on the last year of available data. The projections of distillate and residual to electric generators in New England are drawn from AEO 2019.

Due to constraints in pipeline capacity, generating units in New England face shortages in natural gas supply during the winter period. To capture its impact, TCR included a winter fuel switching mechanism in the ENELYTIX model to approximate the economic and environmental impact resulting from dual-fuel generators switching from natural gas to fuel oil on winter days with high natural gas prices. The fuel switching mechanism is included for all ENELYTIX model runs i.e. the 83C II Base Case and all Proposal Cases. Appendix D outlines TCR’s modeling approach on fuel switching mechanics.

25 New England states are not subject to CSAPR. Some New England states have cap and trade programs for NOx and SO2, but the market is thin, prices are low, and allowances are often granted annually rather than auctioned. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 17 of 210 Section 4. Proposal Evaluation – Quantitative Workbook

TCR’s Quantitative Analysis calculated the costs and benefits of each Proposal using a Quantitative Workbook for that Proposal. If a bid included an alternative pricing option for energy and/or transmission for a particular Proposal, TCR prepared a separate Quantitative Workbook for each pricing option included in the bid. The Quantitative Workbook is an EXCEL workbook consisting of a summary worksheet, a Proposal Metrics worksheet, a GHG Inventory worksheet for the proposal case and Base Case, a worksheet for accounting for load served through existing long-term contracts, and 33 supporting worksheets reporting data drawn from the relevant bid, the Proposal Case modeling results and the 83C II Base Case modeling results. TCR also prepared separate Quantitative Workbooks for each of the sensitivity cases run as part of the Stage 3 analysis. For further discussion of the sensitivity cases, see the Addendum to the 83C II Quantitative Metric Calculations, attached as Appendix B-2.

This section describes the GHG Inventory worksheet and the Proposal Metrics worksheet.

4.1: GHG Inventory Worksheet The goal of the GHG Inventory Worksheet is to measure the incremental contribution of each Proposal towards meeting the Massachusetts GWSA relative to the 83C II Base Case.26 TCR developed the GHG Inventory Worksheet to estimate the impact of the Proposal on the Massachusetts Department of Environmental Protection GHG Inventory following the general principles and methodology provided by DOER.

The GHG Inventory Worksheet calculates values for two types of GHG emission impacts of a Proposal on Massachusetts. First, it calculates changes in annual emissions (in metric tons of CO2 equivalent) of grid energy generated in Massachusetts and/or imported into Massachusetts attributable to operation of the Proposal. Second, it calculates the changes in the MA annual emissions inventory associated with RECs used to comply with state RPS. The manner in which the Proposal’s RECs are treated in each year is a function of market conditions and current law and regulation for compliance in Massachusetts and the other New England states. In particular, the RPS relies on markets, with ACPs, to incentivize new project development and retirements.

The GHG Inventory provides six major outputs by year for the period 2022 to 2046 that are then used as inputs to the calculations of Direct and Indirect Benefits of each Proposal. The six outputs are: 1. RECs from Project (MWh) used towards MA RPS contract gap. 27

26 The Base Case GHG Inventory does not represent full implementation of all policies in the GWSA Clean Energy Compliance Plan (CECP) 2020 Update. Thus, its results should not be interpreted as a prediction of electric sector emissions. Instead, the Base Case GHG Inventory result simply helps determine the incremental impact of a Proposal on the electric sector. Refer to Appendix B.3 for additional details on the GWSA calculation methodology. 27 Massachusetts RPS contract gap equals the total quantity of RECs required to comply with the Massachusetts RPS in a year minus the quantity of non-83C II RECs under contract to comply with Massachusetts RPS in that year. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 18 of 210 2. RECs from Project (MWh) used towards MA incremental CES contract gap28 3. EAs from Project (MWh) used towards MA incremental CES contract gap 4. Residual quantity of RECs (MWh) purchased at market prices and retired to comply with Massachusetts RPS and / or incremental CES 5. RECs from Project (MWh) sold out of state. 6. GWSA compliance contribution (GHG Inventory Impact) of Proposal in MWh. In each year, this

contribution is calculated as the decrease in annual metric tons of CO2 under the Proposal Case relative to the Base Case divided by the Base Case emissions rate. (The Base Case emissions

rate in a given year is metric tons of CO2 emitted that year divided by MWh of energy consumed in Massachusetts that year.)

4.2: Proposal Metrics Worksheet The Proposal Metrics worksheet of the Quantitative Workbook for a given Proposal develops values for each of the metrics used to calculate the Direct and Indirect Costs and Benefits of that Proposal Case. It develops annual values in 2019$ over an evaluation period of 2022 to 2047 and then calculates their respective present values.

The Proposal Metrics worksheet for each Proposal develops these annual and present values from the following major inputs:

• Prices for energy and RECs from the bid • Prices for energy and RECs for Tranche 2 proxy developed per 83C II Quantitative Protocol (as applicable) • Details of generation units under existing and anticipated long term contracts with MA EDCs • Results from ENELYTIX modeling of the relevant Proposal Case • Results from ENELYTIX modeling of the 83C II Base Case • Results from the GHG Inventory worksheet of the relevant Proposal Case, and • The unit value per MWh of incremental contribution towards GWSA compliance.

28 Massachusetts incremental CES contract gap equals the total quantity of additional CECs (which are incremental to the MA RPS requirement) required to comply with the Massachusetts CES in a year minus the quantity of non-83C II CECs under contract to comply with the Massachusetts CES in that year. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 19 of 210 Section 5. Scoring and Ranking of Proposal Cases

The Evaluation Team used the results from TCR’s Quantitative Analyses and from the Qualitative Analyses performed by the 83C II Qualitative Evaluation Team, to score and then rank Proposals.

The scoring system was based on a 100-point scale. A Proposal Case could receive a maximum of 75 points based upon the results of its quantitative evaluation and a maximum of 25 points based upon the results of its qualitative evaluation. TCR developed the Quantitative Analysis scores assigned to each Proposal Case based upon the results of its quantitative evaluations. The 83C II Qualitative Team developed the scores assigned to each Proposal Case based upon the results of their Qualitative Analysis evaluations.

For the 83C II analysis, TCR and the Evaluation Team modified the scoring methodology to address “scaling” concerns raised by witnesses in the 83C I Massachusetts Department of Public Utilities proceeding29. TCR assigned Quantitative Analysis scores to each Proposal Case based upon results of their respective Quantitative Analysis results pursuant to the following approach:

• Assign 75 points to the Proposal Case with the highest levelized unit Net Benefit, 2019$/MWh, (“top bidder”);

• for each other bid, subtract 3.0 points for each $1.00/MWh of levelized unit Net Benefit that the bid is below the top bidder to determine the score for each remaining proposal30.

The 83C II Qualitative Team provided TCR the scores assigned to each Proposal Case based upon results of their qualitative evaluations.

TCR added the quantitative and qualitative scores to calculate the total score of each Proposal Case. TCR then ranked each Proposal Case from high to low according to its total score.

Appendix A summarizes the results of TCR’s Stage Two Quantitative Analyses of each Proposal, the quantitative scores based on those results, the qualitative scores developed by the 83C II Qualitative Team and ranking of each Proposal Case based on the total of the quantitative and qualitative scores.

29 See D.P.U. 18-76/18-77/18-78, Initial Brief of the Office of the Attorney General at 18-20. 30 The Evaluation Team agreed that this alternative approach ensures that quantitative points receive three times the weighting of qualitative points, consistent with a 75 percent weighting of the quantitative score and a 25 percent weighting of the qualitative score. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 20 of 210

Stage Two Proposal Scores and Ranking

A.1: Stage 2 Scores and Ranking based on DEUI Quantitative Scores 83C_II Stage 2 Results Summary 2019_10_22.xlsx D.P.U. 20-16/20-17/20-18 1 of 2 5a Result Summary DEUI Exhibit JU-4 Page 21 of 210 ABCDEFGHIJ 1 83C_II Stage 2 Results 2 Ranking Set All Proposals <‐ Dropdown 3 Qualitative score D.E.U.I. Pts <‐ Dropdown 4 Quantitative points scaling 83C_II <‐ Dropdown 5 Results as of 10/22/2022 Remuneration Sub total ‐ Direct Sub total ‐ Direct Contract Proposal Net Cost @ 2.75% Benefit of Proposed Annual Tranche 1 PPA Tranche 1 PPA ISO‐NE Load Cost of Proposal Proposal Identifier Maximum Capacity Direct Cost of Proposal Energy Delivery (MWh) Start Date End Date Zone Energy + RECs Amount (MW) Factor (%) PPA + RECs (2019$/MWh) 6 (2019$/MWh) (2019$/MWh)

MFW_800_CA_Fixed 804.0 9/1/2025 8/31/2045 SEMA 58.47 1.61 84.06 7

34 83C_II Stage 2 Results Summary 2019_10_22.xlsx D.P.U. 20-16/20-17/20-18 2 of 2 5a Result Summary DEUI Exhibit JU-4 Page 22 of 210 ABKLMNOPQR 1 83C_II Stage 2 Results 2 Ranking Set All Proposals 3 Qualitative score D.E.U.I. Pts 4 Quantitative points scaling 83C_II 5 Results as of 10/22/2022

Contract Total Net Direct Total Net Indirect Net Benefit Net Benefit Quantitiative Qualitative Proposal Identifier Maximum Benefit (Cost) Benefit (Cost) (Cost) (Cost) : Absolute Total Score Rank Score Score Amount (MW) (2019$/MWh) (2019$/MWh) (2019$/MWh) value (2019$) 6

MFW_800_CA_Fixed 804.0 23.99 28.66 52.65 1,643,796,934 75.00 9.50 84.50 1 7

23.99 28.66 52.65 1,643,796,934 75.00 9.00 84.00 2 8

23.44 28.66 52.10 1,626,718,357 73.36 9.50 82.86 3 9

23.44 28.66 52.10 1,626,718,357 73.36 9.00 82.36 4 10

22.91 28.66 51.56 1,610,025,903 71.76 9.50 81.26 5 11

22.91 28.66 51.56 1,610,025,903 71.76 9.00 80.76 6 12

22.36 28.66 51.02 1,592,912,830 70.11 9.50 79.61 7 13

22.36 28.66 51.02 1,592,912,830 70.11 9.00 79.11 8 14

21.83 28.66 50.48 1,576,254,872 68.51 9.50 78.01 9 15

21.83 28.66 50.48 1,576,254,872 68.51 9.00 77.51 10 16

21.28 28.66 49.93 1,559,107,302 66.86 9.50 76.36 11 17

21.28 28.66 49.93 1,559,107,302 66.86 9.00 75.86 12 18

17.71 28.67 46.38 1,407,012,565 56.21 9.50 65.71 13 19

17.71 28.67 46.38 1,407,012,565 56.21 9.00 65.21 14 20

8.91 25.13 34.04 955,692,708 19.18 11.25 30.43 15 21

8.91 25.13 34.04 955,692,708 19.18 11.25 30.43 16 22

5.40 27.12 32.52 964,884,350 14.61 12.50 27.11 17 23

5.36 27.12 32.47 963,604,697 14.49 12.50 26.99 18 24

5.20 27.12 32.32 958,937,697 14.01 12.50 26.51 19 25

5.16 27.12 32.27 957,658,045 13.88 12.50 26.38 20 26

1.97 25.26 27.22 744,327,225 ‐1.27 11.25 9.98 21 27

1.97 25.26 27.22 744,327,225 ‐1.27 11.25 9.98 22 28

0.42 25.99 26.41 783,299,141 ‐3.71 12.50 8.79 23 29

0.35 25.99 26.33 781,094,286 ‐3.94 12.50 8.56 24 30

0.03 25.99 26.02 771,838,232 ‐4.87 12.50 7.63 25 31

‐0.04 25.99 25.95 769,633,377 ‐5.10 12.50 7.40 26 32

0.09 25.26 25.34 692,982,797 ‐6.90 11.25 4.35 27 33

0.09 25.26 25.34 692,982,797 ‐6.90 11.25 4.35 28 34 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 23 of 210 A.2: Stage 2 Scores and Ranking Based on NG Qualitative Scores 83C_II Stage 2 Results Summary 2019_10_22.xlsx D.P.U. 20-16/20-17/20-18 1 of 2 5b Result Summary NG Exhibit JU-4 Page 24 of 210 ABCDEFGHIJ 1 83C_II Stage 2 Results 2 Ranking Set All Proposals <‐ Dropdown 3 Qualitative score NG Pts <‐ Dropdown 4 Quantitative points scaling 83C_II <‐ Dropdown 5 Results as of 10/22/2022 Remuneration Sub total ‐ Direct Sub total ‐ Direct Contract Proposal Net Cost @ 2.75% Benefit of Proposed Annual Tranche 1 PPA Tranche 1 PPA ISO‐NE Load Cost of Proposal Proposal Identifier Maximum Capacity Direct Cost of Proposal Energy Delivery (MWh) Start Date End Date Zone Energy + RECs Amount (MW) Factor (%) PPA + RECs (2019$/MWh) 6 (2019$/MWh) (2019$/MWh)

MFW_800_CA_Fixed 804.0 9/1/2025 8/31/2045 SEMA 58.47 1.61 84.06 7

34 83C_II Stage 2 Results Summary 2019_10_22.xlsx D.P.U. 20-16/20-17/20-18 2 of 2 5b Result Summary NG Exhibit JU-4 Page 25 of 210 ABKLMNOPQR 1 83C_II Stage 2 Results 2 Ranking Set All Proposals 3 Qualitative score NG Pts 4 Quantitative points scaling 83C_II 5 Results as of 10/22/2022

MFW_800_CA_Fixed 804.0 23.99 28.66 52.65 1,643,796,934 75.00 10.00 85.00 1 7

23.44 28.66 52.10 1,626,718,357 73.36 10.00 83.36 2 8

23.99 28.66 52.65 1,643,796,934 75.00 8.00 83.00 3 9

22.91 28.66 51.56 1,610,025,903 71.76 10.00 81.76 4 10

23.44 28.66 52.10 1,626,718,357 73.36 8.00 81.36 5 11

22.36 28.66 51.02 1,592,912,830 70.11 10.00 80.11 6 12

22.91 28.66 51.56 1,610,025,903 71.76 8.00 79.76 7 13

21.83 28.66 50.48 1,576,254,872 68.51 10.00 78.51 8 14

22.36 28.66 51.02 1,592,912,830 70.11 8.00 78.11 9 15

21.28 28.66 49.93 1,559,107,302 66.86 10.00 76.86 10 16

21.83 28.66 50.48 1,576,254,872 68.51 8.00 76.51 11 17

21.28 28.66 49.93 1,559,107,302 66.86 8.00 74.86 12 18

17.71 28.67 46.38 1,407,012,565 56.21 10.00 66.21 13 19

17.71 28.67 46.38 1,407,012,565 56.21 8.00 64.21 14 20

8.91 25.13 34.04 955,692,708 19.18 10.00 29.18 15 21

8.91 25.13 34.04 955,692,708 19.18 10.00 29.18 16 22

5.40 27.12 32.52 964,884,350 14.61 11.50 26.11 17 23

5.36 27.12 32.47 963,604,697 14.49 11.50 25.99 18 24

5.20 27.12 32.32 958,937,697 14.01 11.50 25.51 19 25

5.16 27.12 32.27 957,658,045 13.88 11.50 25.38 20 26

1.97 25.26 27.22 744,327,225 ‐1.27 10.00 8.73 21 27

1.97 25.26 27.22 744,327,225 ‐1.27 10.00 8.73 22 28

0.42 25.99 26.41 783,299,141 ‐3.71 11.50 7.79 23 29

0.35 25.99 26.33 781,094,286 ‐3.94 11.50 7.56 24 30

0.03 25.99 26.02 771,838,232 ‐4.87 11.50 6.63 25 31

‐0.04 25.99 25.95 769,633,377 ‐5.10 11.50 6.40 26 32

0.09 25.26 25.34 692,982,797 ‐6.90 10.00 3.10 27 33

0.09 25.26 25.34 692,982,797 ‐6.90 10.00 3.10 28 34 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 26 of 210

Protocol for 83C II Quantitative Metric Calculations, Stage 2

B.1: Protocol for 83 II Quantitative Metric Calculations D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Stage 2 Quant Protocol incl Attach A and B 2019-08 21 v5.docx Page 27 of 210 Deliberative Policy Confidential Protocol for 83C II Quantitative Metric Calculations, Stage 2

This document describes the quantitative metrics and multi-year net present value (NPV) cost/benefit analysis the evaluation team will use in Stage 2 to evaluate each of the proposals received in response to the Request For Proposals for Long-Term Contracts for Offshore Wind Energy Projects issued May 23, 2019 (“83C II RFP”). The inputs to many of those metrics will be drawn from the results of the analytic tool ENELYTIX licensed by Tabors Caramanis Rudkevich (TCR) to perform economic analyses of a Base Case and each proposal case.

1. The ultimate Stage 2 quantitative unit of comparison of proposals In Stage 2 the core quantitative measure of comparison will be the levelized net unit benefit per MWh for each proposal calculated in 2019 dollars (2019$) over a study period of 2022 to 2049.1 A bidder may offer less than the entire energy output from the capacity (MW) of an offshore wind energy project that is dedicated to a proposal but must offer all the Renewable Energy Certificates (“RECs”) associated with those MWs. For bids that offer more RECs than MWh of energy, the number of RECs will be used in the levelized net unit per MWh calculation. Each proposal will be evaluated based on the simulated energy and RECs from 800 MW of offshore wind capacity consisting of the capacity specified in the bid for the offshore wind project (“OSW project” or “Proposal”) plus, as needed, a proxy unit sized to supplement the bid capacity to total to the 800 MW.

2. The financial parameters to be used in the comparison of proposals  Discount rate (nominal) – 7.15%  Rate of inflation 2%2  Discount rate (real based on $2019) – 5.05%

3. Allocation of the 75 quantitative points 1. Assign 75 points to the proposal with the highest levelized net benefit per MWh (“top bid).3 2. For each other bid, subtract 3.0 points for each $1.00/levelized net benefit per MWh that the bid has a levelized net benefit per MWh that is less favorable than that of the top bid.

4. Analytical approach per 83C II RFP requirements Under the 83C II RFP, the Massachusetts Distribution Companies are seeking to procure at least 400 MW of Offshore Wind Energy Generation capacity, and up to a maximum of 800 MW.

1 Assumes 2022 is earliest COD. RFP says 2027 is latest COD of a bid project; and 2029 is latest COD of a proxy Tranche 2 proxy unit where the bid project is less than 800 MW. 20 years is longest contract. The ENELYTIX modeling system will be used to calculate values for 2022 through 2046. Values for 2047, 2048 and 2049 will be held at 2046 levels. 2 2% is consistent with assumptions in AESC 2018, inflation rates projected in the WEO 2019, OECD 2019, CBO 2019) and assumptions in EIA AEO 2019 3 Under a circumstance in which the Evaluation Team believes the bid with the highest levelized net benefit is an outlier, i.e., the net benefit per MWh of the bid is unreasonably different compared to that of the other bids, the Evaluation Team with unanimous agreement of all members and with input from the Independent Evaluator may award that bid an appropriate number of points, which will be the highest ranked bid, and award 75 points to the second highest bid. Scores of all other bids will then be relative to the second highest bid.

1 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Stage 2 Quant Protocol incl Attach A and B 2019-08 21 v5.docx Page 28 of 210 Deliberative Policy Confidential

Section 2.2.1 requires bidders to submit a proposal with 400 MW generation capacity and delivery facilities comprising generator lead line(s) and all associated facilities required for delivery from the Offshore Wind Energy Generator directly to the corresponding onshore ISO-NE PTF system facilities. Proposed pricing for energy and/or RECs must be designed to recover all costs associated with the proposal, including but not limited to the cost of offshore wind generation, cost of Offshore Delivery Facilities, cost of network upgrades, and, if applicable, energy storage.

Section 2.2.1 also allows eligible bidders to submit additional alternative proposals with a nameplate capacity of no less than 200 MW and no greater than 800 MW.

The types of 83C_II proposals the 83C Quantitative team may receive based upon those sections are:

Type A. 400 MW Type B. x MW (200 MW ≤ x < 400 MW) Type C. y MW (400 MW < y ≤ 800 MW) Summary of Proposed Analytical Approach

As specified in Section 2.3.1 of the 83C_II RFP, the Stage 2 quantitative analysis will determine the Direct Contract Costs and Benefits of each Proposal as well the Other Costs and Benefits to Retail Customers of each Proposal.

 Direct Contract Costs and Benefits will be determined primarily from specifications in the proposals as received (bid) and outputs from modeling of the proposal using ENELYTIX4 (i.e. the ‘Proposal Case’).

 Other Costs and Benefits to Retail Customers will be determined by comparing the ENELYTIX results for the ‘Proposal Case’ to the ENELYTIX results for the 83C II ‘Base Case’. The 83C II ‘Base Case’ is a “but for” scenario that assumes no acquisition of any offshore wind power from this solicitation.

TCR will calculate each category of costs and benefits by year for each proposal in an excel spreadsheet model (“quantitative spreadsheet model”) for that proposal using the proposal’s bid prices and quantities and the results of its ENELYTIX modeling of the Proposal Case and Base Case, bidder responses to Evaluation Team questions and from other assumptions noted below.

5. Modeling Approach TCR will run the ENELYTIX model to establish a set of reference market conditions absent the selection and development of any proposal received in response to this 83C II RFP, “the Base case”. TCR will also utilize ENELYTIX to model each Proposal Case to determine physical outputs and market prices such as projections of the annual quantities of energy and RECs that the Proposal will generate by year. TCR will carry these results forward to its quantitative spreadsheet model for the Proposal which it uses to

4 ENELYTIX modelling of each Proposal is used to determine relevant physical outputs and market prices such as projections of the annual quantities of energy and RECs that the Proposal will generate by year, the market prices for those products, and carbon emissions.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Stage 2 Quant Protocol incl Attach A and B 2019-08 21 v5.docx Page 29 of 210 Deliberative Policy Confidential determine the net benefits (benefits minus costs) for each Proposal. The quantitative spreadsheet model will calculate the NPV of the Proposal’s annual costs and benefits as well as the levelized net unit benefit per MWh of generation of the Proposal. ENELYTIX Modeling Assumptions

The Base Case assumes the EDCs do not select any offshore wind capacity in this, or subsequent, solicitations. The ENELYTIX modeling report describes the ENELYTIX input and modeling assumptions in detail.

Each Proposal Case will assume the EDCs ultimately acquire 800 MW of new offshore capacity consisting of the MW from the bid they select in this solicitation and (if the Proposal being analyzed offers less than 800 MW) the MW from a proxy unit to be acquired from a future solicitation. The 800 MW of new offshore capacity in each Proposal Case will consist of up to two Tranches, the OSW project bid and (if necessary) a proxy unit. Tranche 1 will be the OSW project capacity, performance and COD modeled as specified in the bid for the OSW project (“Tranche 1 OSW project bid”). If the Proposal capacity is less than 800 MW, Tranche 2 will be a proxy unit (“Tranche 2 proxy unit”) sized to supplement the Tranche 1 OSW project bid capacity in order to achieve a total of 800 MW.

This approach enables the evaluation to consider the opportunity costs and benefits of procuring greater than 400 MW in this solicitation as compared to the anticipated costs and benefits of procuring the installed capacity through a future solicitation, as contemplated in 83C_II RFP Section 2.3.1.2.iii.

The characteristics of the Tranche 2 proxy unit will be developed from the most favorable Tranche 1 OSW project bid. The most favorable Tranche 1 OSW project will be the 400 MW bid with the lowest unit cost of energy and RECs or, at the end of Stage 2, the highest ranked 400 MW bid, if different. Should this be the case the unit cost value of this highest ranked Tranche 1 unit will be applied to the full 400MW of the proxy unit.

The key assumptions for the Tranche 2 proxy unit are listed below.

 The commercial online date of the Tranche 2 proxy unit will be the later of 1/1/2026 or 2 years from the COD of the most favorable Tranche 1 OSW project bid.  The tranche 2 proxy unit will interconnect with the ISO-NE system at the aggregate SEMA/RI node.5  The capacity factor of the Tranche 2 proxy unit will be developed from the capacity factor of the most favorable Tranche 1 OSW project bid by applying an assumed compound annual improvement rate of 0.27%.6 This capacity factor improvement assumption is based on an analysis of projected capacity factors of offshore wind Technology Resource Groups (TRGs) 1 to 5 in the NREL Annual Technology Baseline 2018.

5 The aggregate SEMA/RI node will evenly distribute energy from offshore projects across all load centers in the Southeast Massachusetts (SEMA) and Rhode Island (RI) ISO-NE energy areas. 6 NREL (National Renewable Energy Laboratory). 2018. 2018 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. http://www.nrel.gov/analysis/data_tech_baseline.html.

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 The Tranche 2 proxy unit price will be the sum of the energy and REC prices of the most favorable Tranche 1 OSW project bid minus $0.01 per MWh in levelized 2019 dollars to be consistent with the price cap.  The Tranche 2 proxy unit production shape will be the same as the hourly production shape of the most favorable Tranche 1 OSW project bid.  The Tranche 2 proxy unit will have the same percent of nameplate capacity contribution to capacity markets as the most favorable Tranche 1 OSW project bid.

The ENELYTIX modeling report describes the input and modeling assumptions that are common to the Base case and each Proposal Case.

TCR expects to develop a common capacity expansion plan for all 83C_II Proposals because of the anticipated similarity of each Proposal Case in terms of contributions to Installed Capacity Requirements and capacity factors. Attachment B describes the rationale for this approach.

6. Criteria for evaluation and the procedure for their calculation The 83C II RFP specifies two categories of quantitative evaluation criteria or metrics, Direct Contract Costs & Benefits and Other Costs and Benefits to Retail Customers. This section describes the calculation procedure, and information sources, for each of those criteria. A. CALCULATION OF DIRECT COSTS & BENEFIT METRICS 1. A mark-to-market comparison of the price of any eligible Offshore Wind Energy Generation under a contract to projected market prices at the delivery point with the project in-service. a. Calculate the annual market value ($) of energy delivered by the Proposal at the delivery node(s) over the proposal contract period accounting for contract delivery conditions. Annual market value ($) equals the sum over the year of the quantity of energy delivered at nodes in each hour of year times hourly Locational Marginal Prices (LMPs) at the node.

b. Calculate the annual cost ($) of energy from the proposal over the proposal contract period accounting for contract delivery conditions (peak, off-peak, etc.) and bid prices.

c. Calculate the annual net benefit of the energy from the proposal as the market, LMP-based value of energy from the proposal at the point of delivery minus the annual cost ($) of energy from the proposal (step A.1.a results minus step A.1.b results). 2. Comparison of the price of any Renewable Portfolio Standard (“RPS”) Class I eligible RECs under a contract to: i. the avoided cost with the project not in-service if the RECs are to be used for RPS and Clean Energy Standard (“CES”) compliance by the Distribution Companies or Massachusetts retail electric suppliers; and ii. their projected market prices with the project in-service if the RECs are projected to be sold. a. For each year, calculate the MA Class 1 RPS and MA CES compliance obligation of the distribution service retail load served by Massachusetts Electric Distribution Companies (EDCs).

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b. Identify the Class 1 RECs7 and Clean Energy Credits (“CECs)8 that MA EDCs are holding or will hold under long-term contracts in each year. (These are MA EDC existing contracts from pre 83D solicitations, the contract for 800 MW with Vineyard Wind and the 83D contract with NECEC).

c. Calculate over the contract proposal period the direct annual cost of the proposal’s Class 1 RECs as the annual quantity of the proposal RECs times the proposal’s annual bid price for RECs

d. Calculate over the contract proposal period the MA Class 1 RPS and MA CES compliance obligation that could be met with the Class I RECs from the Proposal, i.e. the RPS and CES Gap. (RPS and CES Gap = Step A.2.a minus Step A.2.b)

e. Calculate over the contract proposal period the direct annual dollar benefit of proposal RECs used for MA Class 1 RPS and MA CES compliance obligation (the lesser of the proposal RECs or the RPS and CES Gap) as the avoided cost of meeting that obligation at the market price of Class 1 RECs/CECs in the Base Case (direct annual dollar benefit of proposal RECs used = Proposal RECs used to meet the MA Class 1 RPS and MA CES compliance obligation * Base Case REC Market Price).

f. Calculate over the contract proposal period the direct annual dollar benefit of proposal RECs sold as the remaining proposal RECs not used for MA Class 1 RPS and MA CES compliance times the market price of Class 1 RECs in the Proposal Case. (direct annual dollar benefit of proposal RECs sold = (Proposal RECs – Proposal RECs used to meet MA compliance) * Proposal Case Market Price for REC or CEC whichever is higher)

g. Calculate the total net direct benefit of RECS as the sum of Steps A.2.e and A.2.f minus step A.2.c. 3. Calculate Total direct net benefits of the Proposal as the sum of A.1.c and A.2.g

B. CALCULATION OF OTHER COST & BENEFIT METRICS9 1. Impact of changes to the Locational Marginal Price ("LMP") paid by ratepayers in the Commonwealth. a. For the Proposal case, calculate the annual market value ($) of energy supplied to Massachusetts retail customers in each year starting from the contract proposal start date through the end of the study period, 2049. The annual market value of energy equals the sum over the year of the quantity of energy supplied in each Massachusetts load zone (SEMA, WCMA and NMABO) in each hour of year times hourly LMPs in each load zone.

7 Class 1 RECs may be used for either MA RPS or MA CES compliance. 8 CECs from the selected 83D project may only be used for CES compliance, not RPS. 9 The Evaluation Team determined that the indirect impacts of Proposals on capacity or ancillary service market prices were not reliably quantifiable and therefore did not include those impacts in the evaluation.

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b. Adjust the Proposal case annual market value of energy by the proportion of MA EDC distribution service retail load to total load in each Massachusetts load zone. The result is the zonal LMP-based total cost of energy to MA EDC distribution service customers in the Proposal case.

c. For the Base case, calculate the annual market value of energy supplied to ratepayers in each year starting from the contract proposal start date through the end of the study period, 2049. Annual market value of energy equals the sum over the year of the quantity of energy supplied in each Massachusetts load zone (SEMA, WCMA and NMABO) in each hour of year times hourly LMPs in each load zone.

d. Adjust the Base case annual market value of energy by the proportion of MA EDC distribution service retail load to total load in each Massachusetts load zone. The result is the zonal LMP- based total cost of energy to MA EDC distribution service customers in the Base case.

e. Calculate the gross energy market price change impact of the Proposal on the total cost of energy to MA EDC distribution service customers as the Base Case cost of energy to EDC distribution customers from B.1.d minus the Proposal case cost of energy to EDC distribution customers from B.1.b.

f. Calculate the change in the aggregate market value of energy from all EDC contracts in the Base Case, i.e., without the OSW project in service. The change in market value of each EDC contract equals the quantity of energy from that contract at the delivery node in each hour of year multiplied by the difference between the hourly LMP at that node in the Base case and in the Proposal Case for the respective terms of the EDC contracts.

g. Calculate the net energy market price change impact of the Proposal for the starting from the contract proposal start date through the end of the study period, 2049 on the total cost of energy to MA EDC distribution service customers by adding the change in the aggregate market value of energy from all EDC contracts in the Base Case from B.1.f. to the gross energy price change impact from B.1.e. 2. Impact on RPS and/or CES compliance costs paid by ratepayers in the Commonwealth a. For the Proposal Case calculate the annual quantity of Class 1 RECs that will be acquired from the market to meet the RPS / CES requirement associated with EDC distribution service. This quantity equals the total quantity required for compliance minus the aggregate quantity from EDC contracts in the Base Case and minus the quantity supplied from the Proposal.

b. Calculate the REC market price change under the Proposal Case ($MWh) as the REC market price in the Base Case minus the REC market price in the proposal Case.

c. Calculate the REC market price change impact of the Proposal as the annual quantity of Class 1 RECs that will be acquired from the market, from B.2.a, multiplied by the REC market price change from B.2.b starting from the contract proposal start date through the end of the study period, 2049.

6 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Stage 2 Quant Protocol incl Attach A and B 2019-08 21 v5.docx Page 33 of 210 Deliberative Policy Confidential 3. Impact of the Proposal on the Commonwealth’s ability to meet Global Warming Solutions Act (GWSA) requirements in excess of compliance with the RPS and the CES. a. Calculate the Incremental Inventory Impact in MWh per Attachment A starting from the contract proposal start date through the end of the study period, 2049.

b. Subtract the quantity (MWH) of Class 1 RECs used for MA RPS or CES compliance by each Proposal Case from the Inventory Impact (MWh).

c. Calculate the incremental benefit ($) by multiplying the result from B.3.b by $17.22 2019$/MWh.10 11 4. Impact of a change in Proposal PPA market value in a year with extreme winter gas prices. a. Calculate the 3-month average of the daily spot Algonquin Citygate (AGC) gas prices for historical winter periods (December – February) for each year 2002 through 2019. 12

b. Identify the winter periods with the highest average AGC price and the lowest AGC price. .

c. Compute the average of all historic winter AGC prices, 2002 through 2019. Calculate the highest and lowest historical winter average AGC price as a percentage over or under the historic average winter AGC price.

d. Compute the ratio of the total historic gas consumption (MMBtu) for the winter of the highest average AGC price to the total gas consumption December through February for the modeled winter 2029/2030 period assuming Proposal Case resources. Compute this same ratio for the winter of the lowest average AGC price. 13 e. Adjust the percentage over/under the average for the highest and the lowest historic winter average AGC price by the fuel consumption ratios computed in step 4d. Apply the adjusted gas price over/under factors (high and low) to derive high and low winter gas prices for the three winter months in the 2029/2030 power year.

10 $17.22 2019$/MWh is $16.51 /MWh, the unit value of the incremental inventory impact used in the 83C_I evaluations expressed in 2019$/MWh. 11 “National Grid’s concerns with the methodology and compliance value used in the calculation of the GWSA compliance contribution benefits by DOER, Eversource, and Unitil were set out in detail in its response to Information Request DPU-5-12 in the 83C Round 1 solicitation, Joint Petition of NSTAR Electric Company et al., D.P.U. 18-76/77/78, and in its response to Information Request DPU-2-14 in the 83D solicitation, Joint Petition of NSTAR Electric Company et al., D.P.U. 18-64/65/66. Despite these concerns, National Grid does not intend to sponsor a separate, alternative GWSA net benefit calculation in the current solicitation. This is because National Grid does not believe that the differences between its own version of the GWSA calculation (described in the Information Request responses cited above) and the DOER/Eversource/Unitil version will be material under the particular facts and circumstances of the current 83C Round 2 solicitation. In the event that, contrary to National Grid’s expectation, the calculated GWSA compliance contribution benefits appear to have a material impact on the ranking of bids or portfolios, National Grid may consider it appropriate to exclude this impact from its own evaluation and/or rankings, perhaps as part of the Stage 3 evaluation.” 12 This is the period for which published statistics are available. 13 This ratio is a scaling factor to reduce the magnitude of the historical extreme variation to reflect the reduction in pipeline constraints in the Proposal Case relative to the historical period due lower gas use.

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f. Calculate the value of the energy ($) delivered by the project in the Proposal Case for the three winter months in the 2029/2030 power year assuming Proposal Case resources and Base Case fuel prices. Calculate the value of the energy delivered by the proposal using the adjusted high14 and adjusted low winter gas prices assuming Proposal Case resources.

g. Calculate the percentage changes in the annual proposal contract market value in a year with the adjusted high and low winter gas prices. These percentages equal the energy cost to MA consumers in the 2029/2030 winter under the respective high and low winter gas price scenarios assuming Proposal Case resources divided by the annual energy cost to MA consumers in the 2029/2030 power year under the Proposal Case.

h. Calculate the net percentage change due to extreme winter prices as the high winter gas price percentage change minus the absolute value of the low winter gas price percentage change.

i. Divide the percentage change in the proposal PPA market value in a year with extreme winter gas prices from B.4.h by 20 (the maximum contract period). Apply that percentage to the annual value of the PPA in each year over the contract proposal period. (This approach reflects the uncertainty regarding the specific year in which an extreme winter gas price event might occur during the study period.) 5. Total indirect net benefits of the Proposal a. Calculate the annual sum of the indirect benefits as the sum of B.1.g, B.2.c. B.3.c, and B.4.i. C. CALCULATION OF PROPOSAL TOTAL QUANTITATIVE BENEFITS 1. Calculate the annual sum of the direct and indirect benefits as A.3 plus B.5.a. 2. Calculation of the total net unit benefit of the proposal: a. Compute the present value of the annual direct costs, direct benefits, and indirect benefits in $2019. Discount to 2019 reference year at the real discount rate. b. Compute the present value of the net benefit as the sum of the present values of direct benefits and indirect benefits, less the present value of direct costs. c. Compute the present value of the annual MWh of energy delivered to the system from the Proposal (i.e. OSW project as bid and proxy unit as appropriate) consistent with a total of 800 MW. The annual energy quantities should be discounted to 2019 reference year using the real discount rate. d. Divide the result of step 2 by the result of step 3 to compute the levelized unit net benefit for the proposal. This result will be expressed in 2019 constant dollars per MWh.

14 This calculation captures the impact of a Proposal on costs to ratepayers in a year with an extreme winter event (such as a “polar vortex”). This impact is not captured in any of the other evaluation metrics because the projections for hourly load and monthly gas prices used in the Base Case and each Proposal Case reflect normal weather variations by season. The specific timing and magnitude and timing of an extreme winter event, should one occur during the study period, is unknown.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Stage 2 Quant Protocol incl Attach A and B 2019-08 21 v5.docx Page 35 of 210 Deliberative Policy Confidential D. QUANTITATIVE EVALUATION CALCULATIONS Other benefits prior to Proposal PPA. Any difference in prices or emissions between the proposal case and the base case reported for the years prior to the start date of the proposal PPA, or the OSW project COD will be excluded from the calculations. Such differences are idiosyncratic and qualify as ‘noise’ within the modelling environment.

OSW project energy and REC quantities, costs and market value impacts during PPA period. Quantities from, and /or impacts of, OSW projects that start / end during a calendar year will be reported for the relevant partial year periods.

ATTACHMENT A – GREENHOUSE GAS INVENTORY CALCULATIONS ATTACHMENT B - CAPACITY EXPANSION FOR 83C II OSW PROJECT

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Attachment A - GHG Inventory Calculation Protocol

In order to calculate the impact an 83C_II Proposal project (“Proposal”) or a portfolio of Proposals has on GWSA compliance, the Evaluation Team will utilize the following methodology that estimates the Proposal’s or portfolio of Proposals’ impact on the Massachusetts Department of Environmental Protection Greenhouse Gas (GHG) Inventory (“Inventory”). The Evaluation Team will measure the Incremental Inventory Impact of each Proposal and portfolio of Proposals relative to the 83C_II Base Case.15 The Impact of a Proposal will equal the impact of the proposed Project plus, for Projects smaller than 800 MW, that of a proxy unit (“Proxy”) sized to supplement the Project capacity to total 800 MW.

The methodology uses a GHG Inventory spreadsheet model (GHG workbook) to capture the two major types of GHG emission impacts an 83C_II Proposal has on Massachusetts. First, it captures the changes in emission rates of grid energy generated in Massachusetts and/or imported into Massachusetts caused by the expected dispatch of the 83C_II proposal. Second, it captures the inventory impacts caused by the renewable energy credits (RECs) from the 83C_II proposal that are used to comply with state renewable portfolio standards (RPS) and/or the Massachusetts Clean Energy Standard (CES) as well those that are retired solely for GWSA compliance. The way the Proposal’s RECs are modeled in each year is a function of market conditions and current law and regulation for compliance in Massachusetts and the other New England states. In particular, the RPS and CES mechanisms each rely on markets, as well as alternative compliance payments (ACPs), to incentivize new project development and retirements.

The Evaluation Team will use the GHG workbook to determine the impact of each 83C_II Proposal on the Inventory on a level playing field regardless of the specific 83C_II energy resource. This methodology will produce the following eight major outputs by year for the period 2022 to 2049:

1. RECs from Project (MWh) used towards Massachusetts RPS contract gap.16 2. RECs from Proxy resources, if applicable (MWh) used towards Massachusetts RPS contract gap. 3. RECs from Project (MWh) used towards Massachusetts incremental CES contract gap 4. RECs from Proxy (MWh) used towards Massachusetts incremental CES contract gap 5. Residual quantity of RECs (MWh) purchased at market prices to comply with Massachusetts RPS and/or incremental CES

15 The Base Case Model amount does not represent the full implementation of all 2015 GWSA CECP 2020 Update policies and the associated Inventory results should not be interpreted as a prediction of electric sector emissions. Instead, the Base Case Inventory result is used only to determine the impact of a Proposal or a portfolio of Proposals on the electric sector. 16 Massachusetts RPS contract gap equals the total quantity of RECs required to comply with the Massachusetts RPS in a year minus the quantity of non-Proposal RECs under contract to comply with Massachusetts RPS in that year. Massachusetts incremental CES contract gap equals the total quantity of Clean Energy Certificates (CECs) required to comply with the Massachusetts CES requirements in a year incremental to the RPS minus the quantity of non-Proposal CECs under contract including the CECs from the selected 83D resource to comply with incremental Massachusetts CES in that year.

A-1

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6. RECs from Project (MWh) sold out of state. 7. RECs from Proxy (MWh) sold out of state. 8. GWSA compliance contribution (GHG Inventory Impact) of Proposal (MWh). For each proposal and portfolio, those outputs from the GHG workbook will be inputs to the quantitative spreadsheet model that produces outputs used to determine the Direct Benefits and Indirect Benefits as well as the associated incremental GWSA compliance benefit of the Proposal or portfolio.

A. GHG Workbook Inputs and Assumptions

The Inventory Impact of a Proposal is ultimately calculated as a delta between the GHG inventory for that Proposal’s Case and the GHG inventory for the 83C_II Base Case. The team will use the GHG workbook to calculate the GHG inventory for each Proposal Case and for the 83C_II Base Case using outputs from ENELYTIX modeling of those Cases (“the Model”) as well as a set of inputs common to each Case. The GHG workbook will calculate the forecast GHG Inventory for each Case in million metric tons CO2e (“MMT CO2e”) for every year between 2022 and 2049.17

The GHG workbook calculation will use the following outputs from the Model. Unless noted, the outputs come from the Model’s E&AS module.

 Annual Generation (MWh): The total generation in each New England (NE) state, not counting behind-the-meter PV (which is reflected in Annual Load)  Annual Seabrook Generation and Annual Millstone Generation (MWh)  Imports (MWh) from NY, Quebec, and New Brunswick/PEI (“external control areas”): The Base Case assumes imports remain constant at the levels specified in the Base Case assumptions. A Proposal Case may assume imports increase over Base Case levels if the Proposal includes an increase in imports from external control areas  Annual Total RECs Produced: The number of RECs produced in each NE state and external control area that are retired annually in New England18  Annual 83C_II Proposal RECs Produced: The number of RECs produced in each NE state and external control area by the Proposal or portfolio of proposals

17 Assumes 2022 is earliest COD. The RFP says 2027 is the latest COD of a bid project; 2029 is the latest COD of a Tranche 2 proxy unit where the bid project is less than 800 MW; 20 years is longest contract. The Model will be used to calculate values for 2022 through 2046; values for 2047, 2048 and 2049 will be held at 2046 levels. 18 The quantities of Annual Total RECs imported from each external control area are adjusted slightly so that the regional REC supply is consistent with the RPS and CES supply and demand conditions as indicated by outputs of the Model’s capacity expansion module (REC and CEC prices, and ACP quantities required to comply with all states’ RPSs and the Massachusetts CES). These small differences exist because the Model’s E&AS module, unlike the capacity expansion module, does not enforce RPS and CES constraints. The quantities of Annual Total RECs imported from external control areas are also reallocated among areas as needed to ensure that the quantity of RECs imported from any one external area does not exceed the energy imported from that area—a constraint not enforced in ENELYTIX.

A-2

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 Annual Non-Biogenic Emissions (metric tons CO2e): Emissions from non-biogenic fuel, per Table 1, for each generator in each NE state  Annual REC Price ($/MWh): The REC price projected by the Model’s capacity expansion module19  Annual CEC Price ($/MWh): The price for Massachusetts Clean Energy Certificates projected by the Model’s capacity expansion module  Annual Regional RPS ACP Quantity (MWh): The total quantity of all NE states’ RPS requirements minus total RECs produced, when that difference is positive. This quantity is projected by the Model’s capacity expansion module.  Annual Massachusetts CES ACP Quantity (MWh): The quantity by which the incremental CES requirement is projected to exceed the attributes used to meet it. This value is projected by the Model’s capacity expansion module.  Annual Non-Proposal RECs under Long-Term Contract to Massachusetts EDCs: The number of RECs produced in each NE state and external control area by resources (or portions of resources) that are under long-term contract to Massachusetts EDCs. The GHG workbook will use the following assumptions in addition to those used in ENELYTIX modeling. These quantities are the same for all cases, with details provided in Tables 2 through 5.

 State loads (MWh). The generation required to supply the retail load of each state in each year.  Annual Environmental Attributes (EAs) produced by 83D resources: The non-Class 1 clean energy produced in each NE state and external control area by 83D resources expected to be under long-term contract to Massachusetts EDCs and potentially eligible for compliance with the Massachusetts Clean Energy Standard.  Annual RECs produced by 83C_I resources.  MMWEC ownership/contract share of Millstone Nuclear Power Station output and Seabrook Nuclear Power Station output, by year.  Connecticut EDC contract share of Seabrook Nuclear Power Station output (14.7899% through 2029).  Emission rates for imports from external control areas (lbs. CO2e/MWh): Emission rates for imports from Quebec and New Brunswick / Prince Edward Island will remain constant at the levels in the 2017 Massachusetts Department of Environmental Protection (MassDEP) Greenhouse Gas Baseline, Inventory & Projection. Emission rates for imports from New York vary by year and are determined as described below.  2018 REC Oversupply Allocation: The percentage of unsettled and reserved certificates in the NEPOOL GIS system that are eligible for the states’ Class or Tier 1 RPS (as reported to state regulators for 2018).20 These quantities are used in the calculation of the Annual REC Oversupply Allocation.

19 Annual REC and CEC prices are used solely in the adjustment of Annual Total RECs imported from each external control area, as described in footnote 18. 20 These certificates were not retired for compliance for any Class or Tier 1 RPS but were included in the MassDEP Greenhouse Gas Inventory calculation.

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Emission rates for imports from New York are determined as follows:

a. For all years in the analysis time horizon, the emission rates for New York in pounds of CO2 per MWh are calculated as the total emissions for the year divided by the total generation for the year. b. For 2022 through 2025, the emissions for New York are determined using the Base Case ENELYTIX run. For 2022, this run will not include the Empire and Sunrise New York offshore wind projects. For the 2024 run, the Sunrise project is assumed to be operational beginning in May and Empire is assumed to be operational beginning in December. For 2025, both projects are assumed to be operational for the entire year. c. The 2030 emissions goal of the New York State Climate Leadership and Community Protection Act (“Act,” S.6599/A.8429), signed into law on July 18, 2019, is a reduction of 40% below 1990 levels.21 Based on the New York State Greenhouse Gas Inventory,22 this is equivalent to a 34.45% reduction below 2015 levels. d. For 2026-2030, the emissions for New York electricity generation are determined using a linear interpolation between the emissions determined for 2025 and a 2030 value of 34.45% below the 2015 emissions level. e. For 2031-2040, the emissions for New York are determined using a linear interpolation between the 2030 value and the Act’s 2040 goal of zero emissions.

B. GHG Workbook Outputs

Outputs 1 through 4 — Project and Proxy RECs retired for compliance with Massachusetts RPS and/or CES23

RECs from Proposals in each year are accounted as follows:

a. Non-Proposal RECs under contract to the Massachusetts EDCs are subtracted from their Massachusetts RPS requirement. b. Non-Proposal EAs under contract to the Massachusetts EDCs are subtracted from the Massachusetts incremental CES requirement. c. Project RECS. If there is a remaining RPS gap, Project RECs are deemed to be retired for the Massachusetts EDCs’ compliance with the Massachusetts RPS (including offsetting Massachusetts competitive suppliers Massachusetts RPS obligations). If the gap is less than the Project RECs, then the quantity of Project RECs retired for compliance with the

21 !990 emissions levels for the electricity sector are specified in the New York State Greenhouse Gas Inventory: 1990–2015, Final Report, Revised September 2018, Table S-2. 22 New York State Greenhouse Gas Inventory: 1990–2015, Final Report, Revised September 2018, Table S-2. 23 The Massachusetts RPS and CES requirements discussed throughout include both the requirements of the MA EDCs and those of competitive retail suppliers.

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Massachusetts RPS is the size of the gap. If there are any remaining Project RECs, they are available for compliance with the CES. If there are Project RECs remaining after compliance with the CES, they are available for sale out of state. d. Proxy RECS. If there is a remaining RPS gap, Proxy RECs are deemed to be used for compliance with the Massachusetts RPS (including offsetting Massachusetts competitive suppliers Massachusetts RPS obligations). If there are remaining Proxy RECs, and there is a remaining incremental CES gap, the remaining Proxy Recs are used to comply with the CES. any remaining Proxy RECs are deemed available for sale out of state.24

Output 5 — Residual RECs purchased at market prices for compliance with Massachusetts RPS and CES

If, after applying Proposal RECs to meet the Massachusetts RPS compliance gap, there remains a compliance gap, RECs purchased at market prices will be used for compliance. Those will consist of market RECs from Massachusetts and—if needed—from other NE states and external control areas. In the event of a regional RPS deficiency, the deficiency will be deemed to be consolidated in Connecticut, because that state has the lowest RPS ACP.

If, after surplus RECs have been transferred among states to satisfy RPS deficiencies, a CES compliance gap and a surplus of RECs remain, those RECs (beginning with RECs in Massachusetts) will be used to satisfy the gap.

Outputs 6 and 7 — Project RECs and Proxy RECs sold out of state

In the calculation, out-of-state sales of Proposal RECs can occur only when Massachusetts obligations are satisfied and a surplus (but not regional oversupply) of RECs remains, which is used toward RPS compliance deficiencies in other NE states. If there is a regional oversupply of RECs, an allocation of the regional oversupply will result in all Proposal RECs being retained in Massachusetts, and not sold out of state.

The quantity of Proposal RECs sold out of state in a given year is determined as follows:

a. If the Massachusetts RPS and CES are satisfied and there is a MA REC surplus that includes 83C_II Proposal RECs (and potentially market RECS), referred to here as the “original surplus,” that original surplus is used toward RPS compliance deficiencies in other NE states.

b. If after the transfers of Step a, there is no remaining MA REC surplus, the 83C_II Project and Proxy RECs sold out of state are the quantities of such RECs that had remained after the CES was satisfied.

24 As noted above, Massachusetts RPS and CES requirements discussed throughout include both the requirements of the Massachusetts EDCs and those of competitive retail suppliers. In the calculation, proposal RECs are deemed available for sale out of state only if the entire Massachusetts RPS and CES requirements are satisfied.

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c. If after the transfers of Step a, regional surplus of RECs remains (“remaining surplus”), the difference between the original surplus and the remaining surplus times the proportions of Project and Proxy RECs in the original surplus yield the quantities of Project and Proxy RECs sold out of state.

If there is a regional oversupply of RECs, the allocation of the surplus across states is calculated as follows:

d. The 83C RECs in the regional REC oversupply will be allocated to Massachusetts, and the non- 83C RECs will be allocated among all NE states (as described in Step g).

e. The proportion of 83C RECs in the regional REC oversupply will be the same as the proportion of 83C RECs in the regional REC supply. Divide the total number of RECs produced by 83C_I and 83C_II resources by the total number of RECs produced by all resources to yield the proportion of 83C RECs in the regional REC supply.

f. Multiply the result by the regional REC oversupply to determine the number of 83C RECs in the regional oversupply. Subtract this from the Regional REC oversupply to yield the non-83C REC oversupply.

g. Determine each state's share of the non-83C REC oversupply:

 Each state’s percentage share of the non-83C REC oversupply will be the average of its load share, its share of the 2018 REC oversupply allocation, and the ratio of non-83C RECs produced in the state to non-83C RECs produced in New England.  Multiply these state shares by the total non-83C REC oversupply to yield the number of non- 83C oversupply RECs allocated to each state. To the non-83C RECs allocated to MA, add the 83C RECs in the regional oversupply to yield the total number of oversupply RECs allocated to MA. h. Transfer RECs among states to achieve the total regional oversupply allocation determined in Step g. The transfer into (+) or out of (-) a state will be number of RECs allocated to it in Step g minus its surplus after the transfers of Step a.

Output 8 — GWSA compliance contribution (GHG Inventory Impact)

As the composition of energy generated within and imported into Massachusetts changes each year, one MWh of clean energy will offset a different quantity of emissions.

For the Base Case and each Proposal Case, the overall emission rate for the Inventory in a year will be calculated as pounds of CO2 emitted that year divided by MWh of energy consumed in Massachusetts that year. To express the GHG Inventory Impact of each Proposal Case in MWh, the decrease in metric tons CO2e relative to the Base Case is divided by the Base Case emissions rate (metric tons CO2e/MWh).

A-6 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Quant Protocol Attach A Tables UDATED 2019 08 21 Page 42 of 210 Privileged and confidential

GHG emissions (Metric tons CO2e) are calculated as:

Emissions from Massachusetts generation + Emissions attributed to electricity imports into Massachusetts from other NE states + Emissions attributed to electricity imports from external control areas

Emissions from generation in each NE state are an output of the Model. Emissions from imports from each external control area other than New York are calculated as the product of the quantity of imports from the external control area and a fixed emissions rate for the external control area. Emissions from imports from New York are calculated as above.

For each NE state, generation adjusted for transfers among states and into NE is calculated as:

Total generation in state + Non-MA RECs assigned to MA (≥0 for MA, ≤0 for other states) + 83D EAs assigned to MA (≥0 for MA, ≤0 for other states) + Millstone and Seabrook attributes assigned to MA25 (≥0 for MA, ≤0 for other states) + Seabrook attributes assigned to CT (≥0 for CT, ≤0 for other states) + Surplus RECs transferred into (+) or out of (-) state for RPS or MA CES compliance + Transfers of RECs into (+) or out of (-) state to allocate regional REC oversupply

Adjusted energy imports from each external control area are calculated as:

Energy import from external control area – RECs from area that are assigned to MA - 83D EAs from external area assigned to MA - Transfers of RECs out of external area to allocate regional REC oversupply

To calculate energy transfers from NE states into Massachusetts, i.e., energy imports to Massachusetts, each state’s generation adjusted for transfers among NE states and into NE states from external control areas is compared to its load to determine whether the state has a surplus or shortfall. Generation from external control areas (i.e., imports into NE), as adjusted above, is considered available for transfer. The

25 Millstone attributes are assigned to MA to represent attributes reserved or retired in MA by the Massachusetts Municipal Wholesale Electric Company.

A-7 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Quant Protocol Attach A Tables UDATED 2019 08 21 Page 43 of 210 Privileged and confidential

shortfalls and surpluses are tallied, and the share of total shortfalls attributable to Massachusetts is calculated. The energy transfer from a state or external control area into Massachusetts is then:

푀퐴 푠ℎ푎푟푒 표푓 푡표푡푎푙 푠ℎ표푟푡푓푎푙푙푠 × 퐸푛푒푟푔푦 푡푟푎푛푠푓푒푟 푎푣푎푖푙푎푏푙푒 푓푟표푚 푠푡푎푡푒/푎푟푒푎 푅푎푡푖표 표푓 푡표푡푎푙 푠ℎ표푟푡푓푎푙푙푠 푡표 푎푣푎푖푙푎푏푙푒 푡푟푎푛푠푓푒푟푠

Emissions attributed to energy imports into Massachusetts from each NE state are calculated as:

퐸푚푖푠푠푖표푛푠 푓푟표푚 푔푒푛푒푟푎푡푖표푛 푖푛 푁퐸 푠푡푎푡푒 × 퐸푛푒푟푔푦 푡푟푎푛푠푓푒푟 푓푟표푚 푁퐸 푠푡푎푡푒 푖푛푡표 푀퐴 퐺푒푛푒푟푎푡푖표푛 푖푛 푁퐸 푠푡푎푡푒 푎푑푗푢푠푡푒푑 푓표푟 푡푟푎푛푠푓푒푟푠 푡표/푓푟표푚 표푡ℎ푒푟 푁퐸 푠푡푎푡푒푠 푎푛푑 푖푛푡표 푁퐸 푠푡푎푡푒 푓푟표푚 푒푥푡푒푟푛푎푙 푎푟푒푎푠

Emissions attributed to energy imports into Massachusetts from each external control area are calculated as:

× ( )

C. Portfolio Effect

When multiple projects are run as a portfolio, their benefits may not be additive. The above methodology for individual Proposals will also be applied to Portfolios to determine the direct and other benefits of Portfolios in Stage Three.

A-8 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 83C II Quant Protocol Attach A Tables UDATED 2019 08 21 Page 44 of 210 Privileged and confidential

TABLE 1. Biogenic and Non-biogenic Fuels

Non-Biogenic bituminous coal sub-bituminous coal distillate petroleum natural gas non-biogenic component of municipal solid waste Other tire derived fuel petroleum coke residual petroleum jet fuel Kerosene waste oil

Biogenic landfill gas biogenic component of municipal solid waste black liquor wood/wood waste solids sludge waste

Source: Massachusetts Department of Environmental Protection, Greenhouse Gas Baseline, Inventory & Projection Appendix S: 2016 Emissions from Electricity Consumed in Massachusetts (https://www.mass.gov/files/documents/2016/11/rk/gwsa- appq.xls)

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TABLE 2. State Loads (GWh)

Source: Gross-PDR Annual Energy Forecast (Table from 83C II Base Case Assumptions) minus forecast of Behind-the-Meter Solar PV

TABLE 3. EAs under Long-term Contract to Massachusetts EDCs (MWh)

Source: TCR analysis based on estimated 83D resource output

A-10 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 46 of 210

Table 4. Emission Rates for Imports from Canada (lbs. CO2e/MWh)

Emission Rates, lb CO2e/MWh Quebec 2.81 NB / PEI 693.57

Source: [NEED CITE FROM DOER]

Table 5. 2018 REC Oversupply Allocation

State 2018 REC Oversupply Allocation Massachusetts 37.2% Maine 57.4% New Hampshire 1.4% Vermont 1.7% Rhode Island 0.2% Connecticut 2.1% Source: NEPOOL 2018 Unsettled and Reserved Certificate State Regulator Reports, as summarized by Massachusetts DOER. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 47 of 210

Attachment B – Capacity Expansion for 83C_II OSW projects

This memo describes an issue TCR has identified in modeling capacity expansion for 83C_II OSW projects and provides a solution.

The Issue

The ENELYTIX capacity expansion module determines the optimal combination of retirements of existing capacity and additions of generic new capacity to meet resource adequacy and environmental constraints at least cost, i.e. the objective function, over the planning horizon. The model is set up to obtain the solution with a set precision. There are multiple feasible solutions to the capacity expansion problem within that precision level. As a result, small differences in input assumptions between scenarios, e.g. proposal cases, can have disproportionally large implications for the capacity expansion module’s selection of generic new capacity additions, specifically their timing and composition.

In 83C_I TCR recognized that small differences in input assumptions between two similar Proposals, e.g., the Bay State 800 MW GLL proposal case and the Bay State 800 MW ETN proposal case, could result in significant differences in the capacity expansion module’s selection of generic new capacity additions. The Bay State 800 MW GLL proposal case had capacity additions from 2035 onward consisting of one 533 MW combined cycle (CC) unit and five 338 MW combustion turbine (CT) peaking units (1 CC + 5 CT solution). In contrast, the Bay State 800 MW ETN proposal case had capacity additions from 2035 onward consisting of two 533 MW combined cycle (CC) unit and three 338 MW CT units. (2 CC + 3 CT solution).

 The input assumptions for those two Proposal Cases were nearly identical yet the capacity expansion module selected two different yet equally near-optimal capacity expansion solutions for each of them.  The two different, yet equally near-optimal, capacity expansion solutions produce very different energy price results (LMPS), when dispatched in the Energy & Ancillary Services module (E&AS). All else being equal, a 2 CCs + 3 CTs solution will result in lower LMPs than a 1 CC + 5 CTs solution. As a result, the model will yield indirect price impact benefiting OSW project B for reasons that are an artifact of the model’s algorithm not necessarily reflective of the real differences sought to be estimated. TCR expects to continue to see small differences in input assumptions causing significant differences in the capacity expansion module’s selection of generic new capacity additions for the 83C_II Proposal Cases. TCR expects the Proposal Cases will have relatively close capacity factors, close contributions to the ICR and deliveries into the same SEMA/RI zone. As a result, the capacity expansion module’s selection of generic capacity additions and retirements of existing units for each Proposal will likely lead to outcomes that may have significant differences in energy price projections not necessarily reflective of the real differences sought to be estimated.

TCR Proposed Solution

The capacity expansion module achieves two key objectives: 1) determining retirements and additions of generic new capacity and 2) developing projections of REC and CEC prices.

TCR proposes to use separate runs of the capacity expansion modules to meet each of those objectives:

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 48 of 210

 use a single initial run of the capacity expansion module to determine a common set of retirements and generic capacity additions for all 83C_II Proposal Cases. This is a reasonable approach because of the similarity of ICR contributions and capacity factors among all 83C_II Proposals;  use an 83C_II Proposal specific run of the capacity expansion module to determine the Proposal specific projections of REC and CEC prices. Each Proposal specific run would use the common set of retirements and generic capacity additions for all 83C_II Proposal Cases.

To set up the common run of the capacity expansion model TCR will use the most favorable Tranche 1 OSW project bid and the Tranche 2 proxy unit described in Section 5. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 49 of 210 B.2: Addendum to Protocol D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Appendix B.2 83C II Protocol Addendum 2020 01 26 Page 50 of 210 Deliberative Policy Confidential Addendum to the 83C II Quantitative Metric Calculations, Stage 2

This document serves as an addendum to the Protocol for 83C II Quantitative Metric Calculations, Stage 2 document (“Quantitative Protocol”); it provides additional details and amendments to the evaluation process that could not be documented at the time of Protocol freeze i.e. prior to opening of 83C II bids. Any and all changes were made with joint approval from the full Evaluation Team.

1. Study Period

Page 1 of the Quantitative Protocol states the evaluation metric “….will be the levelized net unit benefit per MWh for each proposal calculated in 2019 dollars (2019$) over a study period of 2022 to 2049”. This study period was selected by the Evaluation Team to ensure that the calculation range for the quantitative metrics was adequately spread out to cover the PPA periods of all project and proxy units under evaluation.

Upon review of the proposals, and after defining the proxy unit parameters per the Quantitative Protocol, it was noted that all applicable Proposal PPAs terminate by 2047. Therefore, it was decided to drop the years 2048 and 2049 from the quantitative calculations, resulting in the final study period being 2022 to 2047.

2. Extrapolation Calculations

Footnote 1 of the Quantitative Protocol states “The ENELYTIX modeling system will be used to calculate values for 2022 through 2046. Values for 2047, 2048 and 2049 will be held at 2046 levels”. Below are some additional notes on calculations under those extrapolation years:

a. All inputs to calculations sourced from ENELYTIX that are tied to the unit PPA periods do not automatically assume their 2046 values. For example, the direct REC benefits of a unit whose PPA ends in 2046 will be reported as zero from 2047 onward instead of its 2046 value. Similarly, the direct REC benefits of a unit whose PPA ends mid 2047 would reflect a fractional part-year value instead of directly assuming its 2046 value. b. All inputs to calculations apart from those described under (a) assume the same value in all extrapolation years (2047 through 2049) as the corresponding 2046 value c. All intermediate and final calculations use the same formula as non-extrapolation years and do not assume their calculated 2046 values. As noted in (a) and (b) above, the differences in inputs to calculations may result in the calculated values being different from their 2046 counterparts.

It should be noted that the shortening of the study period to 2047 eliminates the need to apply extrapolations to 2048 and 2049, as indicated in the Quantitative Protocol.

3. Proxy unit assumptions

Per the modeling approach described on pages 3 and 4 of the Quantitative Protocol, the 400 MW bid from was evaluated as being the least cost bid and subsequently used as a template to establish parameters and costs for the proxy unit. Table 1 and Table 2 provide details of the proxy unit. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 51 of 210

Table 1 Proxy unit Parameters

Parameters Unit Specific Notes Commercial Online Date

Nameplate Capacity

Claimed Capacity Factor

Wind Shape (2012)

Expected Annual Energy Generation ICR Contribution

Point of interconnection

PPA Period Table 2 Proxy unit PPA costs

PPA Price Schedule Energy Price REC Price Total Price [Nominal $/MWh] [Nominal $/MWh] [Nominal $/MWh] Contract Year 1 Contract Year 2 Contract Year 3 Contract Year 4 Contract Year 5 Contract Year 6 Contract Year 7 Contract Year 8 Contract Year 9 Contract Year 10 Contract Year 11 Contract Year 12 Contract Year 13 Contract Year 14 Contract Year 15 Contract Year 16 Contract Year 17 Contract Year 18 Contract Year 19 Contract Year 20 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Appendix B.2 83C II Protocol Addendum 2020 01 26 Page 52 of 210 Deliberative Policy Confidential

4. Remuneration costs

In addition to the direct costs and benefits described in section 6.A on pages 4 and 5 of the Quantitative Protocol, the calculation of direct costs and benefits also includes a ‘Remuneration cost’ which is equal to 2.75% of the sum of the direct costs of energy and the direct costs of RECs over the contract proposal period. The 2.75% markup value was used as the 83C legislation allows for the EDCs to receive remuneration up to 2.75%, if approved by the Department of Public Utilities.

5. Generic Capacity Expansion assumptions

This section expands upon Attachment B of the Quantitative Protocol – Capacity Expansion for 83C_II OSW projects. The generic capacity expansion process was carried out based on the methodology outlined in the attachment except for certain specific assumptions of the unit parameters described below.

The generic capacity expansion for the Proposal cases uses two representative 400 MW tranches. The performance characteristics and parameters for the first tranche represent the average of the bidders 400 MW projects. Those of the second tranche are based on the proxy unit parameters. The table below details the parameters of the tranches noting exceptions wherever applicable.

Table 3 Parameters for Generic Capacity expansion tranches

Parameter Unit Generic Tranche 1 Generic Tranche 2

Nameplate Capacity [MW]

Point of interconnection [-]

Commercial online date [Date] (COD)

Claimed Capacity Factor (for [%] information) Modeled Capacity Factor [%] (based on 2012 estimates) ICR Contribution [MW]

Wind Shape (2012) [-]

6. Stage Three Sensitivity Cases

At the end of Stage Two Analysis, the Evaluation Team noted that the unitized net benefit value for the Indirect Energy Price metric calculations yielded a value that, while consistent across Proposals, was almost an order of magnitude higher than the corresponding metric calculated in 83C I.

Upon further review of the model, it was found that the increase in the metric was driven primarily by the winter fuel switching mechanism which was absent from TCR’s models for 83C I. This mechanism was introduced by TCR as an improvement to the model to better reflect actual market operation. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Appendix B.2 83C II Protocol Addendum 2020 01 26 Page 53 of 210 Deliberative Policy Confidential

The winter fuel switching mechanism allows ENELYTIX to simulate the impact of dual-fuel generators switching from natural gas to fuel oil during days of extreme gas prices. This mechanism approximates the economic and environmental impacts of pipeline constraints on natural gas costs that lead to electricity price spikes seen in the winter periods in New England.

Depending on the number and duration of fuel switches each year, the fuel switch mechanism increases electricity prices in the three winter months of December through February. The prevalence of increased prices depends on the overall natural gas requirements for electricity generation in that year.

Introduction of a significant quantity of non-gas generation over the evaluation period, such as the 800 MW offshore wind in Proposal Case compared to the Base Case, results in a reduction in the number of fuel switches every year as well as significant savings in energy supply costs associated with those reduced switches. These reductions in annual supply costs are reflected in the higher indirect energy price impact calculated in 83 CII compared to the 83C I.

It was also noted that the increase in unit indirect energy price impact benefit is driven by the consistently higher annual benefits seen from 2035 onward. This increase is attributed to the retirement of the Millstone nuclear unit 2 which is replaced by combined cycle gas fired units in both the Base Case and the Proposal cases. The replacement gas fired units increase the annual natural gas requirements in the system, which in turn impacts the number of switches in the Base Case and subsequently the reduction in number of switches in each Proposal Case. The figure below provides an illustration of the number of switches in a Proposal Case compared to the Base Case, highlighting the greater number of switches and reductions after the nuclear unit retirement in 2035.

Figure 1 Comparison of number of fuel switching days Base Case v/s Proposal Case

80 Millstone 2 73 70 Retire 62 Proposal 60 60 Online 55

50 44 44 44 45 39 40 36 36 34 32 31 32

Number of DaysNumber 28 30 2626 2525 2626 26 23 23 18 19 20 16 17 16 14 12 13 12 10 11 9 9 9 8 8 9 8 9 8 9 10 6 6 4 4

Winter Period

83C II Base Case 83C II Proposal Case D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Appendix B.2 83C II Protocol Addendum 2020 01 26 Page 54 of 210 Deliberative Policy Confidential

Upon request of the Evaluation Team to validate the metric and ensure that the higher metric values are attributable to the winter fuel switch mechanism, TCR ran two Proposal Sensitivity Cases on the Stage Two top-ranked Proposal.

- Sensitivity 1: TCR re-ran the 83 C II Base Case and 83C II Proposal Case for the top ranked Proposal without the winter fuel switch mechanism. - Sensitivity 2: TCR re-ran the 83 CII Base Case and the 83C II Proposal Case for the top ranked project assuming the retirement of Millstone nuclear unit 2 is delayed by ten years, coinciding its retirement date with the Millstone nuclear unit 3 retirement which is assumed to be for 2045. TCR included the winter fuel switch mechanism for this sensitivity.

Both Sensitivities resulted in the reduction of the indirect energy price metric to levels comparable to the corresponding 83C I metrics as reported in Table 4, confirming that the increase in metrics is driven by the winter fuel switching mechanism.

Table 4 Comparison of indirect price metric (2019$/MWh)

Top Ranked Stage 2 D.2 Indirect Metrics Sensitivity 1 Sensitivity 2 Proposal MA Energy Market Price Change Impact $ 24.48 $ 3.44 $ 4.49 attributable to Proposal

Figure 2 provides a comparison of the number of fuel switches over the evaluation period for the top ranked Proposal assuming standard evaluation conditions. Figure 3 provides the comparable chart for Sensitivity 2, which assumes a delay in the nuclear retirement. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Appendix B.2 83C II Protocol Addendum 2020 01 26 Page 55 of 210 Deliberative Policy Confidential

Figure 2 Comparison of fuel switch days under standard evaluation assumption

FUEL SWITCH DAYS COMPARISON (STANDARD EVALUATION)

Base Case Top Ranked Proposal 75 80 70 61 62 55 60 47 43 45 42 50 38 37 36 40 30 33 32 30 32 24 22 23 30 17 18 21 1413 1612 13 12 15 20 10 7 10 9 9 8 9 6 8 6 10 10 4 3

# of fuel switch switch days fuel of # 0

Winter of (Dec/Jan/Feb)

Figure 3 Comparison of fuel switch days under sensitivity 2 FUEL SWITCH DAYS COMPARISON (SENSITIVITY 2 - DELAY NUCLEAR RETIR EMENT)

Base Case Top Ranked Proposal

80 7069 70 60 50 40 30 25 2624 20 1920 15 1616 17 20 12 12 14 1412 1312 # of fuel switch # of fuel switch days 11 11 8 8 9 9 8 7 7 5 6 10 4 3 4 2 2 3 4 4 3 2 4 4 0

Winter of (Dec/Jan/Feb) D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 56 of 210 B.3: GWSA Calculation Methodology D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 57 of 210

The Global Warming Solutions Act (GWSA)

The Global Warming Solutions Act (GWSA) requires the Commonwealth to reduce GHG emissions 80 percent below 1990 levels by 2050. In 2010, the Secretary of Energy and Environmental Affairs (EEA) set a 2020 limit on emissions at 25 percent below 1990 levels and published the first Clean Energy and Climate Plan (CECP)1, identifying the policies necessary to achieve these goals. In 2015, EEA released an updated 2020 CECP.2 The 2030 CECP, to be published by EEA in 2020, will identify the 2030 limit on emissions and identify the policies necessary to achieve the new limit.

The 2020 CECP 2015 Update lists three policies for Electricity Generation and Distribution and their associated anticipated 2020 reductions from full policy implementation: Coal-Fired Power Plant Retirements, Renewable Portfolio Standard (RPS), and Clean Energy Imports. Since the publishing of the 2020 CECP 2015 update, the referenced Clean Energy Standard (CES) was implemented by the Massachusetts Department of Environmental Protection (MassDEP) with anticipated reductions for Electricity Generation and Distribution. Additionally, MassDEP promulgated regulation 310 CMR 7.74 Reducing CO2 Emissions from Electricity Generating Facilities in 2017 to set an annual declining limit on CO2 emissions from large electric generating facilities in the Commonwealth. As part of the GWSA 10-year Progress Report published by EEA in 2018, Clean Energy Imports is renamed to Clean Energy Procurements to reflect the procurement of hydroelectricity resources and offshore wind, both of which will be online in the 2020s and help meet the RPS and CES requirements.3

The Massachusetts Department of Environmental Protection’s (MassDEP) Greenhouse Gas Inventory (Inventory) is the database used to track the state’s progress towards the GWSA target. 4 As required by the GWSA, the Inventory accounts for all greenhouse gas emissions associated with the state’s electricity consumption, meaning that if the electricity is used within the state, the Inventory accounts for associated emissions even if the electricity was generated in another state. Massachusetts is a net importer of electricity, meaning the state consumes more electricity than Massachusetts generates. Imported electric sector emissions are calculated considering the generation of each New England state and the transfer of renewable energy certificates for states’ environmental compliance. All the above policies included in the 2020 CECP 2015 Update impact the emissions as accounted for in the Inventory through the emissions from power generators and the transfer and retirement of renewable energy and clean energy certificates for Massachusetts and regional renewable and clean energy portfolio standards.

1 Massachusetts Clean Energy and Climate Plan for 2020; https://www.mass.gov/files/documents/2016/08/sk/2020-clean- energy-plan.pdf 2 Massachusetts Clean Energy and Climate Plan for 2020, 2015 Update; https://www.mass.gov/files/documents/2017/01/uo/cecp-for-2020.pdf 3 Global Warming Solutions Act 10-Year Progress Report; https://www.mass.gov/files/documents/2019/04/02/GWSA-10-Year-Progress-Report.pdf 4 MassDEP Emissions Inventories, https://www.mass.gov/lists/massdep-emissions-inventories and Statewide Greenhouse Gas Emissions Level: 1990 Baseline and 2020 Business As Usual Projection Update, https://www.mass.gov/files/documents/2016/11/xv/gwsa-update-16.pdf D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 58 of 210

GWSA in the Quantitative Evaluation

The GWSA methodology in the Quantitative Evaluation consists of two parts, approximating a proposal's incremental impact on emissions reductions (in MWh) and assigning those emission reductions value (in dollars) to determine a proposal's total $/MWh benefit towards increased GWSA compliance as compared to a base case. Approximating the Emission Reduction Impact

Clean energy policies and their associated emission reductions are included in the results of the analytic tool ENELYTIX licensed by Tabors Caramanis Rudkevich (TCR) to perform economic analyses of a Base Case and each proposal case. TCR uses ten major categories of input assumptions to model the 83C Base Case and each of the Proposal / Portfolio Cases in ENELYTIX. They were Generating Unit Capacity Additions, Transmission, Load Forecast, Installed Capacity Requirements, RPS Requirements, Massachusetts CES and cap on Carbon Emissions, Emission Allowance Prices, Generating Unit Retirements, Generating Unit Operational Characteristics and Fuel Prices. These input assumptions therefore account for all major Electricity Generation and Distribution policies as listed in the 2020 CECP 2015 Update and 2018 GWSA Progress Report, although may not represent their full implementation. For example, compliance with the Massachusetts RPS in the ENELYTIX modeling may be met with a Class I REC or with an Alternative Compliance Payment (ACP), the latter having no associated emission reduction. Each Proposal Case will assume the EDCs ultimately acquire 800 MW of new offshore capacity consisting of the MW from the bid they select in this solicitation and the MW from a proxy unit to be acquired from a future solicitation.

The results of the economic analyses of a Base Case and each proposal case are then input into the GHG Inventory Worksheet to measure the incremental contribution of each Proposal /Portfolio towards meeting the Massachusetts GWSA relative to the 83C Base Case. The incremental contribution over the modeled time period will likely not equal the project’s full emission reduction contribution because the Proposal Case is compared to the Base Case which will also have additional emission reductions post 2019. For example, the ENELYTIX input assumes a cost to increasing RPS compliance in the Base Case, incentivizing additional renewable generation. Incremental contribution from the Proposal can come from greater compliance with policies such as the RPS by avoiding ACP payments or from exceeding the policy compliance in the Base Case through greater reductions in annual emissions (in metric tons of CO2 equivalent) of grid energy generated in Massachusetts and/or imported into Massachusetts or greater number of RECs that may be retired in Massachusetts or other states.

The ENELYTIX modeling report describes the ENELYTIX input and modeling assumptions in detail.

Assigning the Emission Reduction Impact Value

As part of the calculation of direct benefits, the Quantitative Evaluation includes the “Comparison of the price of any Renewable Portfolio Standard (“RPS”) Class I eligible RECs under a contract to: i. the avoided cost with the project not in-service if the RECs are to be used for RPS and Clean Energy Standard (“CES”) compliance by the Distribution Companies or Massachusetts retail electric suppliers, and ii. their projected market prices with the project in- service if the RECs are projected to be sold.” As part of this calculation, TCR determines the MA D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 59 of 210

Class 1 RPS and MA CES compliance obligation that could be met with the Class I RECs from the Proposal. If proposal RECs can be used for MA Class 1 RPS and MA CES compliance obligations, they are assigned direct annual dollar benefit equal to the avoided cost of meeting that obligation at the market price of Class 1 RECs/CECs in the Base Case.

Additionally, proposal RECs that are not retired for RPS or CES compliance or sold into the market may have an impact on GWSA compliance and should be valued through the indirect benefit, calculated as the “Impact of the Proposal on the Commonwealth’s ability to meet Global Warming Solutions Act (GWSA) requirements in excess of compliance with the RPS and the CES.”

Including both the REC compliance benefits and the indirect incremental GWSA compliance benefits in the Quantitative Evaluation, ensures that each environmental attribute or emission reduction in MWh is assigned a single value for its contribution to GWSA compliance and to ensure the value of each MWh of emission reduction is not double counted.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 60 of 210

83C II Base Case Results

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 61 of 210

MA 83C_II Base Case Results

Presentation to the Quantitative Evaluation Team October 10, 2019

10/21/2019 1 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 62 of 210

Summary / Agenda

1. 83C_II Base Case: What it is and is not 2. Capacity Balance for New England 3. Capacity Mix (MW) by Fuel Type 4. Generation Mix (MWh) 5. Model Selected Capacity Retirements and Additions 6. New England Class 1 RPS and MA CES 7. MA CO2 Emission CAP 8. Projected LMPs by Area ($/MWh) 9. ENELYTIX Results Workbook Content

10/21/2019 2 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 63 of 210

1.83C_II Base Case: What it is and is not

It is the reference point or benchmark against which we measure the incremental impacts of each 83C_II Proposal. It is a “counterfactual” projection of market parameters for a scenario key electricity market parameters including electricity prices, REC prices, carbon emissions and in which the Commonwealth does not acquire the last 800 MW of offshore wind through this RFP. EDCs used this approach to develop a Base Case for evaluation of 83D and 83C_I proposals.

It is not a plan for the Massachusetts electric sector and should not be viewed as such.

It assumes:

• Compliance with all legislative requirements and regulations in effect as of June 15, 2019 including class 1 Renewable Portfolio Standard (RPS) regulations in all New England states, the cap on carbon emissions from electric generating units located in MA and the Clean Energy Standard (CES) promulgated August 11, 2017

• Implementation of the resource(s) selected in the MA 83D and MA 83C_I procurement, including all associated transmission developments

• Compliance with MA Class 1 RPS and CES requirements through a combination of the 83D and 83C resources noted above, class 1 RPS eligible generation procured under clean energy contracts over the evaluation period, generic clean energy additions developed on a merchant basis and alternative compliance payments (ACPs)

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2.a. Capacity Balance for New England

Model built CCs & CTs to keep Excess capacity in ISONE in up with increasing ICAP 34,000.0 2023 attributable to inclusion requirements and scheduled of NECEC + VW + other clean retirement of nuclear units in energy procurements. 2035 and 2045 ICAP drops in 2024 due to 32,000.0 retirements of MYSTIC units + model selected retirements

30,000.0

28,000.0 ICR (MW)ICR 26,000.0 Excess capacity maintained in CCs built in NMABO to balance anticipation of Nuclear unit shortfall due to Mystic units retirement retirement 24,000.0

22,000.0

20,000.0 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 Capacity (Summer CSO) Installed Capacity Requirement

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2.b. Capacity Balance by Zone

CONNECTICUT MAINE (REST OF POOL) NORTHEAST MASSACHUSETTS - BOSTON 12,000 30,000 3,500

3,000 10,000 25,000 2,500 8,000 20,000 2,000 6,000 15,000 1,500 ICR (MW)ICR ICR (MW)ICR ICR (MW)ICR 4,000 10,000 1,000

2,000 5,000 500

- - - 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

NORTHERN NEW ENGAND (REST OF POOL) SOUTHEAST MASSACHUSETTS - RHODE ISLAND SOUTHEAST NEW ENGLAND 30,000 9,000 12,000 8,000 25,000 10,000 7,000

20,000 6,000 8,000 5,000 15,000 6,000 4,000 ICR (MW)ICR ICR (MW)ICR ICR (MW)ICR 10,000 3,000 4,000 2,000 5,000 2,000 1,000

- - - 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

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3.a. Nameplate Capacity (MW) by Fuel Type

50,000

45,000 Wind

40,000 PV Refuse 35,000 Land Fill Gas 30,000 Fuel Cell

25,000 Biomass MW Distillate Fuel Oil 20,000 Residual Fuel Oil 15,000 NG Coal 10,000 Uranium 5,000 PSH - Hydro

Includes nameplate capacity of all ISO-NE Generation. Hydro includes capacity from NECEC. 10/21/2019 6 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 67 of 210

3.b. Nameplate Capacity (MW) by Fuel Type

Residual Fuel Distillate Fuel Hydro PSH Uranium Coal NG Oil Oil Biomass Fuel Cell Land Fill Gas PV Refuse Wind Grand Total 2022 1,621 1,867 3,344 535 18,299 4,046 2,520 507 22 57 4,453 401 1,353 39,024 2023 2,711 1,867 3,344 535 18,299 4,046 2,520 507 74 57 4,834 401 1,753 40,947 2024 2,711 1,867 3,344 - 17,032 2,280 2,520 507 74 57 5,210 401 2,857 38,859 2025 2,711 1,867 3,344 - 17,032 2,280 2,520 507 74 57 5,497 401 2,857 39,146 2026 2,711 1,867 3,344 - 17,032 2,280 2,520 507 74 57 5,886 401 3,065 39,744 2027 2,711 1,867 3,344 - 17,032 2,280 2,520 507 74 57 6,284 401 3,357 40,433 2028 2,711 1,867 3,344 - 17,032 2,280 2,520 507 74 57 6,567 401 3,557 40,916 2029 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 6,789 401 3,557 41,671 2030 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 6,991 401 3,557 41,873 2031 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 7,188 401 3,557 42,070 2032 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 7,365 401 3,557 42,247 2033 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 7,567 401 3,557 42,449 2034 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 7,749 401 3,557 42,631 2035 2,711 1,867 3,344 - 17,565 2,280 2,520 507 74 57 7,925 401 3,557 42,807 2036 2,711 1,867 2,485 - 17,565 2,280 2,520 507 74 57 8,079 401 3,557 42,102 2037 2,711 1,867 2,485 - 17,903 2,280 2,520 507 74 57 8,263 401 3,557 42,625 2038 2,711 1,867 2,485 - 17,903 2,280 2,520 507 74 57 8,424 401 3,557 42,786 2039 2,711 1,867 2,485 - 18,436 2,280 2,520 507 74 57 8,581 401 3,557 43,475 2040 2,711 1,867 2,485 - 18,774 2,280 2,520 507 74 57 8,712 401 3,557 43,945 2041 2,711 1,867 2,485 - 18,774 2,280 2,520 507 74 57 8,878 401 3,557 44,110 2042 2,711 1,867 2,485 - 18,774 2,280 2,520 507 74 57 9,019 401 3,557 44,251 2043 2,711 1,867 2,485 - 18,774 2,280 2,520 507 74 57 9,154 401 3,557 44,386 2044 2,711 1,867 2,485 - 19,307 2,280 2,520 507 74 57 9,264 401 3,557 45,030 2045 2,711 1,867 2,485 - 19,307 2,280 2,520 507 74 57 9,411 401 3,557 45,176 2046 2,711 1,867 1,251 - 20,373 2,280 2,520 507 74 57 9,531 401 3,739 45,310

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3.c. ICR Capacity Contribution (MW) by Fuel Type

35,000 Wind

PV 30,000 Refuse

LFG 25,000 Fuel Cell

20,000 Biomass Distillate Fuel Oil MW 15,000 Residual Fuel Oil

10,000 Coal

Uranium 5,000 PSH

Hydro - Installed Capacity Requirement

Includes ICR from all ISO-NE Generation. Hydro includes capacity from NECEC. 10/21/2019 8 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 69 of 210

3.d. ICAP Capacity Contribution (MW) by Fuel Type

Installed Capacity Residual Fuel Distillate Fuel Requireme Hydro PSH Uranium Coal NG Oil Oil Biomass Fuel Cell LFG PV Refuse Wind Grand Total nt 2022 1,426 1,859 3,331 533 15,844 3,920 2,102 488 22 46 519 392 124 30,605 28,402 2023 2,276 1,859 3,331 533 15,844 3,920 2,102 488 74 46 540 392 260 31,664 27,587 2024 2,276 1,859 3,331 - 14,870 2,275 2,102 488 74 46 576 392 666 28,952 27,567 2025 2,276 1,859 3,331 - 14,870 2,275 2,102 488 74 46 583 392 666 28,960 27,681 2026 2,276 1,859 3,331 - 14,870 2,275 2,102 488 74 46 631 392 692 29,035 27,787 2027 2,276 1,859 3,331 - 14,870 2,275 2,102 488 74 46 686 392 730 29,127 27,915 2028 2,276 1,859 3,331 - 14,870 2,275 2,102 488 74 46 713 392 755 29,179 27,948 2029 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,142 2030 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,205 2031 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,324 2032 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,355 2033 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,536 2034 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,658 2035 2,276 1,859 3,331 - 15,403 2,275 2,102 488 74 46 713 392 755 29,712 28,773 2036 2,276 1,859 2,472 - 15,403 2,275 2,102 488 74 46 713 392 755 28,853 28,822 2037 2,276 1,859 2,472 - 15,741 2,275 2,102 488 74 46 713 392 755 29,191 29,031 2038 2,276 1,859 2,472 - 15,741 2,275 2,102 488 74 46 713 392 755 29,191 29,176 2039 2,276 1,859 2,472 - 16,274 2,275 2,102 488 74 46 713 392 755 29,724 29,331 2040 2,276 1,859 2,472 - 16,612 2,275 2,102 488 74 46 713 392 755 30,062 29,413 2041 2,276 1,859 2,472 - 16,612 2,275 2,102 488 74 46 713 392 755 30,062 29,638 2042 2,276 1,859 2,472 - 16,612 2,275 2,102 488 74 46 713 392 755 30,062 29,783 2043 2 276 1 859 2 472 - 16 612 2 275 2 102 488 74 46 713 392 755 30 062 29 932 2044 2,276 1,859 2,472 - 17,145 2,275 2,102 488 74 46 713 392 755 30,595 30,022 2045 2,276 1,859 2,472 - 17,145 2,275 2,102 488 74 46 713 392 755 30,595 30,269 2046 2,276 1,859 1,247 - 18,211 2,275 2,102 488 74 46 713 392 778 30,459 30,459

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4. Generation Mix (MWh)

160,000,000

140,000,000

LFG 120,000,000 FO2 FO6 PSH 100,000,000 Wind Refuse

80,000,000 PV Biomass NG Annual Energy (GWh) Energy Annual 60,000,000 Coal Uranium Hydro 40,000,000 Imports Total ISONE Load

20,000,000

- 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

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5.a. Model Selected Retirements 2046 3000 All Retirements 2,401 MW 2500

Boiler– Natural Gas 2000 100 MW

1500 Coal MW 535 MW

1000 Internal Combustion – Natural Gas

500 <1 MW

Boiler – Residual Fuel Oil 0 1,766 MW 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 ST-FO6 IC/GT-NG Coal-Coal ST-NG

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5.b. Model Selected Retirements by Region and Vintage

Retiring Capacity by Load Zone (2049) Retiring Capacity by Vintage (2049)

816 MW ME 34%

935 MW NH 39%

100 MW WCMA 4%

25 MW SEMA 1% 525 MW CT 22%

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Model Selected New Capacity Additions 5.c. 2046

6,000 High Cost onshore wind 5,185 MW (including TX upgrade) New Nameplate Capacity seen from 2046

5,000 PV 429 MW Onshore wind and PV is 4,000 built for ICAP and RECs starting 2026 through Onshore Wind (w_TX 2028 Upgrade) PV Wind_HC 182 MW 3,000 Wind CT Onshore Wind CC

Nameplate Capacity (MW) Capacity Nameplate CCs built to replace 700 MW 2,000 retiring mystic and scheduled nuclear GT unit retirements 676 1,000 (2 Installations) CCGT

0 3,198 MW 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 (6 Installations)

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5.d. Model Selected New Capacity Additions - Cont’d

CC CT 3,500 800 3,000 700 2,500 600 2,000 500 400 MW

1,500 MW 300 1,000 200 500 100 0 0 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

NMABO RI CT NMABO

PV Wind 500 1,000 450 900 400 800 350 700 300 600 250 500 MW 200 MW 400 150 300 100 200 50 100 0 0 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

NMABO ME VT NH WCMA VT_HCHigh Cost

10/21/2019 14 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 75 of 210

6.a. New England Class 1 RPS Requirements (Input assumption)

60,000

50,000 MA Total REC requirement 83C_II CT 40,000

Total REC requirement RI 83C_I 30,000 NH

REC Requirements (MWh) Requirements REC 20,000 ME

Total ISO-NE Class I REC 10,000 requirement (83C_I)

Total ISO-NE Class I REC requirement (83C_II) - 20212022202320242025202620272028202920302031203220332034203520362037203820392040204120422043204420452046

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6.b. Class 1 RPS and MA CES Requirements

60,000.00

50,000.00

RPS Requirement + MA CES Requirement above MA Class 1 40,000.00

30,000.00 REC REC (GWh)

RPS requirement 20,000.00

10,000.00

- 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

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6.b. Class 1 RPS and MA CES Requirements vs Resources

2022 to 2023 2024 to 2027 2028 to 2044 2045 to 2046 CT ACPs and MA CES ACPs Available physical generation & CT ACPs made CT ACPs displace 60,000.00 made for RPS and MA CES imports adequate for RPS and for RPS resources for CES Compliance MA CES compliance. Compliance compliance

50,000.00 MA CES ACP Payments

CEC fron 83D Import 40,000.00 REC from model additions

30,000.00 REC from Existing/Scheduled ISO NE Gen REC REC (GWh) CT ACP Payments

20,000.00 Imports (traditional)

RPS Requirement + MA CES 10,000.00 Requirement above MA Class 1

RPS requirement

- 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

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6.c. REC and CEC Prices

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6.d. Class 1 RPS & CES Reqts & Resources, REC & CEC prices in 2019 US$/MWh

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7. MA CO2 Emission Cap

MA CO2 Cap Assessment 9,000.0 30.00

8,000.0 25.00 7,000.0

6,000.0 20.00

5,000.0 Emissions 15.00 $/mT

'000mT 4,000.0 Cap (000 mT) MA Premium to RGGI ($/mT) 3,000.0 10.00

2,000.0 5.00 1,000.0

- - 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

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8. Projected Annual Average LMPs by Area (2019 US$/MWh)

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9. ENELYTIX Base Case Results Workbook

Tab Content 1 New Additions Shows new generation additions as selected by the capacity expansion model. See Input Assumptions Document information on scheduled new additions 2 Retirements Shows generation retirements as selected by the capacity expansion model. See Input Assumptions Document information on scheduled retirements 3 GenMix_Gen Generation mix by fuel type in MWh by year 3a Interchange Shows imports into New England by Source Capacity factor by technology/fuel by year. Capacity factor in each category is computed as total generation by category divided by total capacity and by 4 CFs All number of hours in a year 5 CFs New CCs and CTs Capacity factors for new CC and CT generators suggested by the capacity expansion model 6 CFs Wind and PV Capacity factors of new wind and PV generators by year by location 7 ProdCostDet Annual generation and production cost by New England Zone by cost category 8 Gas BurnAnn Annual natural gas burn by New England generators in MMBtu 9 Gas Switchover Daily gas burn in MMBtu and gas cap violation as simulated for years 2022 to 2046 10 SysEmissCO2 CO2 emissions by generating units in New England by zone and state. Emissions are in lbs. 11 SysEmissNOx NOx emissions by generating units in New England by zone and state. Emissions are in lbs. 12 AreaLMP_Monthly LMPs by month by year for each New England Zone reported for On Peak, Off Peak and 24-hour periods 13 AreaLMP_Ann LMPs by year for each New England Zone reported for On Peak, Off Peak and 24-hour periods 14 AreaLoad &Cost Load and Load Cost by zone by year. Load Cost in each zone is computed as a product of hourly load and hourly LMP in that zone summed over year 15 CongRent Congestion rent and count of binding hours for all New England constraints by year 16 Interface Flows Flows on New England interfaces. Flows are reported daily for each year 2022-2046 on average during On Peak and Off Peak hours of the day 17 Tech_program REC GWh Detailed layout of REC contribution by source 18 Zone REC&CEC GWh Detailed layout of REC contribution by source 19 Zone REC GWh Contribution to REC by Zone 20 CES CES Requirements and level met via ACP payments 21 REC Rev by Zone Auxiliary worksheet showing Class 1 REC revenues received by generators by Zone. Used to restate true VOM costs Additional tables on request

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83C II Base Case Assumptions and Description of ENELYTIX simulation model

D.1: New England Document

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 84 of 210

Final Report

Base Case for valuation of 83C Part II Proposals - Input and Modeling Assumptions New England

Prepared for: Eversource Energy, National Grid. Unitil

Tabors Caramanis Rudkevich January 10, 2020

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 85 of 210

Tabors Caramanis Rudkevich 75 Park Plaza Boston, MA 02166 (617) 871-6900 www.tcr-us.com

DISCLAIMER

Tabors Caramanis Rudkevich, INC (TCR) has been contracted by the Massachusetts Electric Distribution Companies (EDCs), Eversource, National Grid and Unitil to provide the quantitative analyses that will allow the EDCs to evaluate the proposals that they receive in response to the 83C II RFPs. The information provided herein is solely for the purpose of development of a Base Case against which the proposed projects may be compared. Any other use of the materials without the explicit permission of TCR is strictly prohibited.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 86 of 210 TABLE OF CONTENTS

Page

Table of Contents ...... iii List of Figures ...... iv List of Tables ...... v CHAPTER 1: Base Case for Evaluation of 83C II Proposals – New England Assumptions ...... 1 1.1: Background ...... 1 1.2: 83C II Base Case Design ...... 2 CHAPTER 2: Modeling Environment ...... 3 2.1: Capacity Expansion Module ...... 5 2.2: Energy and Ancillary Services Module ...... 8 CHAPTER 3: Transmission ...... 10 CHAPTER 4: Interchange ...... 11 CHAPTER 5: Load Forecast ...... 12 5.1: Forecasts of Gross-PDR Annual Energy and Peak Load, 2022 – 2046 ...... 12 5.1.1: 2019 CELT Forecast for 2022 - 2028 ...... 12 5.1.2: TCR Forecast of annual energy and peak load, 2029 - 2046 ...... 14 5.1.3: DER distribution to substations ...... 20 5.2: Forecasts of NEL (Gross – PV – PDR) Annual Energy, 2022 - 2046 ...... 20 5.3: Hourly Load Shape ...... 20 CHAPTER 6: Ancillary Services ...... 22 CHAPTER 7: Installed Capacity Requirement (ICR) ...... 23 7.1: System-wide Installed Capacity Requirement (ICR) ...... 23 7.2: Local Sourcing Requirement (LSR) for Import Constrained Zones ...... 24 7.3: Contribution of Resources toward ICR ...... 25 CHAPTER 8: Renewable Portfolio Standard (RPS) Requirements ...... 26 CHAPTER 9: Massachusetts Carbon Emission Regulations and Clean Energy Standard ...... 30 9.1: Cap on carbon emissions, regulation 310 CMR 7.74...... 30 9.2: Clean Energy Standard, regulation 310 CMR 7.75 ...... 32 9.2.1: Compliance ...... 32 CHAPTER 10: Generating Unit Retirements ...... 35 CHAPTER 11: Generating Unit Capacity Additions ...... 38 11.1: Capacity additions in the ISO-NE interconnection queue ...... 38 11.2: Class 1 Renewable Energy Resource Additions...... 39 11.2.1: Distributed PV Resources ...... 39 11.2.2: Class 1 REC Imports ...... 40 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 87 of 210 11.2.3: Near-Term Class 1 Renewable Resource Additions ...... 40 11.2.4: Generic Market-Driven Class 1 Renewable Resource Additions ...... 42 11.3: Generic Fossil Fuel and Nuclear Resource Additions ...... 45 11.4: Financial Assumptions for Generic Resource Additions ...... 46 CHAPTER 12: Generating Unit Operating Characteristics ...... 47 12.1: Generator Aggregation ...... 47 12.2: Thermal Unit Characteristics ...... 47 12.2.1: Nuclear Unit Operating Characteristics ...... 49 12.3: Hydro Electric Generator Characteristics ...... 49 12.4: Pumped Hydro Storage Facilities ...... 49 12.5: Wind Facilities ...... 50 12.6: Solar Photovoltaics Facilities ...... 50 CHAPTER 13: Fuel Prices ...... 51 13.1: Natural Gas Spot Prices in New England...... 51 13.1.1: Henry Hub Prices ...... 51 13.1.2: Spot gas prices in New England...... 52 13.2: Prices of distillate and residual fuel oil for electric generation in New England...... 54 13.3: Winter fuel switching for dual fuel generators ...... 54 13.4: Uranium Prices ...... 55 13.5: Coal Prices ...... 55 CHAPTER 14: Emission Rates ...... 56 14.1: Emission Rates ...... 56 14.2: Greenhouse Gas Emission Allowance Prices ...... 56

14.3: NOx and SO2 ...... 57 GLOSSARY ...... 59

APPENDIX A: ENELYTIX ...... 63

APPENDIX B: Fuel Price Forecast ...... 67

APPENDIX C: Winter Fuel Switching Modeling ...... 77

LIST OF FIGURES

Page

Figure 1. Interactive use of ENELYTIX modules ...... 3 Figure 2 Representation of the Resource Adequacy Constraints in ISO-NE ...... 6 Figure 3. Seasonal Load Duration Curves and their Representation in Capacity Expansion Module 7 Figure 4. Schematic of the E&AS Module ...... 9 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 88 of 210 Figure 5: TCR forecast Gross - PDR Annual Energy by state (GWh) ...... 19 Figure 6: TCR Gross - PDR Peak Forecast by state (GW) ...... 19 Figure 7: ISO Historical Load Shape, 2012 ...... 21 Figure 8. Process used to project state-specific RPS energy targets ...... 26 Figure 9. TCR and AEO 2019 projections of Henry Hub prices, 2019$ ...... 52 Figure 10. Projections of spot prices in New England (2019$/MMBtu) ...... 53

Figure 11. 83C II Base Case Assumptions relative to RGGI and ISO-NE CO2 Allowance Price Projections as of September 2017 ...... 57 Figure A - 1. Analytical Structure of PSO ...... 64 Figure A-2. Schematic of ENELYTIX Architecture ...... 66 Figure C-1. Graph of historical fuel prices ...... 78 Figure C-2. Number of days in winter period with fuel price exceeding the price of fuel oil ...... 79 Figure C-3. Gas Burn Limit Analysis, Vineyard Wind 800 GLL case ...... 80

Figure C-4. Days exceeding daily gas burn limit by three-month winter period, Vineyard Wind 800 GLL case ...... 81

LIST OF TABLES

Page

Table 1. Applicability of Input and Assumption Categories by ENELYTIX Module ...... 4 Table 2 Scheduled Net Interchange Summary ...... 11 Table 3. Gross-PDR Annual Energy Forecast Summary by ISO-NE Area (GWh) ...... 13 Table 4. Gross-PDR Coincident Summer Peak Load Forecast Summary by ISO-NE Area (MW)...... 13 Table 5. TCR Forecast of Gross Annual Energy and PDR capacity ...... 14 Table 6. Gross - PDR Annual Energy Forecast summary by state (GWh) ...... 17 Table 7. Gross - PDR Annual Peak Forecast summary by ISO-NE states (MW) ...... 18 Table 8. ISO-NE Regulation and Reserve Requirements ...... 22 Table 9. Projection of System-Wide ICR ...... 23 Table 10. Local Sourcing Requirements for Import Constrained Zones ...... 24 Table 11. Exemptions from RPS Obligations ...... 27 Table 12. Projected RPS Requirements ...... 28 Table 12. Projected RPS Requirements (cont.)...... 29 Table 13: Aggregate Limits in Select Years, 2022-2040 ...... 30 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 89 of 210 Table 14: Facility Limits as % of total Cap ...... 31 Table 15. CES requirements, 2022 to 2049 ...... 34 Table 16. ISO-NE approved capacity retirements ...... 35 Table 17 Fixed O&M Requirements by Technology ...... 36 Table 18. Generation Capacity Additions in the ISO New England interconnection Queue ...... 38 Table 19. Additions from New England Clean Energy RFP ...... 40 Table 20. Technical Potential for Installed Renewable Capacity by Resource Type and State ...... 43 Table 21. Assumed Capital, FOM, and VOM Costs for generic market driven renewable additions. 44

Table 22. Assumed Capital, FOM, and VOM Costs for generic market driven non-renewable additions ...... 45 Table 23: Normalized incremental heat rate curve ...... 47 Table 24: Other thermal unit operating parameters by unit type ...... 48 Table 25: Photovoltaic parameter assumptions...... 50 Table 26. Assumptions regarding gas pipeline capacity serving New England ...... 54 Table 27. Base Case CO2 Allowance Price Assumptions (2019$/short ton) ...... 56 Table Appendix B-1. Monthly Spot Gas Pries (2019 $/MMBtu) ...... 67 Table Appendix B-2. Fuel Oil Prices Projection 2022-2046 ...... 75

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CHAPTER 1: Base Case for Evaluation of 83C II Proposals – New England Assumptions

This document describes the modeling and input assumptions that the TCR team proposes for the Base Case against which the Massachusetts electric distribution companies (EDCs) will measure the incremental costs and benefits of each Proposal received in response to the 83C II RFP. TCR refers to this as the “83C II Base Case” or “Base Case”. The complementary document “Base Case Evaluation of 83C II Proposals – Input and Modeling Assumptions New York” describes all 83C II Base Case modeling and input assumptions that are specific to New York. Both reports describe the input and modeling assumptions the TCR team propose for the Base Case against which the EDCs will measure the incremental costs and benefits of each Proposal received in response to the 83C II RFP.

1.1: Background The following legislation, plans and draft regulations provide the background to the development of a Base Case for evaluation of 83C II proposals. • The Global Warming Solutions Act of 2008 (GWSA) requires Massachusetts to reduce the greenhouse gas (GHG) emissions in its GHG inventory to “a 2050 statewide emissions limit that is at least 80 per cent below the 1990 level.”

• In 2010, to start the Commonwealth on a path towards meeting that target, the Secretary of the Massachusetts Executive Office of Energy and Environmental Affairs (EEA) set a statewide GHG emissions reduction limit of 25% for 2020 and released a plan to meet that 2020 target.

• In December 2015, the EEA released an update to that plan for 2020, the 2015 Update Massachusetts Clean Energy and Climate Plan for 2020 (“CECP Update”). The CECP Update includes discussion of policies that would deliver additional GHG reductions over the 2020– 2030 time frame and beyond. For the electric sector, the policies for 2020 and beyond included clean energy imports and a clean energy standard (CES).

• In August 2016, the State legislature passed An Act to Promote Energy Diversity requiring the Massachusetts EDCs to undertake two procurements for supplies of clean energy to help Massachusetts achieve its GWSA targets. Under Section 83D, the EDCs issued an RFP for long term contracts for incremental clean energy generation and associated environmental attributes and/or renewable energy certificates (“RECs”), , for approximately 9,450,000 MWh to be procured pursuant to cost-effective long-term contracts by 2022. Section 83C, requires the EDCs to procure long term contracts for RECs for energy or for a combination of both RECs and energy from offshore wind energy generation equal to approximately 1,600 megawatts of aggregate nameplate capacity not later than June 30, 2027. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 91 of 210

• On August 11, 2017, Massachusetts promulgated new regulations and amendments designed to limit and reduce GHG emissions in Massachusetts. The regulations for the electric sector, 310 CMR 7.74 and 310 CMR 7.75, are a cap on carbon emissions from electric generating units (EGU) located in MA, and a CES. A Massachusetts Department of Environmental Protection (DEP) background document anticipates that the clean energy supplies Massachusetts EDCs contract through the 83C and 83D RFP process will “…deliver adequate quantities of clean energy that count toward CES compliance…”1

1.2: 83C II Base Case Design The 83C II Base Case is not a plan for the Massachusetts electric sector, and it should not be viewed as such. Instead, the 83C II Base Case is a projection of the carbon emission and energy cost implications of a scenario that assumes the additional resources available to meet the regulations promulgated in August 2017 are limited to 83D resources selected through the 2017/2018 83D procurement, 800 MW of 83C resources selected through Part I of this procurement, other expected policy-driven additions and market-driven RPS Class 1 eligible resources.

This 83C II Base Case provides the Evaluation Team a “but for” or “counterfactual” projection of carbon emissions and costs associated with MA electricity consumption under a future in which the EDCs do not acquire 800 MW of offshore wind for delivery by 2029 under long-term contracts with proposals received and selected in response to the 2019 83C II RFP. The 83C II Base Case serves as a common reference point or benchmark against which the EDCs measure the incremental costs and benefits of each Proposal received in response to the 83C II RFP.

The 83C II Base Case reflects all legislative requirements and regulations in effect as of June 15, 2019 including Renewable Portfolio Standard (RPS) regulations in MA and other New England states and the two regulations affecting the electric sector promulgated on August 11, 2017. These are regulation 310 CMR 7.74, a cap on carbon emissions from EGUs located in MA, and regulation 310 CMR 7.75, a Clean Energy Standard (CES). The 83C II Base Case covers the period 2022 through 2046 and expresses cost data in constant 2019$ as of January 1, 2019 unless otherwise noted.

1 Background Document on Proposed New and Amended Regulations, DEP, December 16, 2016. Page 33 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 92 of 210

CHAPTER 2: Modeling Environment

TCR employs ENELYTIX to model the Base Case and Proposal Cases. Appendix 1 describes the ENELYTIX platform in detail. TCR uses ENELYTIX to develop an internally consistent, accurate set of Base Case prices in New England wholesale markets for energy and ancillary services, forward capacity and RECs through the interaction of its two key modules: the Capacity Expansion module and the Energy and Ancillary Services (E&AS) module. Figure 1 illustrates this interaction. • The Capacity Expansion module determines the long-term optimal electric system expansion in New England subject to relevant resource adequacy and environmental constraints. These include system-wide and zonal installed capacity requirements (ICR), RPS requirements and carbon emission limits on Massachusetts EGUs. This module models the power system footprint at the zonal level consistent with the design of the capacity markets in ISO-NE.

• The Energy and Ancillary Services (E&AS) module simulates the Day-Ahead and Real-Time market operations within the footprint of the ISO-NE and New York Independent System Operator (NYISO) power systems and markets. This model implements chronological simulations of the Security Constrained Unit Commitment (SCUC) and Economic Dispatch (SCED) processes, as well as the structure of the ancillary services in ISO-NE and NYISO markets. The E&AS model is fully nodal, performs true Mixed Integer Programming (MIP) based optimization, uses no heuristics, rigorously optimizes storage facilities, phase shifters and High Voltage Direct Current (HVDC) operation and accounts for marginal transmission losses.

Figure 1. Interactive use of ENELYTIX modules D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 93 of 210

The sequence of deploying these modules, as illustrated in Figure 1, is as follows:

• Development of the Base Case begins with application of the Capacity Expansion module, which determines the optimal capacity expansion plan and resulting changes to the generation mix over time, Class 1 REC prices, prices for the MA Clean Energy Credits (CEC)

and the shadow price of CO2 in Massachusetts implied by compliance with the hard cap on emissions from EGUs located in Massachusetts. • Outputs from the Optimal Expansion module are inputs to the Energy and Ancillary Services module. These outputs include new entry and retirement decisions and shadow prices of

CO2 emissions along with the CO2 shadow prices associated with the Regional Greenhouse Gas Initiative (RGGI) program. The E&AS module provides chronological unit commitment and dispatch modeling. This module among other things calculates locational marginal prices for load and generators and net revenues that each generating unit would receive from the Energy and A/S markets. Both modules use the Power System Optimizer (PSO) solver developed by Polaris Systems Optimization, Inc.2 which serves as a key component of the ENELYTIX modeling environment. Within ENELYTIX, all three modules rely on the same dataset for ISO New England and share the economic and operational characteristics of ISO-NE’s existing generating units, representation of the electric transmission system, and projection of future electricity demand.

All modules use the input assumptions in Chapter 3 through 14 where applicable as summarized by module in Table 1 below.

Table 1. Applicability of Input and Assumption Categories by ENELYTIX Module Chapter Capacity Expansion E&AS Module Module

3. Transmission Interfaces only All transmission constraints

4. Interchange fixed schedule economically scheduled

5. Load Forecast Seasonal Load Hourly chronological Duration Curves

6. Ancillary Services N/A Modeled in detail

7. Installed Capacity Requirements By Zone N/A

8. RPS Requirements Yes REC Prices from Capacity Expansion

9. MA Clean Energy Standards and Carbon Yes CO2 shadow prices from Emissions Regulations Capacity Expansion

2 www.psopt.com D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 94 of 210

Chapter Capacity Expansion E&AS Module Module

10. Generating Units Retirements Yes from Capacity Expansion

11. Generating Units Capacity Additions Yes from Capacity Expansion

12. Generating Unit Operational Yes Yes Characteristics

13. Fuel Prices Yes Yes

14. Emission Rates and Allowance Prices Yes Yes

2.1: Capacity Expansion Module The discussion that follows summarizes the methodology used by the Capacity Expansion Model to simulate EGU investment and retirement decisions and calculate market prices for energy, RECs and CECs and shadow prices for Massachusetts CO2 emissions. The specific values of the input assumptions the Capacity Expansion Model uses to model the Base Case are provided in the remaining chapters of this document unless indicated otherwise.

The Capacity Expansion Module solves a dynamic multi-year optimization problem using a MIP optimization solver. The problem is solved over a 35- year optimization horizon (2022 – 2057). The objective function is to minimize the net present value of the total cost, i.e., capital, fuel and operating, of the generation fleet serving the wholesale market within the ISO-NE electrical footprint.

These costs are minimized subject to the resource adequacy, operational and environmental constraints. By respecting these constraints, the optimization algorithm explicitly evaluates the needs for:

• energy delivered to each load zone to meet consumers’ demand in that zone, • installed capacity in each reliability zone to assure resource adequacy (reliability) of the system,

• curbing CO2 emissions by generating plants in Massachusetts to comply with the final 310 CMR 7.74 rules,

• energy produced by new renewable resources procured to comply with state- specific Class 1 RPS and Massachusetts CES requirements, and

• retaining the power flow within the capacity of the transmission network.

While processing these requirements, the algorithm evaluates trade-offs between the capital and operating costs of existing and new resources vis-à-vis their ability to meet these requirements and standard operating constraints. Through finding the global minimum for the net present value of total costs, the algorithms identify the optimal resource mix, locational and technology specific new build decisions and retirement decisions. It also computes shadow prices for environmental constraints. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 95 of 210

The resource adequacy constraints are specified in terms of installed capacity requirements for the ISO-NE system as a whole and for reliability zones within ISO-NE as depicted in Figure 2. These requirements are met by maintaining sufficient generating capacity within each of these reliability zones.

ISO New England performs an annual resource adequacy assessment to develop locational requirements which are then used as inputs to develop parameters for the Forward Capacity Market. This assessment, however, is prepared only for the year for which it conducts the Forward Capacity Auction (FCA). The most recent FCA13 covered the 2022/23 capacity year. Using statistical data for past resource adequacy analyses performed by ISO-NE, forward projections of electricity demand and future limits on transmission interfaces defining reliability zones, TCR develops forward looking estimates of installed capacity requirements for all zones. Chapter 7 presents these estimates.

Figure 2 Representation of the Resource Adequacy Constraints in ISO-NE

Capacity expansion module provides a simplified representation of electric system operation compared to that of the E&AS module. Simplifications are necessary to reduce the size of the optimization problem and achieve computational tractability. The module uses three major simplifications. 1) It relies on load duration curves instead of chronological hourly modeling of electricity demand

2) It uses non-chronological dispatch of generation and does not model the unit commitment process D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 96 of 210

3) It includes representation of transmission interfaces but does not model any other constraints or contingencies.

The model represents load duration curves for three seasons – Summer (June – September), Winter (December – March) and Shoulder (April, May, October and November). Load in each season is represented by blocks of various duration and magnitude that are assumed to remain constant within each block. TCR’s load representation for this module includes 12 blocks for Summer, 10 blocks for Winter and 8 blocks for Shoulder periods as depicted graphically in Figure 3.

Figure 3. Seasonal Load Duration Curves and their Representation in Capacity Expansion Module

This load representation uniquely determines the season and block for each hour of the year. Using that relationship, the module develops average availability of variable resources such as wind and solar by block and season. Capacities of thermal and nuclear units are de-rated in the Shoulder season to account for planned maintenance. Additional derating accounting for forced outages is applied in all seasons.

To reflect the impact of operational constraints on the new build and retirement decisions, the module effectively simulates economic dispatch subject to transmission constraints represented by interfaces monitored by ISO-NE. In computing the impact of generation and loads on interface flows, the full representation of the transmission network which reflects both Kirchhoff’s laws (the current law and the voltage law) is used.

The environmental constraints include requirements for state-by-state procurement of electric energy generated by renewable resources, as well as emissions requirements. The module represents each state’s year-by-year Class 1 RPS requirements, Massachusetts CES requirements, state-specific resource eligibility, limitations on certificate banking and borrowing, and alternative compliance payment (ACP) prices that change over time. By statute, Class 1 RPS ACPs for Massachusetts, Maine, and Rhode Island are indexed to inflation, so in our model they are held constant in real terms at their 2019 levels. The Massachusetts value for 2019 is $68.95 per MWh. Connecticut's ACP is fixed in nominal terms at $55 per MWh in 2019 and reduces to $40 per MWh in 2021, which we deflate in real terms over the study time horizon for modeling purposes. New Hampshire's ACP, currently $57.15 per MWh, increases at half the rate of inflation, so for modeling purposes we deflate it in real terms at half the assumed rate of inflation. By statute, the Massachusetts CES ACP for 2018-2020 is 75% of the Massachusetts RPS ACP, and 50% of the RPS ACP thereafter. The module represents as a constraint the proposed CO2 emission cap rules applicable to generators located in D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 97 of 210

Massachusetts. The module uses projected RGGI CO2 emission allowance prices as an input. Chapters 8, 9 and 14 discuss the detailed input assumptions and data sources.

The module determines Class 1 REC prices as the shadow price of the constraint associated with both meeting all states’ RPS requirements through the addition of Class 1 eligible resources and meeting the Massachusetts incremental CES requirement through the addition of either Class 1 eligible resources or CES-eligible hydro resources. The module determines Massachusetts CEC prices as the Class 1 REC price minus the shadow price of the constraint associated with meeting all states’ RPS requirements. The resulting REC and CEC prices in each year reflects the premiums that the marginal RPS and CES resources need above the energy and capacity market revenues they would receive, to recover their costs.

The capacity expansion module uses a two-phase approach: The first phase makes system expansion and retirement decisions subject to all resource adequacy, operational and environmental constraints except for CES obligations. The second phase dispatches the resources from phase 1 to comply with all obligations including CES, without allowing any additional capacity to be added or retired. This approach serves to create a true counter-factual system expansion case: first, it projects future generation mix in the absence of 83C CES obligations and then it values the impact of 83C II requirements imposed on such a system. Shadow prices for Class 1 RPS and CES requirements obtained in the second phase are used as projection of Class REC and CEC prices, respectively.

The capacity of a given renewable resource type that can be built in a given year is subject to several constraints in the model:

• the estimated remaining technical potential for that resource type in each location

• the estimated maximum single-build capacity that of the resource type

Chapter 11 describes the characteristics of potential renewable resource capacity additions available to the capacity expansion module.

Our projections constrain Class 1 REC and Massachusetts CEC prices to be not less than $2/MWh (except in the presence of a higher administratively set floor price) nor more than $2/MWh below the ACP. The $2/MWh reflects the estimated transaction cost associated with buying and selling RECs and CECs in the market.

2.2: Energy and Ancillary Services Module The ENELYTIX E&AS module is a detailed chronological production costing simulation model which implements SCUC and SCED based simulation of the electricity markets in ISO-NE and NYISO. This module embodies the most detailed operational representation of these electric markets and underlying power systems. In the balance of this document we provide the detailed inputs and assumptions underlying the models and algorithms as shown in Figure 4 below. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 98 of 210

Figure 4. Schematic of the E&AS Module

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CHAPTER 3: Transmission

The geographic footprint modeled by ENELYTIX encompasses the six New England states: Maine, Massachusetts, New Hampshire, Vermont, Rhode Island, and Connecticut, whose electricity movement and wholesale markets are coordinated by ISO-NE. In addition, the model of the E&AS markets incorporates a detailed representation of the NYISO system.3

The physical location of all network resources is organized using substation and node mapping. The transmission topology and electric characteristics of transmission facilities for ISO-NE is modeled on the 2020 SUMMER Peak case obtained by EDCs from ISO-NE which is combined with the representation of the NYISO system obtained from the 2018 FERC 715 powerflow filings for summer peak 2020. TCR personnel formatted power flow information to make it usable by ENELYTIX. TCR mapped New England generators and load areas to bus bars and electrical nodes (eNodes) associated with bus bars according to specifications provided by ISO-NE. Mapping of NYISO and generators and loads was provided by Newton Energy Group, ENELYTIX vendor.

ENELYTIX model organizes physical location of all network resources and loads using bus bars and node mapping. Generators are mapped to bus bars / electrical nodes (eNodes). Bus bars are mapped to NYISO zones and to specific areas outside NYISO system. The mapping of load nodes to NYISO zones and areas outside NYISO is used by ENELYTIX to allocate area load forecast to individual buses in proportion to bus specific loads in the power flow case.

TCR monitored all transmission constraints that were included in evaluation of 83D and 83C_I RFPs. In developing this list of transmission constraints, TCR included the following information: 1. all major ISO New England interfaces and frequently binding constraints assembled by EDCs using historical data from 2012 through June 23, 2017 2. additional constraint contingency pairs from TCR’s contingency analysis 3. Interface definitions and operating limits provided electronically by ISO-NE. TCR verified these interface limits against the ISO_NE’s Planning Transfer Capability Report (2015-16 assessment) In addition to the list of constraints that was monitored in 83D and 83C_I proposal evaluation, TCR also included the following contingency and constraints: 1. Contingency and constraint pairs associated with 83C_I selected proposal. 2. Additional constraints provided by the EDCs to reflect transmission updates and other RFPs in ISO-NE.

3 Transmission topology and operating limits represent Critical Energy Infrastructure Information (CEII). No CEII data is included in this document. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 100 of 210

CHAPTER 4: Interchange

ENELYTIX models New England interchanges with neighboring regions as follows: • NYISO interchanges, hourly economic dispatch o Cross Sound Cable HVDC interconnection with NYISO o Roseton AC interface with NYSIO • Quebec interchanges, hourly schedules from 2012 because the values that year are representative of the 2014 to 2018 levels

o Phases I and II Interface with Hydro Quebec via HVDC o Highgate interface with Hydro Quebec via HVDC • New Brunswick interface at Keswig external node, hourly schedule from 2018

In all instances TCR calendar shifts the interchange flow data for each forecast year to assure that the flow levels remain synchronized with the load pattern in ISO New England.

Table 2 Scheduled Net Interchange Summary Total MWh Average Max MW Min MW MW

NYISO-ISONE interchange N/A N/A N/A N/A

HQ (P1&P2) to ISO-NE 6,244,838 1,325 1,845 0

HQ (Highgate) to ISO-NE 800,033 85 226 0

NB to ISO-NE 2,155,245 230 988 0

Source: ENELYTIX® data set

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CHAPTER 5: Load Forecast

This chapter describes the method TCR uses to develop the forecasts of annual energy and peak load which are inputs to ENELYTIX. These are forecasts of energy and peak load before (“Gross”) and after the impacts of reductions due to passive demand response (“PDR”), i.e. forecasts of Gross and of Gross-PDR. ENELYTIX uses the Gross – PDR forecasts to represent annual energy and peak load requirements over the planning horizon.

The chapter also describes the method used to develop forecasts of annual energy net of the impacts of reductions from behind the meter PV (BTM PV or BMPV). These forecasts, known as the Net Energy Load (NEL) or ‘Gross-PV-PDR’, are used to represent the annual energy requirements of retail customers over the planning horizon.

Finally, this chapter describes the method TCR uses to develop the hourly shape of the Gross- PDR energy forecast.

5.1: Forecasts of Gross-PDR Annual Energy and Peak Load, 2022 – 2046 TCR develops the Gross – PDR load forecasts through 2028 from the 2019 ISO New England Forecast Report of Capacity, Energy, Loads, and Transmission (the CELT Report). TCR develops forecasts for 2029 through 2046 using separate extrapolations for the Gross and PDR components.

5.1.1: 2019 CELT Forecast for 2022 - 2028 The 2019 CELT report provides forecasts of Gross, Gross-PDR and Gross-PV-PDR for annual energy and peak load through 2028. These forecasts are reported for the system level and are determined as generation plus imports minus exports minus pumping for pumped storage.

Table 3 and Table 4 summarize the ISO-NE forecasts of annual energy and peak load by ISO-NE load zone for 2022 through 2028 from the 2019 ISO New England CELT Report. These are forecasts of energy and peak requirements net of the impacts of reductions due to past, present and future energy efficiency measures, referred to as PDR. ISO-NE labels these forecasts “Gross-PDR,” and TCR uses them in the 83C II Base Case to represent the energy and peak load requirements.

The forecasts are coincidental “50/50” forecasts. Coincidental forecast reflects the zonal peak at the time ISO-NE system reaches peak demand instead of the true zonal peak. The 50/50 forecasts represent the median value of the distribution of demand based on different weather scenarios.

The forecasts are taken from tabs 2A and through 2B of the ISO New England CELT 2019 Forecast data file (2019 CELT), the most recent CELT Report. TCR makes slight adjustments to D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 102 of 210 the outer years of the PDR energy and peak in order to align them with the long term forecasts obtained from the most recent version of the EIA Annual Energy Outlook (AEO 2019).

Table 3. Gross-PDR Annual Energy Forecast Summary by ISO-NE Area (GWh) Zone 2022 2023 2024 2025 2026 2027 2028

CT 30,273 30,256 30,375 30,428 30,551 30,696 30,833 ME 12,184 12,324 12,506 12,666 12,839 13,026 13,219 MA 12,279 12,351 12,476 12,543 12,652 12,776 12,935 SEMA* 7,586 7,542 7,547 7,569 7,611 7,670 7,705 WCMA* 56,923 56,686 56,788 56,953 57,267 57,685 58,007 NMABO* 25,789 25,697 25,757 25,846 26,000 26,201 26,361 NH 15,712 15,624 15,630 15,652 15,715 15,806 15,871 RI 15,422 15,364 15,400 15,456 15,551 15,677 15,775 VT 5,716 5,663 5,642 5,616 5,608 5,608 5,597 ISO-NE 124,961 124,821 125,335 125,774 126,528 127,461 128,295

Table 4. Gross-PDR Coincident Summer Peak Load Forecast Summary by ISO-NE Area (MW) Zone 2022 2023 2024 2025 2026 2027 2028

CT 6,577 6,551 6,531 6,532 6,529 6,527 6,506 ME 2,029 2,038 2,047 2,064 2,080 2,097 2,110 MA 2,331 2,334 2,338 2,349 2,358 2,369 2,375 SEMA* 1,889 1,891 1,894 1,909 1,923 1,937 1,945 WCMA* 11,970 11,930 11,910 11,967 12,014 12,073 12,071 NMABO* 5,411 5,396 5,389 5,417 5,441 5,470 5,471 NH 3,298 3,282 3,272 3,284 3,292 3,304 3,299 RI 3,261 3,252 3,249 3,266 3,281 3,299 3,301 VT 1,011 1,007 1,003 1,004 1,004 1,006 1,002 ISO-NE 25,807 25,751 25,723 25,825 25,908 26,009 26,009

* Note – Energy and peak loads for MA are aggregate of values for SEMA, WCMA and NMABO zones.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 103 of 210

5.1.2: TCR Forecast of annual energy and peak load, 2029 - 2046 TCR develops forecasts for 2029 to 2046 by making separate projections of New England gross demand and PDR and then subtracting the PDR projections from the gross demand projection to obtain the Gross-PDR forecasts.

Gross Peak and Energy: TCR assumes linear growth for gross peak and energy for ISO-NE control area and load zones. To develop the forecast, TCR used the five-year compound growth rate (CAGR) from CELT’s 2023-2028 forecast and applied the CAGR to 2028 CELT forecast.

PDR Peak Contribution and Energy: TCR calculates the growth in PDR as the difference between the Gross energy for ISO-NE projection and the long term projection for NEL obtained from AEO 2019, less the projected growth of PV to obtain the forecasted PDR energy. TCR then uses a curve fit extrapolation of the % peak contribution obtained from CELT’s 2023-2028 forecast to obtain the PDR contribution to peak. Table 5 summarizes the projected growth in PDR MW and GWh.

Table 5. TCR Forecast of Gross Annual Energy and PDR capacity ISO-NE 2029 2030 2035 2040 2045

PDR (MW) 5,143 5,322 5,990 6,645 7,142

PDR Energy (GWh) 34,247 35,739 42,546 49,585 57,153

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Table 6 and D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 105 of 210

Table 7 report the resulting projections of Gross-PDR annual energy and peak load by state by year. Figure 5 and Figure 6 plot the resulting projections of Gross-PDR annual energy and peak load by state by year.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 106 of 210

Table 6. Gross - PDR Annual Energy Forecast summary by state (GWh) State 2029 2030 2031 2032 2033 2034 2035 2036 2037

CT 30,999 31,108 31,278 31,419 31,573 31,734 31,883 32,031 32,202

ME 13,279 13,313 13,375 13,426 13,483 13,544 13,600 13,657 13,725

NH 12,997 13,036 13,102 13,157 13,217 13,282 13,342 13,403 13,474

RI 7,756 7,792 7,844 7,890 7,939 7,990 8,039 8,088 8,143

MA 58,320 58,524 58,844 59,110 59,399 59,704 59,983 60,262 60,583

VT 5,642 5,677 5,723 5,764 5,808 5,853 5,897 5,941 5,989

ISO-NE 128,991 129,449 130,166 130,765 131,419 132,108 132,743 133,383 134,116

State 2038 2039 2040 2041 2042 2043 2044 2045 2046

CT 32,377 32,559 32,735 32,912 33,073 33,238 33,412 33,604 33,808

ME 13,795 13,870 13,943 14,016 14,084 14,154 14,229 14,312 14,403

NH 13,548 13,626 13,702 13,779 13,850 13,923 14,002 14,088 14,181

RI 8,200 8,259 8,317 8,376 8,431 8,487 8,547 8,611 8,679

MA 60,913 61,257 61,589 61,923 62,226 62,536 62,865 63,225 63,611

VT 6,038 6,088 6,138 6,188 6,236 6,285 6,336 6,390 6,446

ISO-NE 134,871 135,660 136,423 137,195 137,901 138,623 139,391 140,230 141,128

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Table 7. Gross - PDR Annual Peak Forecast summary by ISO-NE states (MW) State 2029 2030 2031 2032 2033 2034 2035 2036 2037

CT 6,550 6,560 6,584 6,584 6,625 6,649 6,672 6,677 6,723

ME 2,124 2,127 2,135 2,135 2,148 2,156 2,164 2,165 2,180

NH 2,392 2,395 2,404 2,404 2,419 2,428 2,436 2,438 2,455

RI 1,958 1,961 1,968 1,969 1,981 1,988 1,995 1,996 2,010

MA 12,154 12,172 12,216 12,217 12,293 12,337 12,378 12,388 12,475

VT 1,009 1,011 1,014 1,014 1,021 1,024 1,028 1,029 1,036

ISO-NE 26,187 26,226 26,321 26,323 26,487 26,582 26,673 26,693 26,879

State 2038 2039 2040 2041 2042 2043 2044 2045 2046

CT 6,753 6,784 6,797 6,847 6,875 6,904 6,917 6,972 7,011

ME 2,190 2,200 2,204 2,220 2,230 2,239 2,243 2,261 2,274

NH 2,466 2,477 2,482 2,500 2,510 2,521 2,526 2,546 2,560

RI 2,019 2,028 2,032 2,047 2,056 2,064 2,068 2,085 2,096

MA 12,531 12,589 12,611 12,703 12,757 12,811 12,835 12,937 13,008

VT 1,040 1,045 1,047 1,055 1,059 1,064 1,066 1,074 1,080

ISO-NE 26,999 27,123 27,173 27,372 27,487 27,603 27,655 27,875 28,029

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160,000

140,000

120,000

100,000

80,000 GWh

60,000

40,000

20,000

CT ME NEMA NH RI SEMA VT WCMA

Figure 5: TCR forecast Gross - PDR Annual Energy by state (GWh)

15 GW

CT ME NEMA NH RI SEMA VT WCMA

Figure 6: TCR Gross - PDR Peak Forecast by state (GW) D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 109 of 210

5.1.3: DER distribution to substations To accurately capture the impact of distributed energy resources (DER) on the ISONE system, TCR developed distribution factors to spread zonal BTMPV and EE forecast to substations in each ISONE planning zone. Based on 2019 power flow dataset provided by ISO-NE, TCR calculated yearly distribution factor for individual substations in each ISO-NE load zone with the following formula: 푠푢푏푠푡푎푡푖표푛 퐷퐸푅 푙표푎푑 푖푛 푦푒푎푟 푦 푟 = 푦 푍표푛푎푙 퐷퐸푅 푙표푎푑 푖푛 푦푒푎푟 푦

TCR calculated distribution factor r for each zone for each year in the 2020 – 2028 DER dataset provided in the ISO-NE power flow case. TCR did not observe significant intra year change in distribution factor values. Therefore, TCR used 2020 BTMPV and EE distribution factors to spread PV and EE forecast respectively. 5.2: Forecasts of NEL (Gross – PV – PDR) Annual Energy, 2022 - 2046 TCR developed a forecast of energy requirements net of the impacts of reductions from behind the meter PV (BTM PV or BMPV). This forecast, which corresponds to the obligation for retail metered load, is referred to as Net Energy for Load (NEL) and as ‘“Gross-PV-PDR.’”

TCR developed this forecast in order to estimate annual state RPS obligations and the MA CES obligations to use as inputs to ENELYTIX. This forecast is required to calculate those obligations because state regulations specify these obligations as a fraction of metered retail sales measured at the system level, i.e., including transmission and distribution losses. Chapter 8 describes the calculation of, and reports, those RPS and CES requirements.

TCR developed the Gross – PV - PDR forecasts through 2028 from the 2019 CELT Report. It adopted the forecasts for 2029 through 2046 based on the AEO 2019 long term NEL forecast. The PV energy component for 2029 through 2046 was developed based on the ISO-NE 2019 PV Forecast4.

5.3: Hourly Load Shape In order to simulate the ISO New England market on an hourly basis, TCR requires an hourly load shape for each simulated time frame and area modeled. Figure 7 plots the load shapes TCR constructed for each area from the following data:

• 2012 historical load shapes by ISO-NE load zone.5 ENELYTIX uses 2012 load profiles to be consistent with calendar 2012 NREL wind generation profiles, the most recent detailed data available from NREL for New England.

• Annual energy and summer/winter peak forecasts for the study period

4 https://www.iso-ne.com/static-assets/documents/2019/04/final-2019-pv-forecast.pdf 5 2012 SMD Hourly Data, ISO-NE < https://www.iso-ne.com/isoexpress/web/reports/load-and-demand/-/tree/zone-info> D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 110 of 210

To develop hourly load forecasts for future years, ENELYTIX load algorithms first calendar shifts the template load profile to align days of the week and NERC holidays from 2012 to the forecast year. The ENELYTIX algorithm then modifies the calendar shifted template profiles in such a manner that the resulting load shape exhibits the hourly pattern close to that of the template profile while the total energy for the year matches the energy forecast and summer and winter peaks matches the summer and winter peak forecast.

8,000

7,000

6,000

5,000

4,000 MW 3,000

2,000

1,000

CT MA-NMABO MA-SEMA MA-WCMA ME NH RI VT

Figure 7: ISO Historical Load Shape, 2012

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 111 of 210

CHAPTER 6: Ancillary Services

ENELYTIX models four types of Ancillary Services in New England: Regulation, Ten-Minute Spinning Reserve, Ten-Minute Non-Spinning Reserve and Thirty-Minute Operating Reserve. Reserves are cascading – excess regulation counts toward spinning reserves. Excess spinning reserves counts toward Non-spinning. Spinning reserve requirements are considered bi- directional. Non-Spinning reserves can be provided by offline peaking capacity and can handle upward ramping only.

• Regulation must be provided by online resources at the level of ramp rate (in MW/min) limited by a 5-minute activation time.

• Ten-Minute Spinning Reserve (TMSR) must be provided by online resources at the level of ramp rate (MW/min) limited by a 10-minute activation time. Hydro can provide Synchronized reserve up to 50% of its dispatch range.

• Ten-Minute Non-Spinning Reserve (TMNSR) is provided by offline resources capable of supplying energy within 10 minutes of notices. TMNSR can only be provided by quick start capable CTs and Internal Combustion (IC) units.

• Thirty-Minute Operating Reserve (TMOR) can be provided by either on-line or off-line resources with less than 30 minutes activation time.

Table 8 summarizes reserve requirements in ISO-NE.

Table 8. ISO-NE Regulation and Reserve Requirements Reserve Type Requirement (MW)

Regulation Hourly schedule per ISO-NE requirements

Ten min spinning reserves 820

Ten min non-spinning reserves 820

Thirty min operating reserves 750

Hydro generators are assumed to provide regulation and reserves for up to 50% of available dispatch range. Nuclear and wind are assumed to provide no ancillary services.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 112 of 210

CHAPTER 7: Installed Capacity Requirement (ICR)

7.1: System-wide Installed Capacity Requirement (ICR) Table 9 summarizes TCR’s proposed projections. The TCR projections are based on the analyses described earlier in Chapter 5. PDR resources are modeled as price takers.

Table 9. Projection of System-Wide ICR FCA 10 FCA 11 FCA 12 FCA 13 TCR Projection

Power Year 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2029/30 2034/35 2039/40 2044/45

Gross Peak (MW) 30,568 30,377 30,278 29,983 29,773 29,986 31,046 32,148 33,289 34,471

Gross ICR (ICR + 36,848 36,801 36,587 36,640 36,080 36,338 37,622 38,958 40,341 41,773 Tie Benefits)

Gross Margin 20.54% 21.15% 20.84% 22.20% 21.18% 21.18% 21.18% 21.18% 21.18% 21.18%

Peak Net of PV 29,861 29,601 29,436 29,093 28,839 29,014 29,967 30,961 31,998 33,094 (MW)

ICR (MW) 35,126 35,034 34,683 34,719 34,115 34,335 35,512 36,739 38,019 39,365

Margin 17.63% 18.35% 17.83% 19.34% 18.29% 18.34% 18.51% 18.67% 18.82% 18.95%

HQICCs (MW) 975 959 958 969 969 969 969 969 969 969

Net ICR (MW) 34,151 34,075 33,725 33,750 33,146 33,366 34,543 35,770 37,050 38,396

PDR (MW) 2,913 3,327 3,706 4,031 4,301 4,540 5,143 5,853 6,460 7,116

ADR, Imports and PDR adjustment 1,224 1,262 1,232 1,317 1,259 1,259 1,259 1,259 1,259 1,259 (MW)

Net ICR less PDR, ADR & Imports 30,014 29,486 28,787 28,402 27,586 27,567 28,142 28,658 29,331 30,022 (MW)

Starting with the data provided in the four most recent ICR studies, TCR estimates implied reserve margin requirements – the difference between ICR and projected summer peak demand divided by the net (gross-PV) peak demand. A simple average of these margins is 21.18 %. TCR D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 113 of 210 assumes that this margin will persist into the future and used this assumption to develop the future ICR projection.

TCR assumes that the future import capacity from Hydro Quebec will remain at the 2022/23 level of 969 MW estimated by ISO-NE. This assumption reflects the annual capacity typically available from the existing supply agreement with Hydro Quebec.

Finally, TCR assumes external control areas and Active Demand Response (ADR) resources within New-England will provide an additional 1,259 MW. These assumptions are based upon the average quantities of capacity that cleared in ISO-NE Forward Capacity Auctions 10 through 13.

7.2: Local Sourcing Requirement (LSR) for Import Constrained Zones Local Sourcing Requirements are minimum levels of installed capacity that must be procured within an import constrained zone. FCA 10 identified Southeast New England (SENE), consisting of NMABO, SEMA and RI, to be the only zone requiring LSR. Table 10 summarizes TCR’s projection of Local Sourcing Requirements for SENE.

Table 10. Local Sourcing Requirements for Import Constrained Zones FCA 12 FCA 13 TCR Projection

2021 2022 2023 2024 2025 2030 2035 2040 2045 Power Year /22 /23 /24 /25 /26 /31 /36 /41 /46

NEMA/Boston 2,182 2,205 2,233 2,264 2,300 2,513 2,701 2,916 3,182

RI/SEMA 6,314 6,299 6,295 6,298 6,314 6,530 6,786 7,073 7,411

SENE 8,441 8,511 8,524 8,548 8,591 8,962 9,346 9,783 10,317

CT 5,943 5,456 5,431 5,420 5,412 5,394 5,341 5,298 5,290

CT+MA+RI 20,365 19,561 19,476 19,422 19,401 19,647 19,907 20,231 20,696

All but ME 24,472 23,716 23,623 23,569 23,543 23,784 24,028 24,342 24,817

Starting with the data provided in ISO-NE ICR studies available as of June 2019, TCR estimates implied reserve margin requirements for all import constrained zones. The implied reserve margin was computed as a difference between the sum of LSR and N-1 contingency import limit into the zone and the 90/10 peak demand in that zone divided by the 90/10 peak demand. 90/10 peak demand is the ISO New England estimated summer peak which is likely to occur under the 1 in 10 years most critical weather conditions.

For each zone, TCR computes a simple average using historical data from past FCAs in which that zone was evaluated by ISO-NE as potentially binding. TCR then assumed that the implied D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 114 of 210 margin for each zone will remain constant in the future and used that estimate to derive future LSR values. The last two rows in Table 10 represent LSR projections for rest of pool zones, CT+MA+RI and “All but ME”. TCR uses these to model export constrained zones of Northern New England and Maine, respectively, as discussed in Chapter 2.

7.3: Contribution of Resources toward ICR For resources listed in ISO-NE CELT 2019 Generator List as well as scheduled new additions, TCR used the Summer Cleared Capacity based on the results of FCA 13. Units reporting dynamic de-list capacity were assumed to contribute the sum of their cleared capacity and their delist capacity.

For scheduled clean energy procurement additions that did not participate in FCA13, TCR assumed their contribution to ICR based on its analysis of similar clean energy procurement resources that have summer cleared capacities in FCA 13.

For model built resources, TCR used the following assumptions to model their nameplate capacity contribution to the ICR:

• Offshore wind: 20%. ISO-NE has used this value in various of its planning studies, and consistent with the projected ICR contributions from bids received in response to MA 83C I

• Onshore wind: 12.8%. This value is the ratio of Summer Claimed Capability over nameplate capacity for wind units in the CELT generation list.

• Utility-scale and non-BTM distributed solar PV: 32%. This value is set in between the 2020 peak load contribution in CELT for BMPV (34%) and anticipated future reduction in that level due to the shift in the time of peak load occurrence caused by the addition of PVs.

• Conventional combined cycle (CC) gas turbine units and simple cycle gas turbine units (GT): 100% D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 115 of 210

CHAPTER 8: Renewable Portfolio Standard (RPS) Requirements

This Chapter describes the forecast requirement for Class 1 RPS resources over the study period.

As described in Chapter 2, TCR configures the ENELYTIX Capacity Expansion Module to model Class 1 RPS requirements and resources for all New England states except Vermont, which does not have a Class 1 RPS requirement equivalent to those of the other five states. Over the study time horizon, TCR expects negligible interaction between secondary tiers and the Class 1 REC markets; only Class 1 requirements are modeled, therefore, in order to project new Class 1 eligible renewable additions and Massachusetts Class 1 REC prices.6

With the exception of Vermont, the eligibility criteria for Class 1 RPS programs in each of the New England states have a great deal of overlap, and the resulting high level of “fungibility” of new resources’ environmental attributes creates a linkage among the Class 1 REC markets of the other five states. This means that they must all be modeled to project REC prices in each.

Figure 8 illustrates the process TCR used to determine state-specific Class 1 RPS energy targets by year for each of the five states.

Figure 8. Process used to project state-specific RPS energy targets

6 The New Hampshire Class II (solar) requirement (0.3 percent of RPS-obligated load) has been added to our Class 1 requirement, given that the distributed solar resources likely to count toward it are included in the distributed PV forecast represented in the model. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 116 of 210

TCR projects RPS requirements using the following data:

• Projections of NEL from Chapter 5. • Load share for load serving entities (LSEs) and certain wholesale load exempt from state RPS requirements.

• Annual RPS targets for each state7, expressed as a percentage of sales to end-use customers for obligated (non-exempt) load-serving entities.

For a given state, the forecast requirement for Class 1 RPS energy is equal to the forecast load of LSEs obligated to comply with the RPS multiplied by the annual Class 1 RPS percentage target. The forecast load of LSEs obligated to comply with each RPS is equal to the Gross-PV- PDR forecast of NEL by state, reduced by exempt load. Table 11. Exemptions from RPS Obligations

State Percentage of Load Exempt from RPS Requirements CT 7.9% MA* 17.4% ME 2.2% NH 1.7% RI 2.5% * MA Includes approximately 14% exempt retail and 3.4% exempt wholesale load.

TCR derives the shares of NEL exempt from RPS obligations used in its calculation from state RPS compliance reports, ISO-NE historical NEL data, and EIA data. Table 12 provides a full listing of projected New England RPS requirements.8

7 TCR models state RPS targets per regulations as of June 15, 2019. This does not include changes to the Maine RPS target “An Act to Reform Maine’s Renewable Portfolio Standard,” LD1494, passed on June 26, 2019 (http://legislature.maine.gov/legis/bills/display ps.asp?PID=1456&snum=129&paper=&paperld=l&ld=1494) . Based on a review of the bill and its implications on the modeling assumptions, the Evaluation Team decided to exclude changes to the Maine RPS target due to uncertainties on implementation details. 8 Sources: (a) 2019-2028: ISO-NE 2019 CELT and PV Forecast, reduced for PDR and BMPV. Post-2028 energy, PDR, and BMPV values based on TCR calculations. 2029-2049: TCR projection of Gross-PV-PDR energy load forecast (see Chapter 5); (b) Values based on RPS compliance reports, ISO-NE historical NEL data, and EIA data; (d) Massachusetts: MGL ch. 25A, Section 11F, as amended by Chapter 227 of the Acts of 2018, Section 12. (https://malegislature.gov/Laws/GeneralLaws/PartI/TitleII/Chapter25A/Section11F, https://malegislature.gov/Laws/SessionLaws/Acts/2018/Chapter227) Connecticut: Connecticut Renewable Portfolio Standard, Connecticut Public Utilities Regulatory Authority. (https://www.ct.gov/pura/cwp/view.asp?a=3354&q=415186) Rhode Island: RES Obligation Targets, by Compliance Year, for Both New and Existing Resources, Rhode Island Public Utilities Commission, (http://www.ripuc.ri.gov/utilityinfo/RES-Annual-Targets.pdf.) New Hampshire: SB 129, enacted July 2017. (http://gencourt.state.nh.us/bill status/billText.aspx?sy=2017&id=957&txtFormat=pdf&v=current.) Maine: Maine Renewable Portfolio Standard, Maine Public Utilities Commission. (https://www.maine.gov/mpuc/electricity/RPSMain.htm.) D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 117 of 210

Table 12. Projected RPS Requirements

(a) Net Energy for Load (NEL) Gross-PV-PDR Forecast (GWh)

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 CT 29,351 29,219 29,244 29,208 29,240 29,308 29,392 29,568 29,626 29,748 29,843 29,952 MA 55,138 54,734 54,677 54,725 54,933 55,250 55,470 55,740 55,850 56,079 56,258 56,464 ME 12,102 12,233 12,407 12,558 12,723 12,901 13,086 13,016 13,041 13,095 13,136 13,185 NH 12,130 12,192 12,302 12,356 12,451 12,561 12,706 12,673 12,698 12,750 12,790 12,837 RI 7,458 7,401 7,383 7,383 7,402 7,439 7,452 7,505 7,519 7,550 7,574 7,602 (b) RPS-exempt load as a proportion of NEL

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 CT 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% MA 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% ME 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% NH 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% RI 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% (c) NEL Subject to RPS Obligations (GWh) = (a) x (1 - b)

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 CT 27,030 26,908 26,932 26,898 26,928 26,990 27,068 27,230 27,283 27,395 27,483 27,583 MA 45,557 45,223 45,176 45,216 45,387 45,649 45,831 46,054 46,145 46,334 46,482 46,652 ME 11,835 11,963 12,133 12,280 12,441 12,616 12,797 12,728 12,753 12,805 12,846 12,893 NH 11,928 11,988 12,097 12,150 12,244 12,352 12,494 12,461 12,486 12,537 12,577 12,623 RI 7,271 7,216 7,199 7,198 7,217 7,253 7,266 7,317 7,331 7,362 7,385 7,412 (d) Class 1 RPS Requirements (%) *

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 CT 24.0% 26.0% 28.0% 30.0% 32.0% 34.0% 36.0% 38.0% 40.0% 40.0% 40.0% 40.0% MA 20.0% 22.0% 24.0% 26.0% 28.0% 30.0% 32.0% 34.0% 35.0% 36.0% 37.0% 38.0% ME 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% NH 13.0% 13.9% 14.8% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% RI 17.0% 18.5% 20.0% 21.5% 23.0% 24.5% 26.0% 27.5% 29.0% 30.5% 32.0% 33.5% (e) Class 1 RPS Requirements (GWh) = (c) x (d)

2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 CT 6,487 6,996 7,541 8,070 8,617 9,177 9,744 10,347 10,913 10,958 10,993 11,033 MA 9,111 9,949 10,842 11,756 12,708 13,695 14,666 15,658 16,151 16,680 17,198 17,728 ME 1,183 1,196 1,213 1,228 1,244 1,262 1,280 1,273 1,275 1,281 1,285 1,289 NH 1,551 1,666 1,790 1,907 1,922 1,939 1,962 1,956 1,960 1,968 1,975 1,982 RI 1,236 1,335 1,440 1,548 1,660 1,777 1,889 2,012 2,126 2,245 2,363 2,483 * NH Requirement includes Class II solar (0.7%)

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 118 of 210

Table 12. Projected RPS Requirements (cont.) (a) Net Energy for Load (NEL) Gross-PV-PDR Forecast (GWh)

2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 CT 30,071 30,178 30,287 30,420 30,560 30,709 30,853 31,001 31,133 31,272 31,422 31,591 MA 56,688 56,890 57,096 57,347 57,611 57,891 58,163 58,441 58,692 58,952 59,236 59,553 ME 13,237 13,284 13,332 13,391 13,452 13,518 13,581 13,646 13,705 13,766 13,832 13,906 NH 12,888 12,934 12,981 13,038 13,098 13,162 13,224 13,287 13,344 13,403 13,467 13,540 RI 7,632 7,659 7,687 7,721 7,757 7,794 7,831 7,868 7,902 7,937 7,975 8,018 (b) RPS-exempt load as a proportion of NEL

2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 CT 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% 7.9% MA 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% 17.4% ME 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% NH 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% 1.7% RI 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% (c) NEL Subject to RPS Obligations (GWh) = (a) x (1 - b)

2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 CT 27,693 27,791 27,892 28,015 28,143 28,281 28,413 28,549 28,671 28,799 28,937 29,092 MA 46,837 47,004 47,174 47,382 47,600 47,832 48,056 48,286 48,493 48,708 48,942 49,205 ME 12,944 12,990 13,037 13,095 13,155 13,219 13,281 13,344 13,402 13,461 13,526 13,598 NH 12,673 12,718 12,765 12,821 12,880 12,942 13,003 13,065 13,121 13,180 13,243 13,314 RI 7,441 7,468 7,495 7,528 7,563 7,599 7,635 7,672 7,705 7,739 7,776 7,818 (d) Class 1 RPS Requirements (%) *

2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 CT 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% MA 39.0% 40.0% 41.0% 42.0% 43.0% 44.0% 45.0% 46.0% 47.0% 48.0% 49.0% 50.0% ME 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% NH 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% 15.7% RI 35.0% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% (e) Class 1 RPS Requirements (GWh) = (c) x (d)

2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 CT 11,077 11,117 11,157 11,206 11,257 11,312 11,365 11,420 11,469 11,519 11,575 11,637 MA 18,266 18,802 19,342 19,900 20,468 21,046 21,625 22,211 22,792 23,380 23,982 24,602 ME 1,294 1,299 1,304 1,309 1,315 1,322 1,328 1,334 1,340 1,346 1,353 1,360 NH 1,990 1,997 2,004 2,013 2,022 2,032 2,041 2,051 2,060 2,069 2,079 2,090 RI 2,605 2,726 2,736 2,748 2,760 2,774 2,787 2,800 2,812 2,825 2,838 2,853 * NH Requirement includes Class II solar (0.7%) D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 119 of 210

CHAPTER 9: Massachusetts Carbon Emission Regulations and Clean Energy Standard

The 83C II Base Case uses the two regulations affecting the electric sector promulgated on August 11, 2017. These are regulation 310 CMR 7.74, a cap on carbon emissions from EGUs located in MA, and regulation 310 CMR 7.75, the CES.

9.1: Cap on carbon emissions, regulation 310 CMR 7.74

The regulation imposes an annual physical cap on CO2 emissions from EGUs located in the Commonwealth. EGUs are classed as either New Facilities or Existing Facilities, with separate specific caps on aggregate emissions applicable to EGUs in each category, plus an aggregate cap on emissions from all EGUs (i.e., aggregate cap). Individual EGUs are allowed to use “over- compliance credits” in order to comply with their unit specific limits. Table 13 presents the limits for new and existing EGUs for select years. The sum of these is the aggregate limit.9

Table 13: Aggregate Limits in Select Years, 2022-2040 Existing Facility New Facility Aggregate GHG Year Aggregate GHG Aggregate GHG Emissions Limit Emissions Limit Emissions Limit

2022 8,207,213 6,707,213 1,500,000

2023 7,979,235 6,479,235 1,500,000

2024 7,751,257 6,251,257 1,500,000

2025 7,523,279 6,023,279 1,500,000

2026 7,295,301 6,095,301 1,200,000

2027 7,067,323 5,904,823 1,162,500

2028 6,839,345 5,714,345 1,125,000

2029 6,611,366 5,523,866 1,087,500

2030 6,383,388 5,333,388 1,050,000

9 Massachusetts Department of Environmental Protection, “BACKGROUND DOCUMENT ON PROPOSED NEW AND AMENDED REGULATIONS: 310 CMR 7.00 and 310 CMR 60.00 Air Pollution Control for Stationary and Mobile Sources,” December 16, 2016. Table 13is reproduced from Table 3 in this report.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 120 of 210

Existing Facility New Facility Aggregate GHG Year Aggregate GHG Aggregate GHG Emissions Limit Emissions Limit Emissions Limit

. . . (- 2.5% of 2018 /yr)

2040 4,103,607 3,428,607 675,000

. . . (- 2.5% of 2018 /yr)

The rule defines New Facilities as EGUs located in Massachusetts that have less than 10 years operational history as well as those that are scheduled for commissioning during the 2018 – 2025 time period. The only significant new EGU subject to the New Facility Cap is the Salem Harbor unit, which came into service in 2017.

Table 14 lists the Existing Facilities that are subject to the Existing Facility cap according to Table 4 in the DEP December document.10

Table 14: Facility Limits as % of total Cap Facility Name 2013-2015 Average % of Total Generation (MWh) Generation

ANP Bellingham Energy Company, LLC 2,238,927 12%

ANP Blackstone Energy Company, LLC 2,049,400 11%

Bellingham 507,609 3%

Berkshire Power 1,137,483 6%

Canal Station 265,266 1%

Cleary Flood 131,311 1%

Dartmouth Power 125,833 1%

Deer Island Treatment 2,584 0%

Dighton 859,904 4%

Fore River Energy Center 3,236,599 17%

Kendall Square 1,219,559 6%

MASSPOWER 791,485 4%

Medway Station 4,172 0%

10 Ibid, p. 39. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 121 of 210

Facility Name 2013-2015 Average % of Total Generation (MWh) Generation

Milford Power, LLC 387,564 2%

Millennium Power Partners 1,723,289 9%

Mystic 3,945,784 21%

Pittsfield Generating 208,106 1%

Potter (Braintree Electric) 63,569 0%

Stony Brook 179,176 1%

Tanner Street Generation 95,400 0%

Waters River 4,131 0%

West Springfield 39,933 0%

9.2: Clean Energy Standard, regulation 310 CMR 7.75 The regulation requires retail electricity sellers, excluding Municipal Light Plants (MLPs), to procure CECs or pay the CES ACP. The affected retail electricity sellers are investor-owned distribution companies providing standard offer service and competitive energy suppliers. CECs, referred to as “clean energy attributes”, are expressed in megawatt hours (MWh). The quantity of CECs sellers are required to acquire each year (the “standard”) is a specified percentage of their electricity sales, expressed in MWh

Table 15 presents our forecast of CES requirements over the study period. This forecast is based on the NEL (Gross-PV-PDR) from Chapter 5 and an assumption that the annual net energy load of MLPs remains at 14%, its level in 2017, over the study period.11

9.2.1: Compliance Retail electricity sellers are allowed to comply with the CES by acquiring RPS Class 1 RECs, by acquiring CECs from DEP-approved new clean energy generation from non-RPS eligible technologies built after 2010, or by paying an ACP. By statute, the CES ACP is set 75% of the Massachusetts Class 1 ACP for 2018-2020 and 50% of the Class 1 ACP thereafter. The rule contains provisions specifying geographic eligibility and banking of CECs. Imports of new clean energy generation from Canada are imported through transmission capacity that comes online after 2017.

In the 83C II Base Case, compliance with the CES is not enforced as a constraint in the Capacity Expansion optimization. The annual cost of compliance, however, is quantified in a post-

11 TCR calculation from data in Figure 2, Mass DEP GHG Reporting Program Summary Report For Retail Sellers of Electricity Emissions Year 2012, DEP, April 2015 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 122 of 210 modeling calculation as the product of any shortfall in meeting a given year’s target and the CES ACP for that year.12

12 More precisely, the ACP is modeled in the 83C II Base Case as a soft constraint with a very small cost of $0.01/MWh, so that compliance with the CES can be easily tracked, and the cost accounted for afterward. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 123 of 210 Table 15. CES requirements, 2022 to 2049 Requirements, % 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 MA Class 1 RPS & CES Requirements - % of Applicable Load MA Class 1 RPS 22.0% 24.0% 26.0% 28.0% 30.0% 32.0% 34.0% 35.0% 36.0% 37.0% 38.0% 39.0% 40.0% CES 26.0% 28.0% 30.0% 32.0% 34.0% 36.0% 38.0% 40.0% 42.0% 44.0% 46.0% 48.0% 50.0% CES incr to Class 1 RPS 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% CES applicable to MLP Load 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Requirements, GWh MA Load per ISO NE CELT GWh 54,734 54,677 54,725 54,933 55,250 55,470 55,740 55,850 56,079 56,258 56,464 56,688 56,890 2019, GROSS-PV-PDR wholesale load exempt from % 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% CES wholesale load exempt from GWh CES 1,848 1,846 1,848 1,855 1,866 1,873 1,882 1,886 1,894 1,900 1,907 1,914 1,921 MLP load % 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% MLP load GWh 7,663 7,655 7,662 7,691 7,735 7,766 7,804 7,819 7,851 7,876 7,905 7,936 7,965 non-MLP load subject to CES GWh 45,223 45,176 45,216 45,387 45,649 45,831 46,054 46,145 46,334 46,482 46,652 46,837 47,004 CES Requirements, non-MLP GWh 9,949 10,842 11,756 12,708 13,695 14,666 15,658 16,151 16,680 17,198 17,728 18,266 18,802 Requirements, % 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 MA Class 1 RPS & CES Requirements - % of Applicable Load MA Class 1 RPS 41.0% 42.0% 43.0% 44.0% 45.0% 46.0% 47.0% 48.0% 49.0% 50.0% 51.0% 52.0% CES 52.0% 54.0% 56.0% 58.0% 60.0% 62.0% 64.0% 66.0% 68.0% 70.0% 72.0% 74.0% Draft CES incr to Class 1 RPS 11.0% 12.0% 13.0% 14.0% 15.0% 16.0% 17.0% 18.0% 19.0% 20.0% 21.0% 22.0% CES applicable to MLP Load 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Requirements, GWh MA Load per ISO NE CELT GWh GWh 57,347 57,611 57,891 58,163 58,441 58,692 58,952 59,236 59,553 59,900 60,294 2019, GROSS-PV-PDR wholesale load exempt from % 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% 3.4% CES wholesale load exempt from GWh GWh 1,937 1,946 1,955 1,964 1,974 1,982 1,991 2,000 2,011 2,023 2,036 CES MLP load % 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% 14% MLP load GWh 8,029 8,065 8,105 8,143 8,182 8,217 8,253 8,293 8,337 8,386 8,441 8,497 non-MLP load subject to CES GWh 47,382 47,600 47,832 48,056 48,286 48,493 48,708 48,942 49,205 49,491 49,817 50,144 CES Requirements, non-MLP GWh 19,900 20,468 21,046 21,625 22,211 22,792 23,380 23,982 24,602 25,241 25,905 26,576 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 124 of 210 CHAPTER 10: Generating Unit Retirements

Table 16 summarizes the ISO-NE approved scheduled retirements. TCR obtains this list of retirements from S&P Global’s data services and cross verifies the retirements against the relevant ISO-NE Seasonal Claimed Capability reports for specific units to see which month ISO-NE deactivated, or will deactivate, the particular unit.13 Mystic units 8 and 9 are assumed to retire after the termination of their existing Reliability Must Run (RMR) agreement with ISO-NE.

Table 16. ISO-NE approved capacity retirements Summer CELT Energy Generation/Fuel Capacity Retire Asset ID Name Area Type (MW) Date

Retirements Per ISO-NE retirement Tracker

340 BRIDGEPORT HARBOR 3 CT ST-SUB 399.5 6/1/2021

783 HIGHGATE FALLS VT HDR-WAT 9.58 6/1/2021

953 ATTLEBORO LANDFILL - QF SEMA IC-OBG 1.7 6/1/2021

502 MYSTIC 7 NEMA ST-RFO 617.04 6/1/2022

503 MYSTIC JET NEMA GT-DFO 14.2 6/1/2022

1029 BUNKER RD #13 GAS TURB SEMA GT-DFO 3.84 6/1/2022

1028 BUNKER RD #12 GAS TURB SEMA GT-DFO 3.78 6/1/2022

1432 GRS-FALL RIVER SEMA GT-LFG 5.3 6/1/2022

531 PAWTUCKET POWER RI CC-NG 70.14 6/1/2022

Retirement per NRC license expiration

484 MILLSTONE POINT 2 CT ST-NUC 856.52 7/1/2035

485 MILLSTONE POINT 3 CT ST-NUC 1225 11/1/2045

Assumed retirements

1478 MYSTIC 8 NEMA CC-NG 872.33 6/1/2024

1616 MYSTIC 9 NEMA CC-NG 872.33 6/1/2024

13 https://www.iso-ne.com/static-assets/documents/2016/08/retirement tracker external.xlsx D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 125 of 210 Over the study period ENELYTIX analyzes the economics of existing thermal units to determine whether their projected revenues compared to their projected variable operating costs justifies retiring any of those units. The ENELYTIX capacity expansion optimization algorithm evaluates the trade-off between the need to keep the generating unit online to meet resource adequacy requirements against making an investment into another generating unit to satisfy environmental constraints and/or producing energy at lower operating cost. Table 17 presents our assumptions regarding fixed O&M costs of existing units which are a key input to this evaluation.

Table 17 Fixed O&M Requirements by Technology Unit Type / Technology FOM ($/kW-yr) Source

Combined Cycle Gas Turbine 36.51 1

Gas Turbine (Aeroderivative) 40.99 1

Gas Turbine (Frame) 22.88 1

Coal Boiler 73.56 2

Gas/Oil Boiler 43.72 4

Nuclear* 109.79 2

Biomass 121.57 2

Hydro* 37.03 3

Pumped Storage Hydro* 20.20 2

Solar Photovoltaic* 11.94 1

Wind Onshore* 121.57 1

Wind Offshore* 165.13 3

Notes

- All costs adjusted to 2019$

- Regional costs adjusted to New England Region, as applicable

*Units not considered for retirement

Sources

1. ISO https://www.iso-ne.com/static-assets/documents/2018/02/2022-2023-ccp-forward-capacity-auction-

NE 13-iso-offer-review-trigger-price-update.xlsx

https://www.iso-ne.com/static-assets/documents/2017/01/cone and ortp updates.pdf

2. EIA https://www.eia.gov/analysis/studies/powerplants/capitalcost/archive/2013/pdf/updated capcost.pdf

https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capcost assumption.pdf D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 126 of 210 https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/beret addendum leidos.pdf

https://www.eia.gov/outlooks/aeo/assumptions/pdf/electricity.pdf

3. NREL https://data.nrel.gov/files/89/2018-ATB-data-interim-geo.xlsm

4. EIPC https://www.eipconline.com/uploads/MRN- NEEM Modeling assumptions Draft Jan 25 2011 Input Tables Exhibits.xls D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 127 of 210 CHAPTER 11: Generating Unit Capacity Additions

TCR uses the existing generating units listed in the ISO-NE 2019 CELT Report, tab 2.1, Generator list.14

11.1: Capacity additions in the ISO-NE interconnection queue Table 18 summarizes projected near-term new generation additions drawn from the TCR database for this project. These are projects listed in ISO New England’s interconnection queue as of June 15, 2019, which are either under construction or which have had major interconnection studies completed and have cleared the latest Forward Capacity Auction (FCA) completed as of June 2019.15,16

Table 18. Generation Capacity Additions in the ISO New England interconnection Queue Summer Energy ICAP In effect / FCA ID Name Area Type (MW) COD

Upgrades to existing units

Natural 486 MILFORD POWER (UPGRADE) SEMA 202 (+53) 6/1/2020 Gas

Pumped 582.6 359/360 J. COCKWELL 1 & 2 (UPGRADE) WCMA 6/1/2021 Storage (+80)

New additions per FCA 11 – 13 (excludes units procured under contract)

Natural 38692 MMWEC Simple Cycle Gas Turbine NEMA 58 6/1/2021 Gas

38943 Athens Energy LLC_1 ME Wood 7 6/1/2021

40613 Fusion Solar Center LLC CT Solar 7.4 6/1/2022

40616 Pawcatuck Solar Center CT Solar 9 6/1/2022

40623 East Longmeadow Solar PV WCMA Solar 0.8 6/1/2022

Energy Madison BESS ME 5 6/1/2022 40653 Storage

40732 Three Corners Solar ME Solar 85.2 6/1/2022

14 https://www.iso-ne.com/system-planning/system-plans-studies/celt/?document-type=CELT%20Reports 15 https://irtt.iso-ne.com/reports/external 16 https://www.iso-ne.com/isoexpress/web/reports/auctions/-/tree/fcm-auction-results D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 128 of 210 Summer Energy ICAP In effect / FCA ID Name Area Type (MW) COD

Natural 38663 Killingly Energy Center CT 632 6/1/2022 Gas

Forward Capacity Auction Additions not included in Base Case

Natural 38504 Burrillville Energy Center 317 RI 485 6/1/2022 Gas

11.2: Class 1 Renewable Energy Resource Additions The ENELYTIX capacity expansion module determines the quantity of new Class 1 eligible renewable energy resources needed to satisfy Class 1 RPS requirements in each state each year.

The following discussion describes TCR’s assumptions regarding distributed PV additions, assumed 83C II generic resource additions, class 1 REC imports, near-term renewable additions, and generic market-driven additions.

11.2.1: Distributed PV Resources Because distributed PV development is largely driven by policies other than the Class 1 RPS requirements—such as Solar Massachusetts Renewable Target (“SMART”) and the Small Scale Renewable Energy Growth and Renewable Energy Fund programs in Rhode Island—TCR uses ISO-NE’s Final 2019 PV Forecast to project distributed PV additions, rather than add them using the Capacity Expansion model in response to the market.18 All distributed PV generation additions through 2028 in the ISO-NE PV Forecast are assumed in the Base Case to come to fruition. TCR forecast distributed PV for the remainder of the study horizon by extrapolating the ISO-NE PV Forecast using a curve fit.

The forecast breaks PV into two types—behind the meter, and non-BTM distributed PV. Non-BTM PV are allowed to provide energy and capacity, whereas BMPV can only provide energy. Non-BTM PV resources are assumed to provide a contribution to ICR at a level equal to 32 percent of their nameplate capacity. In representing the Massachusetts RPS rules in the Capacity Expansion module, TCR assumes that all distributed PV energy can count against or reduce the Class 1 RPS requirement.19 TCR assumes distributed PV in Vermont counts toward the Vermont Distributed Generation (Tier 1) requirement (not represented in our model), and do not allow it to count toward Class 1 requirements elsewhere.

17 This unit cleared the FCA but had its permits rejected by the Rhode Island Energy Facilities Siting Board https://www.spglobal.com/marketintelligence/en/news-insights/trending/k8VLtDyRFhxe5Ep6YTD-9Q2 18 ISO New England Final 2019 PV Forecast, May 1, 2019 (“ISO-NE PV Forecast”). The PV forecast includes detailed estimates of installations in each state, developed in conjunction with those states. The projected new entry is primarily policy-driven, but includes a post-policy component; both components embody explicit realization rates that vary over the period. In incorporating the PV forecast, TCR removed non-BTM PV installed and already existing through 2019, so as not to double-count these resources, already included as part of the CELT Generation List. 19 Reducing the requirement (as in the Solar Carve-outs) or being counted toward it (as in the SMART program) are effectively the same thing from a modeling perspective. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 129 of 210 11.2.2: Class 1 REC Imports Resources located outside ISO-NE provide RECs used to comply with Class 1 RPS obligations in each of the states. Imports of RECs are required to be coupled with energy import transactions. TCR assumes that RECs imported into ISO-NE to comply with Class 1 RPS requirements remain constant at their 2015 levels throughout the study time horizon. TCR estimates the 2015 level, based upon the most recent public data available from state RPS compliance reports and the NEPOOL GIS, to be 2,400 GWh, about 22.8% of the combined 2015 Class 1 requirements.

11.2.3: Near-Term Class 1 Renewable Resource Additions Table 18 listed renewable additions in the ISO-NE interconnection queue having cleared the FCA. In addition to those projects, TCR assumes renewable generation projects selected under recent clean energy RFPs. Table 19 lists those projects. TCR assembled the data on each project based on inputs from the EDCs.

Table 19. Additions from New England Clean Energy RFP Generator Name Generating Type Energy Area Online Date Nameplate MW

Connecticut Small Scale RFP (2017)

Pawcatuck Solar Center Solar PV CT 15.0

Litchfield Solar Plant+Park Project Solar PV CT 19.8 Litchfield Solar Plant Facility

North Stonington Solar Plant + Park Solar PV CT 10.0 Project NS Solar Plant Facility

W. Portsmouth St. Solar Solar PV ΝΗ 10.0

Constitution Solar Solar PV CT 19.6

Highgate Solar Solar PV VT 19.6

Hinckley Solar Solar PV ΜΕ 19.6

Randolph Center Solar Solar PV VT 19.6

Sheldon Solar Solar PV VT 19.6

Winslow Solar Solar PV ΜΕ 19.6

Davenport Solar Solar PV VT 15.0

Nutmeg Solar Solar PV CT 19.6

Wallingford Renewable Energy (WRE) Solar PV CT 20.0

GRE-29-WATERFORD-CT Solar PV CT 17.7

GRE-15-NORTH HAVEN SOLAR Solar PV CT 5.0 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 130 of 210 Generator Name Generating Type Energy Area Online Date Nameplate MW

Coolidge Solar II Solar PV VT 19.6

New England Clean Energy RFP (2017)

Ranger Sanford Solar PV ME 11/1/2020 49.4

Ranger Farmington Solar PV ME 11/1/2020 49.4

Ranger Quinebaug Solar PV CT 11/1/2021 49.4

Ranger Chinook Solar PV NH 11/1/2021 30.0

Deepwater Solar PV CT 10/14/2019 26.4

Candlewood Solar PV CT 9/30/2020 20.0

RES Woods Hill Solar PV CT 12/26/2018 20.0

RES Hope-Scituate Solar PV RI 12/31/2020 20.0

Massachusetts 83D (2017/18)

NECEC Hydro Hydro ME (Import) 1/1/2023 1,090.0

Massachusetts 83C_I (2017/18)

Vineyard Wind 400_T1 Offshore Wind SEMA 1/1/2023* 400.0

Vineyard Wind 400_T2 Offshore Wind SEMA 1/1/2024* 400.0

Rhode Island Revolution Wind Procurement (2018/19)

RevolutionWind 400_RI Offshore Wind RI 1/1/2024 400.0

Connecticut Clean Energy RFP (2018)

RevolutionWind 200_CT Offshore Wind RI 200.0

Energy and Innovation Park Fuel Cell CT 20.0

Bloom Colchester Fuel Cell CT 10.0

Hartford Fuel Cell Fuel Cell CT 7.4

Derby Fuel Cell Fuel Cell CT 14.8

Connecticut Zero Carbon RFP (2018)

RevolutionWind 100_CT Expansion Offshore Wind RI 104.0

Tilton Heights Energy Center Solar PV NH 19.9

Steel Mill Solar Solar PV NH 10.0 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 131 of 210 Generator Name Generating Type Energy Area Online Date Nameplate MW

Old Mill Solar Solar PV ME 15.0

Keay Brook Energy Center Solar PV ME 19.9

GRE-3-ME-SACO_wstorage Solar PV ME 19.8

Montville Energy Center Solar PV CT 19.9

Black Hill Point Energy Center_wstorage Solar PV CT 19.9

Gravel Pit Solar PV CT 20.0

* COD of units assumed to be delayed by 1 year

11.2.4: Generic Market-Driven Class 1 Renewable Resource Additions The Federal Production Tax Credit (PTC), renewed in December 2015, is scheduled to phase out by 2020, such that only resources beginning construction before the end of 2019 are eligible. The Investment Tax Credit (ITC) for large wind is scheduled to be eliminated by 2020. TCR does not model the PTC or the ITC in the Base Case.20

All distributed PV additions are assumed to be already represented in the ISO-NE PV Forecast resources; as a result, the only candidate PV additions available to the capacity expansion model are utility-scale PV.

Table 20 presents our assumptions regarding the technical potential of Class 1 eligible resources by technology, drawn from U.S. Renewable Energy Technical Potentials, A GIS-Based Analysis, Anthony Lopez, Billy Roberts, Donna Heimiller, Nate Blair, and Gian Porro, NREL Technical Report NREL/TP- 6A20-51946, July 2012.21

20 Potential extension of the ITC in recent budget bills in Congress is not considered.

21 http://en.openei.org/doe-opendata/dataset/5346c5c2-be26-4be7-9663-b5a98cbb7527/resource/01fe78a8-77b6-4c59-bc36- cae177ee86c3/download/usretechpotential.pdf D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 132 of 210

Table 20. Technical Potential for Installed Renewable Capacity by Resource Type and State Technology CT ME MA NH RI VT Total

Capacity (GW)

Conventional

Hydro New Stream Reach 0.2 0.9 0.3 0.4 0.0 0.4 2.2 Dev.

Onshore 0.0 11.3 1.0 2.1 0.0 2.9 17.4 Wind Offshore 7.2 147.4 184.1 3.5 21.0 363.1

PV Utility-scale 17.1 660.6 62.5 37.9 10.0 36.5 824.7

Biomass Gaseous 0.1 0.0 0.1 0.0 0.1 0.0 0.3

Energy (GWh/year)

Conventional

Hydro New Stream Reach 922 3,916 1,197 1,741 59 1,710 9,546 Dev.

Onshore 62 28,743 2,827 5,706 130 7,796 45,264

Wind 1,561, Offshore 26,545 631,960 799,344 14,478 89,115 442

1,103,54 1,363, PV Utility-scale 27,344 99,674 61,154 15,424 56,360 3 500

Biomass Gaseous 415 125 1,104 390 474 203 2,710

Table 20 highlights the on-shore wind potential in Maine because TCR assumed that only 25 percent of the 11.3 GW potential listed would be available for generic market-driven new additions. This limit is due to transmission capacity limits in Maine, in particular the Orrington interface which is a significant bottleneck to moving wind energy southward. Approximately 25 percent (by capacity) of Maine wind generation projects in the ISO-NE interconnection queue with Active status as of July 2017 (about 3,800 MW) are listed as interconnecting to substations south of Orrington. Therefore, TCR only made 25 percent of the 11.3 GW potential listed for Maine available to the capacity expansion model for generic market-driven new additions. Furthermore, TCR assumed that only a fraction of the wind potential could be realized without major transmission upgrades. In consultation with EDCs, TCR assumed without transmission upgrades up to 200 MW of wind could added in each state of Maine, New D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 133 of 210 Hampshire and Vermont. Additional 100 MW was assumed to be feasible to add in the WCMA zone. Above these limits, additional capital costs were associated with on-shore wind additions, as reflected in Table 21.

Table 20 also highlights the PV potential in Massachusetts of 62.5 GW. To distribute this potential across the three load zones in Massachusetts, TCR and the Evaluation team reviewed the quantity of utility scale PV in the ISO-NE interconnection queue as well as the existing PV in the 2019 CELT Report, as well as further review of the NREL source document and associated footprints of the three energy areas. It was decided to limit the quantity of PV potential in the NMABO zone to 1.5 GW, SEMA to 8.5 GW and the balance potential to WCMA.

Table 21 presents capital and operating cost assumptions for generic market-driven renewable resource additions.

Table 21. Assumed Capital, FOM, and VOM Costs for generic market driven renewable additions Variable Overnight Fixed Operation Operation & Technology Capital Costs & Maintenance Source Maintenance ($/kW) ($/kW-yr) ($/MWh)

Hydropower 6,353.89 37.03 - 2

Photovoltaic 1,903.49 11.94 - 1

Onshore Wind 2,554.61 30.15 - 1

High Cost Onshore Wind 3,326.48 30.15 - 1 *

Offshore Wind 4,285.36 165.13 - 2

Notes

- All costs adjusted to 2019$

- Regional Costs adjusted to New England Region, as applicable

* Higher cost reflective of assumed transmission upgrades allowing capacity to be built beyond the allowable threshold

Sources

https://www.iso-ne.com/static-assets/documents/2018/02/2022-2023-ccp- forward-capacity-auction-13-iso-offer-review-trigger-price-update.xlsx 1. ISO NE https://www.iso-ne.com/static- assets/documents/2017/01/cone and ortp updates.pdf

https://atb.nrel.gov/ 2. NREL https://data.nrel.gov/files/89/2018-ATB-data-interim-geo.xlsm D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 134 of 210 https://www.iso-ne.com/static- * ISO-Ne ME resource assets/documents/2018/03/final maine resource integration study report non integration study ceii.pdf

11.3: Generic Fossil Fuel and Nuclear Resource Additions Generic fossil fuel resource additions include dual-fuel capable combined cycle and simple cycle gas turbine generating units. For these technologies, TCR relies on unit characteristics and cost assumptions as specified in the Concentric Energy Advisors’ (CEA) report prepared for ISO-NE; filed with FERC in support of its application for the FCA12 parameters.22 TCR also considers Advanced Nuclear options. Table 22 presents capital and operating cost assumptions for generic market-driven fossil resource additions.

Table 22. Assumed Capital, FOM, and VOM Costs for generic market driven non-renewable additions Variable Overnight Fixed Operation Operation & Technology Capital Costs & Maintenance Source Maintenance ($/kW) ($/kW-yr) ($/MWh)

Combined Cycle Gas 971.64 36.51 3.30 1 Turbine

Open Cycle Gas Turbine 791.13 22.88 4.24 1 - Conventional

Open Cycle Gas Turbine 1,490.85 40.99 4.71 1 - Aeroderivative

Nuclear 6,508.62 109.79 2.52 2

Biomass 5,509.40 121.57 4.64 2

Notes

- All costs adjusted to 2019$

- Regional Costs adjusted to New England Region, as applicable

* Higher cost reflective of assumed transmission upgrades allowing capacity to be built beyond the allowable threshold

Sources

https://www.iso-ne.com/static-assets/documents/2018/02/2022-2023-ccp- 1. ISO NE forward-capacity-auction-13-iso-offer-review-trigger-price-update.xlsx

22 Available online at https://www.iso-ne.com/static-assets/documents/2017/01/cone_and_ortp_updates.pdf D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 135 of 210 https://www.iso-ne.com/static- assets/documents/2017/01/cone and ortp updates.pdf

https://www.eia.gov/analysis/studies/powerplants/capitalcost/archive/2013/pdf/u pdated capcost.pdf

https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capcost assu 2. EIA mption.pdf https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/beret addendu m leidos.pdf

https://www.eia.gov/outlooks/aeo/assumptions/pdf/electricity.pdf

https://atb.nrel.gov/ 3. NREL https://data.nrel.gov/files/89/2018-ATB-data-interim-geo.xlsm

https://www.iso-ne.com/static- 4. ISO-Ne ME resource assets/documents/2018/03/final maine resource integration study report non integration study ceii.pdf

11.4: Financial Assumptions for Generic Resource Additions The base case uses common financing assumptions for all market-driven unit additions, both fossil fuel and renewable. These assumptions include a 20-year financing period, and a real after tax weighted average cost of capital (WACC) of 6.0%. The WACC is based on the results of an analysis by Concentric Energy Advisors prepared for ISO New England, which assumes uncontracted merchant development, and is based on costs of equity and debt that are commensurate with a merchant project’s perceived risks of cost recovery in the market, which are higher than those of a project whose revenues are contracted under a PPA.23 The use of a WACC based on merchant rather than contracted development reflects the Base Case assumption that only merchant development will be possible because the market will not bring about the development of resources with long-term PPAs in the absence of mandated procurements such as 83C.

23 ISO-NE CONE and ORTP Analysis. Concentric Energy Advisors. Prepared for ISO New England, January 13, 2017, p. 48. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 136 of 210 CHAPTER 12: Generating Unit Operating Characteristics

12.1: Generator Aggregation To optimize model computation time, TCR aggregates all units below 20 MWs by type, fuel and load zone into a smaller set of units. Full load heat rates for the aggregates are calculated as the capacity- weighted average of the individual units and all other parameters are inherited from the unit type.

12.2: Thermal Unit Characteristics Thermal generation characteristics are generally determined by a generator’s technology and fuel type. These characteristics include heat rate curve shape, non-fuel operation and maintenance costs, startup costs, forced and planned outage rates, minimum up and down times, and quick start, regulation and spinning reserve capabilities.

TCR developed generator outage and heat rate data from information by similar unit type as obtained from both the North American Electric Reliability Corporation (NERC) Generating Availability Report and power industry data provided by S&P Global.

Each thermal unit type has a distinct normalized incremental heat rate curve. The normalized heat rate curve is scaled by the full load heat rate (FLHR) to produce unit specific heat curve. Table 23 summarizes the shape of normalized heat rate curves used in ENELYTIX.

Table 23: Normalized incremental heat rate curve Unit Type Blocks (Total) Block Capacity Range (% of Max) Heat Rate (% of FLHR) CT 1 1 100% 100% 1 50% 113% 2 51% ~ 67% 75% CC 4 3 68% ~ 83% 86% 4 84% ~ 100% 100% 1 0% ~ 50% 106% 2 51% ~ 65% 90% ST (Coal) 4 3 66% ~ 95% 95% 4 96% ~ 100% 100% 1 25% 118% 2 26% ~ 50% 90% ST (Other) 4 3 51% ~ 80% 95% 4 81% ~ 100% 100%

Source: ENELYTIX® data set

Table 24 summarizes other operating parameter assumptions by unit type for thermal generators. The abbreviations in the unit type column are structured as follows: First 2-3 characters identify the technology type, the next 1-2 characters identify the fuel used (gas, oil, coal, biomass, refuse) and the numbers identify the size of generating units mapped to that type.

Table 24: Other thermal unit operating parameters by unit type Min Up Min Down Startup Cost Unit Type EFORd AvgNumFO VOM Time (h) Time (h) Cold ($/MWh) CCg100 (0-100MW) 6 8 4.29 6.29361 2.5 35 CCg100+ (100-9999MW) 6 8 4.29 6.29361 2.5 35 CCgo100 (0-100MW) 6 8 4.29 6.29361 2.5 35 CCgo100+ (100-9999MW) 6 8 4.29 6.29361 2.5 35 GTg20 (0-20MW) 1 1 18.6 7.17047 10 0 GTg50 (20-50MW) 1 1 12.97 5.97854 10 0 GTgo20 (0-20MW) 1 1 18.6 7.17047 10 0 GTgo50 (20-50MW) 1 1 12.97 5.97854 10 0 GTo20 (0-20MW) 1 1 18.6 7.17047 10 0 GTo20 (0-20MW) 1 1 18.6 7.17047 10 0 GTo50 (20-50MW) 1 1 12.97 5.97854 10 0 GTo50+ (50-9999MW) 1 1 9.29 8.83609 10 0 ICb+ (0-500MW) 1 1 11.63 5.36087 10 0 ICg20 (0-20MW) 1 1 21.16 8.15737 10 0 ICg50 (20-50MW) 1 1 11.54 5.31938 10 0 ICg50+ (50-500MW) 1 1 11.54 5.31938 10 0 ICgo20 (0-20MW) 1 1 21.16 8.15737 10 0 ICgo50 (20-50MW) 1 1 11.54 5.31938 10 0 ICgo50 + (50-500MW) 1 1 11.54 5.31938 10 0 ICo20 (0-20MW) 1 1 21.16 8.15737 10 0 ICo50 (20-50MW) 1 1 11.54 5.31938 10 0 ICo50 (20-50MW) 1 1 11.54 5.31938 10 0 ICo50+ (50-500MW) 1 1 11.54 5.31938 10 0 STb+ (0-500MW) 1 1 10.26 6.60348 0 35 STc100 (0-100MW) 24 12 8.32 6.62999 5 45 STc250 (100-250MW) 24 12 6.47 7.56834 4 45 STc600+ (600-9999MW) 24 12 7.05 8.24258 2 45 STg100 (0-100MW) 10 8 10.34 3.04348 6 40 STg200 (100-200MW) 10 8 8.42 6.23223 5 40 STg600 (200-600MW) 10 8 8.35 8.25635 4 40 STgo100 (0-100MW) 10 8 10.34 3.04348 6 40 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 138 of 210 Min Up Min Down Startup Cost Unit Type EFORd AvgNumFO VOM Time (h) Time (h) Cold ($/MWh) STgo200 (100-200MW) 10 8 8.42 6.23223 5 40 STgo600 (200-600MW) 10 8 8.35 8.25635 4 40 STo100 (0-100MW) 10 8 10.34 3.39285 6 40 STo200 (100-200MW) 10 8 8.42 8.38989 5 40 STo600 (200-600MW) 10 8 8.35 5.96487 4 40 STo600+ (600-9999MW) 10 8 14.55 22.7626 3 40 STr+ (0-500MW) 10 8 10.26 6.60348 2 40 NUC-BWR1000MW+ 164 164 2.19 1.26865 0 90 NUC-BWR (800-1000MW) 164 164 1.66 1.61458 0 90 NUC-BWR (400-799MW) 164 164 3.27 2.44982 0 90 NUC-PWR1000MW+ 164 164 4.02 2.29472 0 90 NUC-PWR (800-1000MW) 164 164 3.02 1.03991 0 90 NUC-PWR (400-799MW) 164 164 3.02 2.03373 0 90

Source: ENELYTIX® data set

12.2.1: Nuclear Unit Operating Characteristics Nuclear plants are modeled as special thermal units in ENELYTIX. In general, nuclear facilities are treated as must run units and assumed to run except for periods during generator maintenance and forced outage. Current refueling schedules are obtained from roadtech.com24. Future schedules are estimated per specified periodicity.

12.3: Hydro Electric Generator Characteristics TCR models hydro electric generators as energy constrained generators that output energy in relation to daily pattern of water flow, i.e. the minimum and maximum generating capability and the total energy for each plant. TCR obtains historic hydro generation MWh from EIA and S&P Global database. Based on this historic information, TCR develops daily maximum energy output for each hydro power plant in ISO-NE. Subject to this maximum energy output constraint, TCR allows ENELYTIX® to optimize hourly energy output of each hydro electric generator to minimize system-wide production costs in each hour of the day.

12.4: Pumped Hydro Storage Facilities TCR models pumped storage with the following specifications obtained from the National Hydroelectric Power Resource Study prepared for the U.S. Army Engineer Institute of Water Resources.

• Max Storage: Unit Capacity * Number of Storage hours • Min Storage: 10% of Max Storage • Min MW: Pumping Capacity • Efficiency: Annual Output/Annual Pumping Energy

24 https://www.roadtechs.com/shutdown/shutdown.php?region=n D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 139 of 210 12.5: Wind Facilities Wind generation is represented as hourly generation profile in ENELYTIX®. TCR assembles wind generation profiles from the National Renewable Energy Laboratory (NREL)’s Wind Integration National Dataset (WIND) Toolkit dataset based on 2012 weather data.25 TCR maps each wind power plant to the nearest NREL site based on the plant’s location. For wind plants with known historic capacity factor, TCR further screens for NREL wind sites that have capacity factor within delta of 2% from historical average capacity factor inside a 50-mile radius range from the plant’s location. The resulting normalized NREL site schedule is scaled to the installed capacity of the corresponding wind site and then calendar-shifted for each forecast year making it synchronized with load profiles and interchange schedules.

12.6: Solar Photovoltaics Facilities Like wind facilities, photovoltaic (PV) generators are also represented as hourly generation profiles in ENELYTIX®. TCR obtains solar irradiation data from the weather station closest to a PV generator’s location and uses NREL’s PVWatts® Calculator to estimate the site’s energy production. TCR assumes all utility scale PV facilities are fixed array installations with characteristics summarized in Table 25.

Table 25: Photovoltaic parameter assumptions PV Parameter Assumption Elevation (m) 5 Module Type Standard Array Type Fixed (Open Rack) Array Tilt (deg) 20 Array Azimuth (deg) 180 System Losses (%) 14 Invert Efficiency (%) 96

Source: ENELYTIX® data set

25 https://www.nrel.gov/grid/wind-toolkit.html D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 140 of 210 CHAPTER 13: Fuel Prices

13.1: Natural Gas Spot Prices in New England TCR develops projections of the monthly spot price of natural gas to each gas-fired unit in New England based upon the projections of spot prices at the market hub which serves the unit. The four relevant hubs are Algonquin, Tennessee Zone 6, Tennessee Dracut and Iroquois Zone 1. Attachment A provides our forecast of monthly spot prices at those hubs in 2019$/MMBtu for the period January 2022 through December 2046, as well as the underlying forecast of monthly Henry Hub prices.

The projections of natural gas spot prices at each market hub equals the TCR projection of monthly Henry Hub prices plus the TCR projection of monthly basis differential to each market hub from the Henry Hub.

13.1.1: Henry Hub Prices TCR begins by developing a projection of annual Henry Hub prices and then develops monthly Henry Hub prices from those annual prices. We use Henry Hub because of the quantity of forecast and trading data available for that market hub.

The projection of annual Henry Hub prices is a based upon forward prices and a long-term forecast. The forward prices are from OTC Global Holdings available from S&P Global as of June 10th, 2019. The long-term forecast is from the Energy Information Administration (EIA) Reference Case in the AEO 2019. TCR uses a blend of the forward prices and the long-term forecast prices for the first five years of its projections as the forward prices reflect expectations regarding market conditions in the near- term. TCR then uses the AEO 2019 forecast as those prices reflect fundamentals of long-term demand and supply. This is the standard approach TCR uses in its long-term modeling; it is generally consistent with the approach the Avoided Energy Supply Cost (AESC) studies have used since 2007.

Figure 9 plots TCR’s forecast of annual Henry Hub prices, S&P Global’s Henry Hub futures as well as the AEO 2019 forecasts for its Reference Case. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 141 of 210 $8.00

$7.00

$6.00

$5.00

$4.00

$3.00 2019$ 2019$ / MMBtu

$2.00

$1.00

$- 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046

Historic Actuals AEO 2019 Reference Case S&P Global Henry Hub Futures TCR Forecast

Figure 9. TCR and AEO 2019 projections of Henry Hub prices, 2019$

TCR develops its projection of monthly Henry Hub prices from its projection of annual prices using the historical ratios of monthly prices at Henry Hub to annual prices at Henry Hub.

13.1.2: Spot gas prices in New England TCR develops projections of the monthly spot price of natural gas to each gas-fired unit in New England based upon the projections of spot prices at the market hub which serves the unit. The projections of natural gas spot prices at each market hub equals the TCR projection of monthly Henry Hub prices plus the TCR projection of monthly basis differential to each market hub from the Henry Hub.

TCR develops its projection of monthly basis between Henry Hub and each New England market hub for the period January 2022 through December 2027 from projections of basis for those hubs drawn from S&P Global. TCR develops its projection of monthly basis between Henry Hub and each New England market hub from January 2028 onward based upon an assumption that basis will remain relatively constant in 2018$ dollars over that period.

Figure 10 plots the TCR forecast of monthly spot prices at the Henry Hub and the Algonquin hub in 2018$. This Figure indicates that the TCR forecast of gas prices to electric generating units shows significant variation between prices in winter months and prices in summer months. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 142 of 210 $12.00

$10.00

$8.00

$6.00

$4.00 2019 2019 $/MMBtu

$2.00

$0.00 7/2019 7/2020 7/2021 7/2022 7/2023 7/2024 7/2025 7/2026 7/2027 7/2028 7/2029 7/2030 7/2031 7/2032 7/2033 7/2034 7/2035 7/2036 7/2037 7/2038 7/2039 7/2040 7/2041 7/2042 7/2043 7/2044 7/2045 7/2046

TCR forecasted Algonquin Gates prices TCR forecasted Henry Hub prices

Figure 10. Projections of spot prices in New England (2019$/MMBtu)

The projections of monthly basis underlying the TCR projections of monthly spot gas prices in New England are consistent with two basic assumptions regarding gas pipeline capacity over the study period, 2022 - 2046. First, TCR assumes gas utilities will be able to acquire any additional capacity they may need to meet growth in their retail load. Second, TCR assumes that the gas pipeline capacity available to deliver gas to electric generating units on average each day, particularly in the winter months of December through February, will be limited to the pipeline capacity expected to be in- service as of November 2020 less the aggregate quantity of gas utilities require each day.

Table 26 presents our assumptions regarding gas pipeline capacity as of November 2020 and average daily demand in the winter months of December through January. TCR developed the assumptions regarding capacity based upon data reported in the AESC 2018 report and on data reported by the Northeast Gas Association. The estimates of average daily gas use by gas utilities (LDCs) and electric generating units during the three major winter months of December, January and February is based upon actual gas use in those months in 2015/2016 and in 2017/2018. A comparison of the average daily gas use data and the assumed gas pipeline and direct delivery capacity indicates that the issue of adequate pipeline capacity to serve gas-fired generating units primarily occurs on days of peak gas use during those three months rather than on days of average gas use throughout the winter, i.e., on 10 to 20 days per winter rather than on every day during the winter.

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 143 of 210 Table 26. Assumptions regarding gas pipeline capacity serving New England

TCR assumptions re gas delivery capacity and average demand (Dec, Jan, Feb) New England (Bcf/d)

Projected in Existing January Additions in service by November Major Sources of Capacity service - 2018 (1) 2020 (1, 2) November 2020 Bcf/d addition Bcf/d Bcf/d Algonquin (ALG) 1.82 Atlantic Bridge 0.13 1.95 Tennessee (TGP) 1.39 Station 261 0.10 1.49 Iroquois 0.26 0.26 Portland Natural Gas (PNGTS) 0.21 Portland Xpress 0.05 0.26 Vaughan Mainline Vermont Gas 0.07 0.04 0.11 Expansion M&N Pipeline 0.83 0.83 Distrigas to Mystic units 0.70 0.70 Total 5.28 5.61

Projected Average daily demand Dec - Feb (3) LDCs 2.17 Electric Generating units 0.90 Total 3.07

Sources 1. Synapse Energy Economics. Amended AESC 2018. pp 35-36. 2. Northeast Gas Association. Planned Enhancements, Northeast Natural Gas Pipeline Systems (10-17-18). 3. TCR analysis of EIA statistics on gas use by month by state in New England.

TCR’s assumption regarding the availability of adequate gas pipeline capacity to serve gas-fired units on most winter days over the study period, recognizing that some gas-fired units that dual-fuel capability, is informed by the following facts and assumptions. First, starting from June 2018, gas- fired capacity is subject to the new ISO NE performance requirements and face financial penalties for non-performance. Second, based upon TCR’s modeling of the Vineyard Wind 800 MW GLL Case, the average quantity of gas per day required by gas-fired units during the study period, particularly on winter days, is likely to be less than the average daily quantity assumed for the winter of 2020/2021, as described in Appendix C.

13.2: Prices of distillate and residual fuel oil for electric generation in New England. Table Appendix B-2 in Appendix B provides the 83C Phase II Base Case projections of distillate and residual to electric generators in New England from 2022 to 2046. These projections are drawn from AEO 2019 and expressed in 2019$.

13.3: Winter fuel switching for dual fuel generators D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 144 of 210 Because of natural gas pipeline supply constraint in New England, generators often experience gas shortages in extreme winter days. During gas shortage days, dual fuel generators switch fuel from natural gas to fuel oil due to economic reasons and/or operational requirements. TCR modeled winter fuel switching mechanic to approximate the economic and environmental impact resulting from dual fuel generators switching from natural gas to fuel oil on winter days with high natural gas prices. Appendix C outlines TCR’s modeling approach on fuel switching mechanics.

13.4: Uranium Prices TCR develops uranium prices using the pricing calculator created by the Bulletin of the Atomic Scientist26. The calculator estimates the cost of electricity assuming the nuclear fuel cycle is “Once- Through”. TCR omits all capital related cost associated with the cost of electricity from the calculator. The resulting uranium price is 0.99 Nominal $/MMBtu, which TCR assumed to be fixed.

13.5: Coal Prices TCR develops plant level coal price from S&P Global’s power plant operations data base. TCR derives coal cost in $/MMBtu by dividing S&P Global reported annual cost of coal delivered ($/ton) by annual average heat content of coal burned (Btu/lbs.). Based on this method, TCR calculates the exact coal cost for plants where data is available. For plants without sufficient data, TCR assumes the average cost from other coal plants in the same area and/or state.

TCR developed coal cost for this project using 2015-2017 coal price data by plant from S&P Global Services and converted said prices to real 2019 $/MMBtu. TCR assumes the prices reported in will remain at those levels over the study period.

26 http://thebulletin.org/nuclear-fuel-cycle-cost-calculator/model D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 145 of 210 CHAPTER 14: Emission Rates

14.1: Emission Rates

Emission rates for NOx and SO2 are obtained from historical S&P Global’s Unit and Plant emission rates data. For future generating units under construction for which there are no emission rates, generic EIA emission data are used.27 For existing units for which no emission rates were reported, emission rate by fuel type from EIA is used. CO2 emission rates by fuel type are taken from EPA’s “Fuel and Carbon Dioxide Emissions Savings Calculation Methodology for Combined Heat and Power Systems.”28

14.2: Greenhouse Gas Emission Allowance Prices

TCR developed its CO2 allowance price assumptions based upon a review of projections RGGI prepared as part of its 2017 Program Review. RGGI developed a new Model Rule, and projected corresponding

CO2 emissions and prices for six representative years over the period 2017-2031 (the Base Model Rule Policy Case). RGGI also ran studies to test the sensitivity of its projections to changes in various assumptions such as gas prices, nuclear retirements, transmission additions between Canada and New England, renewable costs, the addition of 1600 MW offshore wind, and whether a national policy (i.e., the Clean Power Plan) would be in place. The RGGI simulations of the Model Rule and associated sensitivity studies are documented in RGGI Program Review meeting materials.29

TCR, based upon its review of the RGGI scenarios, developed the Base Case CO2 allowance price using a curve fit to RGGI’s 2017 Model Rule Policy Case projection. Table 27 presents the Base Case CO2 allowance price assumptions.

Table 27. Base Case CO2 Allowance Price Assumptions (2019$/short ton) Year 2022 2023 2024 2025 2026 2027 2028 2029 Price 6.92 7.22 7.55 7.89 8.26 8.65 9.07 9.50 Year 2031 2032 2033 2034 2035 2036 2037 2038 Price 10.44 10.94 11.46 12.00 12.57 13.16 13.77 14.40 Year 2040 2041 2042 2043 2044 2045 2046 Price 15.73 16.43 17.14 17.89 18.65 19.43 20.24

Figure 11 plots the Base Case price assumptions as well as the RGGI projection for the Model Rule Policy Scenario.

27 https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capcost_assumption.pdf 28 https://www.epa.gov/sites/production/files/2015-07/documents/emission-factors_2014.pdf 29 “Draft 2017 Model Rule Policy Scenario Overview,” prepared for RGGI by ICF International, September 25, 2017. Numeric values for CO2 prices taken from Draft_IPM_Results_Model_Rule.xlsx. Available at https://www.rggi.org/program-overview-and-design/program- review. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 146 of 210

Figure 11. 83C II Base Case Assumptions relative to RGGI and ISO-NE CO2 Allowance Price Projections as of September 2017

14.3: NOx and SO2

TCR assumed allowance prices of zero for NOx and SO2 emissions. The Federal Cross State Air

Pollution Rule (CSAPR) establishes NOx and SO2 emission limits, and no New England state has emission limits under CSAPR. Therefore, CSAPR allowance prices are not applicable to New England generators.

SO2. With the retirement of Brayton Point, SO2 emissions in New England have dropped to levels near zero and correspondingly we assume zero value for SO2 allowances for the applicable state acid rain programs.

NOx. In accordance with Governor Baker’s Executive Order 562 and to meet federal Clean Air Act requirements, MA DEP in August 2016 proposed to replace the Massachusetts Clean Air Interstate Rule (310 CMR 7.32) with a new Ozone Season Nitrogen Oxides Control (310 CMR 7.34). The rule was intended to meet a 2017 (and beyond) budget for NOx emissions from large fossil-fuel-fired electric power and steam generating units during the ozone season (May 1st through September 30th). The proposed Massachusetts Ozone Season NOx budget is 1,799 tons. NOx ozone season emissions from all sources have been decreasing, and over the past five years have ranged between 975 and 1,620 tons.

As a result, we ascribe zero value to NOx allowances in Massachusetts. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 147 of 210 On September 9, 2016, US EPA approved a State Implementation Plan revision submitted by

Connecticut. This revision continues to allow facilities to create and/or use emission credits using NOx

Emission Trading and Agreement Orders (TAOs) to comply with the NOx emission limits required by RCSA section 22a-174-22 (Control of Nitrogen Oxides), which imposes emissions rate limits on generators. It is possible that under this rule NOx DERCs, or allowances, will have value to certain individual generators. Lacking evidence of a liquid market or visible pricing for such allowances in Connecticut, we are assuming their value to be zero. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 148 of 210 GLOSSARY

Term Definition

10MNSR 10 Minute Non-Spinning Reserve

10MSR 10 Minute Spinning Reserve

30MR 30 Minute Reserves

ACP Alternative Compliance Payments

ADR Active Demand Response

AEO Annual Energy Outlook

AESC Avoided Energy Supply Cost

ALG Algonquin

BIO Biomass

BMPV/ BTM PV Behind-the-meter Photovoltaic

CAGR Compound Annual Growth Rate

CC Combined Cycle

CEA Concentric Energy Advisors

CEC Clean Energy Credits

CECP Clean Energy and Climate Plan

CEII Critical Energy Infrastructure Information

CELT Capacity, Energy, Loads, and Transmission

CES Clean Energy Standard

CMR Code of Massachusetts Regulations

COD Commercial Operation/Online Date

CPP Clean Power Plan

CSAPR Cross-State Air Pollutions Rule

CT Combustion Turbine

CT PURA Connecticut Public Utilities Regulatory Authority

DA Day-ahead

DEP Department of Environmental Protection D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 149 of 210 Term Definition

DERC Discrete Emission Reduction Credits

DFO Distillate Fuel Oil

E&AS Energy and Ancillary Services

EDC Electric Distribution Company

EEA Energy and Environmental Affairs

EFORd Effective Forced Outage Rates

EGU Electric Generating Units

EIA Energy Information Administration

EIPC Eastern Interconnection Planning Collaborative

EPA Environmental Protection Agency

FCA Forward Capacity Auction

FCM Forward Capacity Market

FERC Federal Energy Regulatory Commission

FLHR Full Load Heat Rate

FOM Fixed Operation & Maintenance

GHG Greenhouse Gas

Gold Book NYISO’s Load & Capacity Data Report

GSC Generator Supply Curve

GT Gas Turbine

GWSA Global Warming Solutions Act

HD Hydro Power

HVDC High Voltage Direct Current

IC Internal Combustion (reciprocating) Engine

ICAP Installed Capacity

ICR Installed Capacity Requirements

ITC Investment Tax Credit

Kirchhoff’s laws the current law and the voltage law

LDC Load Distribution Company D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 150 of 210 Term Definition

LMP Locational Marginal Price

LSE Load Serving Entity

LSR Local Sourcing Requirement

MA DEP Massachusetts Department of Environmental Protection

MIP Mixed Integer Programming

MLP Municipal Light Plant

MMD Market Model Database

NEL Net Energy Load

NEPOOL GIS New England Power Pool Generation Information System

NERC North American Electric Reliability Corporation

NG Natural Gas

NREL National Renewable Energy Laboratory

PDR Passive Demand Response

PME Power Market Explorer

PNGTS Portland Natural Gas

PPA Power Purchase Agreement

PS Pumped Storage Unit

PSO Power System Optimizer

PTC Production Tax Credit

PV Photovoltaic

PVWatts® NREL’s PV Calculator

RCSA Regulations of Connecticut State Agencies

REC Renewable Energy Certificate, Renewable Energy Credit

RFO Residual Fuel Oil

RFP Requests for Proposal

RGGI Regional Greenhouse Gas Initiative

RMR Reliability Must Run

RPS Renewable Portfolio Standard D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 151 of 210 Term Definition

RT Real-time

SCED Security Constrained Economic Dispatch

SCUC Security Constrained Unit Commitment

SENE Southeast New England

SMART Solar Massachusetts Renewable Target

ST Steam Turbine

SUN Solar Powered

TAO Trading and Agreement Orders

TARA tool Transmission Adequacy & Reliability Assessment tool

TGP Tennessee Gas Pipeline

TMNSR Ten-Minute Non-Spinning Reserve

TMOR Thirty-Minute Operating Reserve

TMSR Ten-Minute Spinning Reserve

VOM Variable Operation & Maintenance

WACC weighted average cost of capital

WAT Water

WIND (NREL) Wind Integration National Dataset

WT Wind Turbine

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 152 of 210 APPENDIX A: ENELYTIX

This Appendix describes the computer model and analytical capability TCR uses to support the evaluation of 83C II Proposed Clean Energy Projects.

A.1: ENELYTIX® and Power System Optimizer (PSO) ENELYTIX®30 is a cloud based energy market simulation environment implemented on Amazon EC2 commercial cloud.

A central element of ENELYTIX is the Power System Optimizer (“PSO”), an advanced simulator of power markets. PSO provides ENELYTIX the capability to accurately model the decision processes used in a wide range of power planning and market structures including long-term system expansion, capacity markets, Day-ahead energy markets and Real-time energy markets. ENELYTIX has this capability because it can configure PSO to determine the optimum solution to each market structure. Figure A-1 illustrates the four key components of the PSO analytical structure: Inputs, Models, Algorithms and Outputs.

As a system expansion optimization model, PSO integrates resource adequacy requirements with the specific design of the capacity market and with the environmental compliance policies, such as state- level and regional Renewable Portfolio Standards (RPS) and emission constraints.

As a production cost model, PSO is built on a Mixed Integer Programming (MIP) based unit commitment and economic dispatch structure that simulates the operation of the electric power system. PSO determines the security-constrained commitment and dispatch of each modeled generating unit, the loading of each element of the transmission system, and the locational marginal price (LMP) for each generator and load area. PSO supports both hourly and sub hourly timescales. In this project, the PSO is set up to model unit commitment (DA market) and an economic dispatch (RT market). In the commitment process, generating units in a region are turned on or kept on in order for the system to have enough generating capacity available to meet the expected peak load and required operating reserves in the region for the next day. PSO then uses the set of committed units to dispatch the system on an hourly real-time basis, whereby committed units throughout the modeled footprint are operated between their minimum and maximum operating points to minimize total production costs. The unit commitment in PSO is formulated as a mixed integer linear programming optimization problem which is solved to the true optima using the commercial CPLEX solver.

As an FCM Capacity Market Model, PSO is configured to simulate the outcome of the ISO-NE’s Forward Capacity Auction subject to market specific rules and parameters develop projections of capacity prices.

30 ENELYTIX® is a registered trademark of Newton Energy Group, LLC.f D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 153 of 210

Figure A - 1. Analytical Structure of PSO The ENELYTIX/PSO modeling environment provides a realistic, objective and highly defendable analyses of the physical and financial performance of power systems, in particular power systems integrating variable renewable resources. The critical advantage of PSO over traditional production costing modeling tools is its ability to model the concurrent dynamics of:

• uncertainty of future conditions of the power system;

• the scope, physical capabilities and economics of options available to the system operator to respond to these uncertain conditions;

• the timing and optionality or irreversibility of operator’s decisions to exercise these options.

By capturing these concurrent dynamics, ENELYTIX/PSO avoids the generally recognized inability of traditional simulation tools to reflect the effect of operational decisions on the physics of the power system, price formation and financial performance of physical and financial assets.

A.1.1: Modeling the Impact of Uncertainty System operators deal with a number of uncertainties in the data they use for their day-ahead decisions that ultimately impact operations and prices in the real-time market. These uncertainties typically include differences between forecast and actual load; forecast and actual output of variable generation; and forecast versus actual generation and transmission outages.

ENELYTIX/PSO offers the most realistic representation of the impact of those uncertainties between day-ahead decisions and real-time dispatch. ENELYTIX/PSO provides information, data structures and algorithms necessary for the realistic representation of these uncertainties including different load D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 154 of 210 shapes and wind patterns for modeling the Day-ahead and Real-time markets. It also has embedded methods for incorporating forecast errors if explicit forecasts are not available, and model representation of time points at which the system becomes aware of generator outages.

System operators’ options for responding to these uncertainties include (1) generation commitment decisions based on day-ahead and intra-day reliability assessments, (2) forward-looking procurement of ancillary services and (3) deployment of reserves when uncertainty is realized. ENELYTIX/PSO provides unique capabilities to model the process by which system operators rely on these options. The model allows the user to specify the decision timing and (at each decision point) to determine classes of decisions that are still provisional and can be revisited at a later stage, and classes of decisions that are final and therefore irreversible. These capabilities are critical for an accurate representation of forward commitments, actual dispatch decisions, curtailments, emergence of scarcity events and corresponding price formation. The ENELYTIX/PSO represents these concurrent dynamics through the use of the decision cycle logic and rolling horizon optimization.

A.1.2: ENELYTIX modeling architecture ENELYTIX provides the advanced modeling features of PSO and the scalability of cloud computing. With the ENELYTIX cloud-based architecture, TCR can generate, simulate and post process a large number of Cases in a matter of hours. What we can turn around in an hour competing models require 10 days.

Figure A-2 illustrates the ENELYTIX architecture. This Figure highlights the system services that support parallel processing of simulation projects. As shown in that Figure, a Project consists of Tasks. Each Task is a collection of Cases, and each Case is partitioned into Segments which could be processed in parallel. In ENELYTIX, implementation of a Task is a single-click experience. Once the Task is launched, it invokes a process in which all user requested Cases are generated at once out of the Market Model Database (MMD) pre-populated with model data. Cases are formed by specifying alternative versions of inputs (e.g. alternative supply options or portfolios of such options, load forecast, new entry and retirement assumptions or fuel price sensitivities, types and requirements for ancillary services and myriads of other alternatives the user may need to explore and compare against each other within the same task). D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 155 of 210

Figure A-2. Schematic of ENELYTIX Architecture

ENELYTIX automatically partitions each Case into Segments for parallel execution. Segments are queued and sent to servers dynamically procured on the cloud to be processed with PSO.

ENELYTIX collects output results, merges Segment related outputs corresponding to the same Case and sends both outputs and inputs to the Power Market Explorer (PME) Cube. PME is a multi-dimensional cube structure directly accessible from an Excel workbook on the user’s desktop or laptop which provides self-service analytics for detailed exploration of output results in their entirety, side-by-side comparisons across cases, decision cycles, over time and numerous other dimensions. With PME, the user obtains instantaneous report generation via PivotTables and graphics via PivotCharts extracted directly from the PME cube. Although configurable, PME already comes with conveniently pre- calculated metrics including wholesale consumer payments, system-wide and regional adjusted production costs, emissions, curtailments, fuel use and detailed reports on assets’ physical and financial performance.

ENELYTIX complies with high standards of data security properly protecting confidential and Critical Energy Infrastructure Information (CEII).

For additional information about ENELYTIX, visit www.enelytix.com. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 156 of 210

APPENDIX B: Fuel Price Forecast

B.1: Natural Gas Forecast Prices

Table Appendix B-1. Monthly Spot Gas Pries (2019 $/MMBtu) Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 1/2022 9.198 9.360 5.515 9.429 2/2022 9.143 9.305 5.352 9.374 3/2022 5.391 5.552 3.701 5.621 4/2022 3.198 3.428 2.513 3.171 5/2022 2.522 2.751 2.427 2.494 6/2022 2.525 2.754 2.552 2.497 7/2022 2.704 2.932 2.574 2.676 8/2022 2.662 2.889 2.557 2.634 9/2022 2.361 2.588 2.439 2.334 10/2022 2.622 2.849 2.564 2.595 11/2022 4.204 4.363 2.648 4.431 12/2022 7.123 7.281 3.562 7.349 1/2023 9.697 9.855 5.454 9.923 2/2023 9.635 9.793 5.292 9.860 3/2023 5.746 5.903 3.722 5.971 4/2023 3.329 3.553 2.641 3.302 5/2023 2.679 2.903 2.572 2.652 6/2023 2.694 2.917 2.706 2.667 7/2023 2.881 3.103 2.739 2.854 8/2023 2.846 3.068 2.729 2.819 9/2023 2.553 2.774 2.616 2.526 10/2023 2.816 3.037 2.744 2.789 11/2023 4.341 4.496 2.796 4.562 12/2023 7.191 7.345 3.682 7.411 1/2024 9.748 9.902 5.552 9.969 2/2024 9.690 9.844 5.397 9.910 3/2024 5.906 6.060 3.893 6.125 4/2024 3.448 3.667 2.866 3.422 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 157 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 5/2024 2.830 3.048 2.795 2.803 6/2024 2.835 3.053 2.917 2.809 7/2024 3.004 3.221 2.940 2.977 8/2024 2.966 3.183 2.925 2.940 9/2024 2.688 2.905 2.815 2.662 10/2024 2.936 3.152 2.938 2.910 11/2024 4.382 4.533 2.955 4.598 12/2024 7.074 7.225 3.804 7.290 1/2025 9.569 9.719 5.674 9.784 2/2025 9.512 9.662 5.524 9.727 3/2025 5.964 6.114 4.107 6.178 4/2025 3.724 3.938 3.159 3.698 5/2025 3.116 3.330 3.086 3.091 6/2025 3.123 3.336 3.207 3.098 7/2025 3.290 3.503 3.232 3.265 8/2025 3.260 3.472 3.224 3.234 9/2025 2.990 3.202 3.117 2.965 10/2025 3.231 3.443 3.237 3.206 11/2025 4.538 4.686 3.220 4.749 12/2025 7.093 7.240 4.043 7.303 1/2026 9.365 9.512 5.749 9.575 2/2026 9.309 9.456 5.602 9.519 3/2026 5.948 6.094 4.236 6.157 4/2026 3.885 4.094 3.336 3.860 5/2026 3.287 3.495 3.260 3.261 6/2026 3.293 3.501 3.378 3.268 7/2026 3.457 3.665 3.404 3.432 8/2026 3.429 3.637 3.397 3.404 9/2026 3.170 3.377 3.297 3.145 10/2026 3.413 3.620 3.422 3.388 11/2026 4.599 4.744 3.381 4.805 12/2026 7.024 7.168 4.178 7.230 1/2027 9.133 9.277 5.774 9.338 2/2027 9.081 9.224 5.634 9.286 3/2027 5.895 6.038 4.316 6.099 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 158 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 4/2027 4.009 4.213 3.475 3.984 5/2027 3.427 3.631 3.404 3.403 6/2027 3.435 3.639 3.522 3.411 7/2027 3.597 3.801 3.548 3.573 8/2027 3.572 3.775 3.544 3.548 9/2027 3.319 3.521 3.447 3.295 10/2027 3.555 3.757 3.567 3.531 11/2027 4.620 4.761 3.495 4.821 12/2027 6.917 7.058 4.261 7.119 1/2028 8.871 9.012 5.752 9.072 2/2028 8.819 8.959 5.614 9.019 3/2028 5.798 5.938 4.343 5.998 4/2028 4.059 4.258 3.539 4.035 5/2028 3.483 3.682 3.463 3.459 6/2028 3.493 3.692 3.580 3.469 7/2028 3.660 3.858 3.614 3.636 8/2028 3.656 3.854 3.631 3.632 9/2028 3.417 3.615 3.545 3.393 10/2028 3.665 3.863 3.680 3.641 11/2028 4.620 4.758 3.581 4.817 12/2028 6.799 6.937 4.318 6.996 1/2029 8.877 9.017 5.765 9.077 2/2029 8.824 8.965 5.627 9.025 3/2029 5.811 5.951 4.359 6.010 4/2029 4.073 4.273 3.555 4.049 5/2029 3.499 3.698 3.479 3.475 6/2029 3.509 3.708 3.596 3.485 7/2029 3.676 3.874 3.630 3.652 8/2029 3.672 3.870 3.647 3.648 9/2029 3.434 3.632 3.562 3.410 10/2029 3.682 3.879 3.697 3.658 11/2029 4.635 4.773 3.599 4.832 12/2029 6.811 6.948 4.335 7.007 1/2030 8.904 9.044 5.799 9.104 2/2030 8.851 8.991 5.661 9.051 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 159 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 3/2030 5.843 5.983 4.395 6.043 4/2030 4.107 4.305 3.590 4.083 5/2030 3.533 3.732 3.513 3.509 6/2030 3.544 3.742 3.631 3.520 7/2030 3.711 3.909 3.666 3.687 8/2030 3.708 3.905 3.683 3.684 9/2030 3.471 3.668 3.598 3.447 10/2030 3.719 3.916 3.733 3.695 11/2030 4.671 4.809 3.637 4.868 12/2030 6.845 6.983 4.374 7.042 1/2031 8.880 9.020 5.780 9.080 2/2031 8.828 8.967 5.642 9.027 3/2031 5.825 5.964 4.379 6.024 4/2031 4.091 4.290 3.575 4.067 5/2031 3.519 3.717 3.499 3.495 6/2031 3.530 3.728 3.617 3.506 7/2031 3.696 3.894 3.651 3.673 8/2031 3.693 3.890 3.669 3.669 9/2031 3.456 3.653 3.583 3.433 10/2031 3.704 3.901 3.718 3.680 11/2031 4.655 4.792 3.622 4.851 12/2031 6.826 6.963 4.358 7.021 1/2032 9.018 9.157 5.922 9.217 2/2032 8.964 9.103 5.783 9.163 3/2032 5.962 6.101 4.518 6.161 4/2032 4.220 4.418 3.705 4.196 5/2032 3.647 3.845 3.628 3.624 6/2032 3.659 3.857 3.746 3.636 7/2032 3.827 4.024 3.782 3.803 8/2032 3.825 4.022 3.801 3.802 9/2032 3.589 3.786 3.716 3.565 10/2032 3.838 4.034 3.852 3.814 11/2032 4.790 4.927 3.758 4.986 12/2032 6.963 7.100 4.499 7.158 1/2033 9.073 9.213 5.983 9.272 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 160 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 2/2033 9.018 9.158 5.843 9.217 3/2033 6.020 6.159 4.579 6.219 4/2033 4.276 4.474 3.762 4.253 5/2033 3.704 3.902 3.685 3.680 6/2033 3.717 3.914 3.803 3.693 7/2033 3.885 4.082 3.840 3.861 8/2033 3.883 4.080 3.859 3.860 9/2033 3.648 3.844 3.774 3.624 10/2033 3.897 4.093 3.911 3.873 11/2033 4.848 4.985 3.819 5.044 12/2033 7.020 7.157 4.561 7.215 1/2034 9.111 9.250 6.026 9.309 2/2034 9.055 9.194 5.886 9.254 3/2034 6.062 6.200 4.623 6.260 4/2034 4.317 4.514 3.803 4.293 5/2034 3.745 3.942 3.726 3.722 6/2034 3.758 3.955 3.844 3.734 7/2034 3.926 4.123 3.881 3.903 8/2034 3.925 4.122 3.901 3.902 9/2034 3.690 3.886 3.817 3.667 10/2034 3.940 4.135 3.954 3.916 11/2034 4.890 5.027 3.863 5.085 12/2034 7.060 7.197 4.606 7.255 1/2035 9.147 9.286 6.068 9.346 2/2035 9.091 9.230 5.928 9.289 3/2035 6.102 6.240 4.666 6.299 4/2035 4.356 4.554 3.844 4.333 5/2035 3.785 3.982 3.766 3.762 6/2035 3.799 3.995 3.885 3.775 7/2035 3.967 4.163 3.922 3.943 8/2035 3.967 4.162 3.942 3.943 9/2035 3.732 3.927 3.858 3.709 10/2035 3.981 4.176 3.995 3.958 11/2035 4.931 5.067 3.905 5.125 12/2035 7.098 7.234 4.649 7.293 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 161 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 1/2036 9.221 9.359 6.148 9.419 2/2036 9.163 9.302 6.007 9.361 3/2036 6.178 6.316 4.745 6.376 4/2036 4.430 4.627 3.919 4.406 5/2036 3.860 4.056 3.840 3.836 6/2036 3.873 4.069 3.959 3.850 7/2036 4.042 4.238 3.997 4.019 8/2036 4.042 4.238 4.018 4.019 9/2036 3.809 4.003 3.934 3.785 10/2036 4.058 4.253 4.072 4.035 11/2036 5.007 5.143 3.984 5.201 12/2036 7.173 7.309 4.730 7.367 1/2037 9.231 9.369 6.166 9.428 2/2037 9.173 9.311 6.024 9.370 3/2037 6.195 6.332 4.765 6.391 4/2037 4.448 4.644 3.938 4.425 5/2037 3.879 4.075 3.859 3.855 6/2037 3.893 4.088 3.978 3.869 7/2037 4.061 4.257 4.017 4.038 8/2037 4.062 4.257 4.038 4.039 9/2037 3.829 4.023 3.954 3.805 10/2037 4.078 4.272 4.092 4.055 11/2037 5.025 5.161 4.004 5.219 12/2037 7.188 7.323 4.750 7.381 1/2038 9.230 9.368 6.172 9.427 2/2038 9.172 9.310 6.031 9.369 3/2038 6.201 6.338 4.774 6.397 4/2038 4.457 4.652 3.947 4.433 5/2038 3.888 4.084 3.869 3.865 6/2038 3.902 4.097 3.988 3.879 7/2038 4.071 4.266 4.026 4.047 8/2038 4.072 4.266 4.048 4.048 9/2038 3.839 4.033 3.964 3.816 10/2038 4.088 4.282 4.102 4.065 11/2038 5.033 5.169 4.015 5.227 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 162 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 12/2038 7.192 7.327 4.759 7.385 1/2039 9.243 9.380 6.192 9.439 2/2039 9.185 9.322 6.050 9.381 3/2039 6.219 6.356 4.796 6.415 4/2039 4.476 4.672 3.969 4.453 5/2039 3.909 4.104 3.890 3.886 6/2039 3.924 4.118 4.009 3.900 7/2039 4.092 4.286 4.047 4.069 8/2039 4.093 4.287 4.069 4.070 9/2039 3.861 4.055 3.986 3.838 10/2039 4.110 4.303 4.124 4.086 11/2039 5.053 5.188 4.037 5.246 12/2039 7.208 7.343 4.782 7.400 1/2040 9.296 9.433 6.252 9.492 2/2040 9.237 9.374 6.110 9.432 3/2040 6.277 6.413 4.857 6.472 4/2040 4.533 4.728 4.026 4.510 5/2040 3.967 4.161 3.947 3.943 6/2040 3.981 4.175 4.066 3.958 7/2040 4.150 4.344 4.106 4.127 8/2040 4.152 4.345 4.128 4.129 9/2040 3.920 4.113 4.045 3.897 10/2040 4.169 4.362 4.183 4.146 11/2040 5.111 5.246 4.098 5.304 12/2040 7.264 7.398 4.844 7.456 1/2041 9.271 9.407 6.235 9.466 2/2041 9.212 9.348 6.093 9.407 3/2041 6.259 6.395 4.843 6.454 4/2041 4.520 4.714 4.015 4.497 5/2041 3.955 4.149 3.936 3.932 6/2041 3.970 4.163 4.054 3.946 7/2041 4.138 4.331 4.093 4.115 8/2041 4.139 4.332 4.116 4.116 9/2041 3.909 4.101 4.033 3.885 10/2041 4.157 4.349 4.171 4.133 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 163 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 11/2041 5.096 5.231 4.086 5.288 12/2041 7.242 7.376 4.829 7.434 1/2042 9.303 9.439 6.275 9.498 2/2042 9.243 9.379 6.133 9.438 3/2042 6.297 6.433 4.886 6.492 4/2042 4.559 4.753 4.055 4.536 5/2042 3.995 4.189 3.976 3.972 6/2042 4.010 4.203 4.095 3.987 7/2042 4.178 4.371 4.134 4.155 8/2042 4.181 4.373 4.157 4.157 9/2042 3.950 4.143 4.074 3.927 10/2042 4.198 4.390 4.212 4.175 11/2042 5.136 5.270 4.129 5.328 12/2042 7.279 7.412 4.872 7.469 1/2043 9.355 9.491 6.337 9.550 2/2043 9.295 9.431 6.194 9.489 3/2043 6.356 6.492 4.948 6.550 4/2043 4.617 4.810 4.114 4.594 5/2043 4.054 4.247 4.035 4.031 6/2043 4.069 4.262 4.154 4.046 7/2043 4.238 4.430 4.194 4.215 8/2043 4.241 4.432 4.217 4.218 9/2043 4.011 4.203 4.135 3.988 10/2043 4.259 4.450 4.273 4.236 11/2043 5.195 5.329 4.191 5.386 12/2043 7.334 7.467 4.935 7.524 1/2044 9.427 9.562 6.418 9.620 2/2044 9.365 9.500 6.274 9.558 3/2044 6.433 6.569 5.030 6.626 4/2044 4.692 4.885 4.192 4.669 5/2044 4.131 4.323 4.111 4.107 6/2044 4.147 4.339 4.231 4.124 7/2044 4.315 4.507 4.272 4.292 8/2044 4.319 4.510 4.295 4.296 9/2044 4.091 4.281 4.214 4.068 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 164 of 210 Date Algon Gates Tennessee at Dracut Iroquois Zone 1 Tennessee Zone 6 10/2044 4.339 4.529 4.353 4.316 11/2044 5.274 5.407 4.272 5.464 12/2044 7.409 7.542 5.018 7.599 1/2045 9.490 9.625 6.491 9.683 2/2045 9.427 9.562 6.347 9.620 3/2045 6.504 6.638 5.105 6.696 4/2045 4.761 4.953 4.262 4.738 5/2045 4.201 4.392 4.182 4.178 6/2045 4.217 4.409 4.301 4.194 7/2045 4.386 4.577 4.343 4.363 8/2045 4.391 4.581 4.367 4.368 9/2045 4.163 4.353 4.286 4.140 10/2045 4.411 4.601 4.425 4.389 11/2045 5.344 5.477 4.347 5.534 12/2045 7.476 7.609 5.094 7.665 1/2046 9.529 9.663 6.540 9.721 2/2046 9.465 9.600 6.395 9.657 3/2046 6.550 6.684 5.157 6.742 4/2046 4.809 5.000 4.312 4.786 5/2046 4.249 4.440 4.231 4.227 6/2046 4.267 4.457 4.350 4.244 7/2046 4.436 4.626 4.392 4.413 8/2046 4.441 4.631 4.417 4.418 9/2046 4.214 4.404 4.336 4.191 10/2046 4.462 4.651 4.476 4.439 11/2046 5.393 5.525 4.399 5.582 12/2046 7.520 7.652 5.146 7.709

B.2: Fuel Oil Prices Projection

Table Appendix B-2. Fuel Oil Prices Projection 2022-2046 Year Distillate Oil Price (2019 $/MMBtu) Residual Oil Price (2019 $/MMBtu) 2022 20.150 12.141 2023 19.544 11.828 2024 19.303 11.693 2025 19.673 11.920 2026 20.124 12.326 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 165 of 210 2027 20.812 12.881 2028 20.960 13.082 2029 21.435 13.505 2030 21.599 13.612 2031 21.806 13.816 2032 22.089 14.056 2033 22.477 14.144 2034 22.504 14.288 2035 22.715 14.429 2036 23.131 14.673 2037 23.024 14.798 2038 23.202 14.849 2039 23.368 14.999 2040 23.603 15.109 2041 23.685 15.200 2042 23.916 15.425 2043 23.951 15.462 2044 23.961 15.454 2045 24.043 15.540 2046 24.046 15.545

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 166 of 210 APPENDIX C: Winter Fuel Switching Modeling

To estimate the impact on market operations and incremental CO2 emissions resulting from dual-fuel unit switching from gas to fuel oil on winter days with high gas prices TCR has developed an approach to modeling that switching. That approach involves the following key steps:

1. Estimate the number of days when switching from gas to oil is assumed to occur each year. To develop that estimate, TCR reviewed historical prices for No.2 Distillate fuel oil to identify days when Fuel oil 2 price dropped below the price of natural gas and take an average of that over several years31.

2. Reviewed daily gas burn quantities during winter months from the MA 83C II cases and develop a ‘gas burn limit’ such that the number of days in the simulation in which the gas burn exceeds the limit is equal to the assumed number of days of fuel switching identified in step 1 above.

3. Imposed the gas burn limit on all gas-fired power plants over the winter period i.e. December through February. Introduced a penalty cost for exceeding the burn limit equal to the price of fuel oil. Imposing that constraint emulates the fuel switching process in which only limited number of dual-fuel units will switch to oil

4. Developed a CO2 emission multiplier to adjust for additional emissions from fuel oil operation and apply it over the period that the penalty cost is applied for the base case and each proposal case.

31 TCR did not estimate the number of fuel switching days based on projections of gas prices and fuel prices as these projections were not granular enough for the analysis. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 167 of 210 C.1: Estimating number of fuel switching days each year In order to determine the number of days that the price of natural exceeded the price of fuel oil, TCR reviewed historic prices over a ten-year period for the following fuels:

• Henry Hub Natural Gas Spot Price32, Daily, Nominal Dollars per MMBTU (for reference only)

• Algonquin Gate Natural Gas Spot Price33, Daily, Nominal Dollars per MMBTU

• New York Harbor No.2 Fuel Oil34 (Distillate Fuel Oil / DFO), Monthly, Nominal Dollars per Gallon35

• New York Harbor No.6 Fuel Oil36 (Residual Fuel Oil / RFO), Monthly, Nominal Dollars per Barrel37

Figure C-1 provides a summary of the reviewed fuel prices in Nominal $/MMBTU with each vertical gridline representing the first day of the calendar year. TCR assumed that the fuel oil prices reported for each month held constant during that month and that gas prices on days for which there were no reported prices were equal to prices reported for the most recent preceding day.

Fuel Price [$/MMBTU] PriceFuel 10

Algonquin Gate Natural Gas Spot Price Henry Hub Natural Gas Spot Price New York Harbor No.2 Fuel Oil New York Harbor No.6 Fuel Oil

Figure C-1. Graph of historical fuel prices

32 EIA / Thomson Reuters (https://www.eia.gov/dnav/ng/hist/rngwhhdm.htm) 33 S&P Global (https://platform.marketintelligence.spglobal.com/ ) 34 EIA / Thomson Reuters (https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=EER EPD2F PF4 Y35NY DPG&f=M) 35 1 Gallon No.2 = 138.690 BTU, 1 Gallon No.6 = 149,690 BTU (https://www.ct.gov/deep/lib/deep/energy/energyprice/energy conversion factors.pdf) 36 NYMEX / S&P Global (https://platform.marketintelligence.spglobal.com/ ) 37 1 Barrel = 42 Gallons, see footnote 4 for gallons to BTU D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 168 of 210 TCR determined the aggregate number of days in each December, January, February period, i.e. ‘three winter month period”, on which the gas spot price at the Algonquin City Gate (i) exceeded the price of No.2 Fuel Oil (DFO), and (ii) exceeded the price of No.6 Fuel Oil (RFO) respectively.

TCR developed a representative number of ‘days-per-three winter month winter-period’ on which dual- fuel generators would switch from natural gas to their respective secondary fuels based on price by averaging the aggregate number of days in excess of fuel oil prices for the most recent six three winter month periods, i.e. winter of 2012/2013 through winter of 2017/2018. The representative number of ‘days-per-three winter month -period’ for dual-fuel units capable of switching to DFO is fifteen days and for duel-fuel units capable of switching to RFO is thirty-five days.

Figure C-2 provides the results of this analysis.

Calculation 1 Number of Days Gas Price exceeds No.2 Fuel Oil Price (DFO) Year 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Jan 1 7 0 0 0 4 14 7 1 0 11 Feb 0 2 0 0 0 4 12 19 2 0 0 Dec 1 0 0 0 0 6 1 0 1 5

2008 / 2009 / 2010 / 2011 / 2012 / 2013 / 2014 / 2015 / 2016 / 2017 / Winter of 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Days 10 0 0 0 8 32 27 3 1 16

6 yr Average 15 Days

Calculation 2 Number of Days Gas Price exceeds No.6 Fuel Oil Price (RFO) Year 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Jan 7 28 0 4 0 6 18 24 28 1 17 Feb 8 11 0 0 0 13 18 28 9 0 7 Dec 31 0 2 0 0 10 4 3 14 8

2008 / 2009 / 2010 / 2011 / 2012 / 2013 / 2014 / 2015 / 2016 / 2017 / Winter of 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Days 70 060 194656401532

6 yr Average 35 Days

Figure C-2. Number of days in winter period with fuel price exceeding the price of fuel oil TCR determined how it should apply these results in its ENELTYIX modeling by identifying the percentage of ISO-NE gas-fired capacity capable of switching to DFO and to RFO respectively. A review of the ISO-NE CELT 201938 generators list indicates that of the 5.5 GW of gas-fired units that have dual- fuel capability, 98%39 list DFO as their secondary fuel. Based upon those statistics TCR proposes to assume fifteen days of fuel switching during the three winter month periods on average over the study period.

38 https://www iso-ne.com/static-assets/documents/2018/04/2018 celt report xls

39 Combined Cycle and Combustion Turbine (peaker) units represent 5,416 MW of a total 5,511 MW Natural gas based dual-fuel generation capacity listed in CELT. West Springfield 3 is a 95 MW steam turbine unit and is the only generator that lists RFO as a secondary fuel. The impact of RFO switchover was concluded to not be significant to the analysis and ignored. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 169 of 210 C.2: Develop daily gas burn limit Having developed an assumed average number of fuel switching days per three winter month period, TCR developed an assumed “daily gas burn limit” (MMBtu/day) beyond which dual-fuel gas-fired generators would switch to fuel oil. TCR developed the daily gas burn limit from the results of its ENELYTIX modelling of the New England electricity market for the Vineyard Wind 800 GLL case (MA 83C I), as that case most closely represents the generation mix TCR expects for the 83C II Base Case. TCR developed the daily gas burn limit from the results of the Vineyard Wind 800 GLL case in two basic steps. First, TCR started with a draft assumed limit and determined the number of days in each three-winter month period on which the daily gas burn quantity exceeded that draft assumed limit. TCR used those results to revise (calibrate) the draft limit until it determined the burn quantity per day at which the average number of days per three-month period exceeding it over all winter periods in the study period for that case, i.e. 2021/22 through 2041/42, would be fifteen days. The resulting daily gas burn limit assumption is 820,000 MMBTU / day.

Figure C-3 plots the daily gas burn limit and the average daily gas burn quantities by month in each of the three winter month periods from the Vineyard Wind 800 GLL case

1,000,000

900,000

800,000

700,000

600,000

500,000

400,000

300,000 Daily Daily Gas Burn (MMBTU) 200,000

100,000

Winter Period Average daily gas burn in December Average daily gas burn in January

Average daily gas burn in February Daily 'gas burn limit'

Figure C-3. Gas Burn Limit Analysis, Vineyard Wind 800 GLL case Figure C-4 presents the number of days in each three-winter month period on which the projected daily gas burn exceeds the daily gas burn imit. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 170 of 210

40 35 35 33 31 28 30 27

23 25 22 21 20 15 14 15 Number Number Days of 12 12 9 10 6 6 5 4 4 4 5 3 - -

Winter Period No of days above gas burn limit Target number of days (15)

Figure C-4. Days exceeding daily gas burn limit by three-month winter period, Vineyard Wind 800 GLL case

C.3: Impose gas burn limit on all gas fired generators In its ENELYTIX modeling TCR proposes to impose penalty costs on daily gas use in December through January that exceeds the daily gas burn limit established in step (b). TCR will impose these penalty costs in the base case and each proposal case. The penalty cost imposed for exceeding this limit will represent the incremental costs associated with operating on fuel oil. The penalty costs will be as follows: a. Premium on fuel cost: Penalty cost per MMBTU equal to the price difference between the projected prices of DFO in New England and the project prices of natural gas, averaged across all New England natural gas hubs. b. Premium on cost of GHG emissions: Penalty cost per MMBTU equal to the RGGI price in that given year multiplied by the difference in the GHG emission factors for DFO and natural gas

C.4: Develop GHG emission multipliers to adjust additional GHG emission from fuel oil To account for adjustments to reported GHG emission outside the ENELYTIX model, TCR applied a

GHG emission multiplier of 44.3 lbs. CO2/MMBTU for each MMBTU that is reported to be in violation of the constraint set in step (c). This multiplier is calculated as the difference in CO2 emission factors for DFO and natural gas as reported by EIA40.

40 https://www.eia.gov/environment/emissions/co2_vol_mass.php D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 171 of 210 D.2: New York Document

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 172 of 210

Final Report

Base Case for Evaluation of 83C Part II Proposals - Input and Modeling Assumptions New York

Prepared for: Eversource Energy, National Grid, Unitil

Tabors Caramanis Rudkevich January 10, 2020

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 173 of 210

Tabors Caramanis Rudkevich 75 Park Plaza Boston, MA 02166 (617) 871-6900 www.tcr-us.com

DISCLAIMER

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 174 of 210 TABLE OF CONTENTS

Page

Table of Contents ...... 1 List of Figures ...... 2 List of Tables ...... 2 CHAPTER 1: Model Overview and Footprint ...... 3 1.1: Model footprint ...... 3 CHAPTER 2: Transmission Topology ...... 4 CHAPTER 3: System Demand ...... 5 3.1: Load Forecast ...... 5 3.2: Hourly Load Shapes ...... 8 Ancillary Service Requirements ...... 9 CHAPTER 4: Generating Capacity ...... 10 4.1: Scheduled generator additions: ...... 10 4.2: Scheduled retirements: ...... 12 4.3: Capacity balance and generic additions ...... 14 CHAPTER 5: Generating Unit Operating Characteristics ...... 16 5.1: Generator Aggregation ...... 16 5.2: Thermal Unit Characteristics...... 16 5.2.1: Nuclear Unit Operating Characteristics ...... 18 5.3: Hydro Electric Generator Characteristics ...... 18 5.4: Pumped Hydro Storage Facilities ...... 18 5.5: Wind Facilities ...... 19 5.6: Solar Photovoltaics Facilities ...... 19 CHAPTER 6: Fuel Cost ...... 20 6.1: Natural Gas Prices ...... 20 6.2: Fuel Oil Prices ...... 21 6.3: Uranium Prices...... 21 6.4: Coal Prices ...... 22 CHAPTER 7: Emission Rates and Allowances ...... 23 7.1: Emission Programs ...... 23 7.1.1: Regional Greenhouse Gas Initiative ...... 23 7.1.2: Cross State Air Pollution Rule ...... 24 7.2: Emission Rates ...... 25 GLOSSARY ...... 26

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 175 of 210 APPENDIX A: Fuel Price Forecast ...... 30

LIST OF FIGURES

Page

Figure 1. NYISO 2012 historic hourly load...... 8 Figure 2. Capacity Balance for NYISO 2019-2039 ...... 14 Figure 3. Capacity Balance for Zone G-J 2019-2039 ...... 15 Figure 4. Capacity Balance for Zone J 2019-2039 ...... 15 Figure 5. Projection of spot natural gas prices by NYISO pipeline hub (2019$/MMBtu) ...... 20 Figure 6. Projection of fuel oil price (2019$/MMBtu) ...... 21 Figure 7. Projection of RGGI allowance price ($/short Ton) ...... 23 Figure 8. Map of states covered by CSAPR programs ...... 24

LIST OF TABLES

Page

Table 1. Interface limits ...... 4 Table 2. 50/50 annual energy by NYISO zone (GWh) ...... 6 Table 3. Noncoincidental summer peak by NYISO zone (MW) ...... 7 Table 4. New York ISO reserve requirements ...... 9 Table 5. Scheduled Generation Additions and Update ...... 10 Table 6. NYSERDA Generation Additions and Updates ...... 11 Table 7. NYISO Approved Retirements ...... 12 Table 8. Generic Generator Additions ...... 14 Table 9. Normalized incremental heat rate curve ...... 16 Table 10. Other thermal unit operating parameters by unit type ...... 17 Table 11. Photovoltaic parameter assumptions...... 19 Table 12. Coal price ($/MMBtu) ...... 22 Table 13. CSAPR emission allowance prices ...... 24

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 176 of 210 CHAPTER 1: Model Overview and Footprint

This document describes the modeling and input assumptions specific to New York that the TCR team propose for the Base Case against which the Massachusetts electric distribution companies (“EDCs”) will measure the incremental costs and benefits of each Proposal received in response to the 83C RFP part 2 (“83C_II”). TCR refers to this as the “Base Case”.

The complementary document “Base Case Evaluation of 83C_II Proposals – Input and Modeling Assumptions New England” describes all 83C_II Base Case modeling and input assumptions that are common to both New York and New England.

1.1: Model footprint TCR will model the New York Energy and Ancillary Services (E&AS) market to simulate day-ahead and real-time economic transactions between ISO-NE and NYISO. To that end, TCR will use ENELYTIX’s production costing capability to simulate the operation of the two neighboring markets – ISO-NE and NYISO. The New England assumptions document describes the ENELYTIX modeling environment as applied to E&AS markets.

TCR will not model the New York ISO capacity expansion, RPS compliance or capacity market. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 177 of 210 CHAPTER 2: Transmission Topology

ENELYTIX® model organizes physical location of all network resources and loads using bus bar and node mapping. The NYISO transmission topology was modeled based on 2018 FERC 715 powerflow fillings for summer peak 2020. TCR verified the power flow model against the NYISO queue to make sure that essential projects are represented in the power flow case. Generators are mapped to bus bars/electrical nodes (eNodes). Bus bars are mapped to NYISO areas and to specific areas outside NYISO system. The mapping of load nodes to NYISO areas and external zones outside NYISO is used by ENELYTIX® to allocate area load forecasts to individual buses in proportion to bus specific loads in the power flow case.

In determining a representative list of transmission constraints to monitor, TCR included all major NYISO interfaces and critical contingencies. The set of contingencies to monitor and enforce was provided by PowerGEM based on the contingency analysis PowerGEM performed using their TARA tool and complemented by TCR analysis of historically binding constraints. However, to make the Energy and Ancillary Services model run faster, all contingencies exclusively in NY were omitted. TCR developed limits for interfaces based on information provided in NYISO planning studies. Table 1 shows the Interface limits applied.

Table 1. Interface limits Summer Max Constraint Name Summer Min (MW)1 Winter Max (MW) Winter Min (MW) (MW) DYSINGER-EAST 1,740 -9,999 1,740 -9,999 WEST-CENTRAL 400 -9,999 400 -9,999 MOSES-SOUTH 2,350 -9,999 2,350 -9,999 CENTRAL-EAST 2,350 -9,999 2,350 -9,999 TOTAL-EAST 4,850 -9,999 4,850 -9,999 UPNY-CONED 4,950 -9,999 4,950 -9,999 DNWDIE-SOUTH-Pl 5,625 -9,999 5,625 -9,999

1 A limit of -9,999 is a model input representing a case of no constraint. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 178 of 210 CHAPTER 3: System Demand

To simulate hourly operation of NYISO, ENELYTIX® requires hourly demand data of NYISO energy zones. TCR computes hourly forecast for each area by scaling hourly historic load shape to match the forecasted monthly energy and peak forecast for each NYISO area.

The 2019 NYISO Load and Capacity Data report (Gold Book) projects energy and peak forecast to 2039. for the purpose of the 83C_II model, TCR assumes the load in NYISO would remain constant at 2039 level until the end of the study period.

3.1: Load Forecast Table 2 and Table 3 summarize the forecasts of annual energy and peak load by NYISO load zones from 2022 through 2046. These forecasts reflect NYISO projections of energy reductions resulting from statewide energy efficiency programs, modified new building codes and appliance efficiency standards, the impact of retail solar PV, and rising load due to greater penetration of electric vehicles. NYISO labels these as “Baseline” forecasts.

The forecasts of annual energy and peak demand for 2022 through 2039 are from the 2019 Gold Book, the most recent available version. TCR assumes the demand would be constant after 2039. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 179 of 210

Table 2. 50/50 annual energy by NYISO zone (GWh) Year A B C D E F G H I J K NYCA 2022 15,078 9,760 15,747 5,382 7,457 11,629 9,540 2,720 5,803 51,067 19,972 154,155 2023 14,955 9,724 15,649 5,373 7,368 11,540 9,509 2,728 5,807 51,102 19,817 153,572 2024 14,879 9,724 15,602 5,367 7,306 11,489 9,515 2,733 5,823 51,245 19,703 153,386 2025 14,738 9,676 15,485 5,355 7,214 11,390 9,475 2,742 5,824 51,248 19,492 152,639 2026 14,656 9,668 15,428 5,348 7,158 11,341 9,476 2,757 5,834 51,336 19,378 152,380 2027 14,596 9,666 15,385 5,341 7,112 11,304 9,492 2,782 5,852 51,494 19,347 152,371 2028 14,590 9,695 15,394 5,337 7,095 11,312 9,544 2,807 5,881 51,749 19,608 153,012 2029 14,535 9,689 15,348 5,328 7,059 11,278 9,563 2,828 5,902 51,934 19,783 153,247 2030 14,485 9,684 15,306 5,321 7,023 11,246 9,575 2,848 5,911 52,013 20,037 153,449 2031 14,451 9,688 15,275 5,316 6,995 11,227 9,598 2,877 5,927 52,156 20,347 153,857 2032 14,480 9,732 15,312 5,316 7,004 11,267 9,668 2,910 5,970 52,532 20,708 154,899 2033 14,444 9,733 15,281 5,313 6,979 11,255 9,693 2,942 5,987 52,687 20,988 155,302 2034 14,457 9,770 15,298 5,314 6,980 11,286 9,755 2,983 6,027 53,035 21,388 156,293 2035 14,480 9,809 15,325 5,315 6,988 11,324 9,824 3,030 6,074 53,448 21,869 157,486 2036 14,546 9,880 15,400 5,319 7,018 11,399 9,924 3,078 6,141 54,043 22,446 159,194 2037 14,542 9,904 15,399 5,319 7,012 11,423 9,980 3,125 6,182 54,398 22,919 160,203 2038 14,578 9,957 15,443 5,321 7,027 11,480 10,064 3,178 6,239 54,906 23,533 161,726 2039 – 2046 14,622 10,016 15,494 5,325 7,049 11,546 10,153 3,238 6,299 55,435 23,849 163,026

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 180 of 210

Table 3. Noncoincidental summer peak by NYISO zone (MW) Year A B C D E F G H I J K 2024 2,602 1,944 2,714 661 1,246 2,264 2,209 634 1,406 11,598 4,894 2025 2,582 1,940 2,695 658 1,229 2,242 2,206 635 1,408 11,616 4,823 2026 2,565 1,937 2,678 657 1,214 2,225 2,196 636 1,408 11,616 4,758 2027 2,548 1,937 2,666 654 1,203 2,208 2,184 636 1,406 11,598 4,719 2028 2,537 1,937 2,653 654 1,193 2,197 2,174 637 1,405 11,589 4,730 2029 2,530 1,941 2,646 652 1,184 2,191 2,170 639 1,404 11,580 4,815 2030 2,520 1,941 2,633 651 1,177 2,174 2,159 639 1,403 11,572 4,833 2031 2,513 1,942 2,623 651 1,169 2,162 2,151 641 1,404 11,580 4,857 2032 2,510 1,945 2,618 650 1,166 2,154 2,150 645 1,413 11,660 4,876 2033 2,508 1,949 2,614 650 1,164 2,147 2,161 649 1,424 11,749 4,902 2034 2,509 1,955 2,610 650 1,161 2,143 2,163 654 1,437 11,863 4,928 2035 2,512 1,962 2,613 650 1,161 2,142 2,169 661 1,456 12,013 4,966 2036 2,518 1,973 2,615 650 1,165 2,145 2,175 667 1,473 12,155 5,003 2037 2,526 1,981 2,622 652 1,168 2,149 2,182 676 1,492 12,313 5,051 2038 2,536 1,993 2,632 652 1,173 2,157 2,188 684 1,511 12,472 5,096 2039 - 2046 2,549 2,006 2,641 653 1,181 2,168 2,207 691 1,524 12,581 5,152

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 181 of 210

3.2: Hourly Load Shapes TCR develops load forecast based on 2012 load shape to align load shape with NREL’s photovoltaic and wind shape data.

12,000

10,000

8,000

6,000 MW

4,000

2,000

A B C D E F G H I J K

Figure 1. NYISO 2012 historic hourly load D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 182 of 210

Ancillary Service Requirements

Following NYISO’s structure of ancillary services, TCR models three types of reserves: 10 minute spinning (10MSR), 10 minute non-spinning (10MNSR) and 30 minute reserves (30MR). Reserves are cascading, excess higher quality reserves counted toward meeting lower quality reserve requirements. Excess 10MSR counted toward 10MNSR requirements and both excess 10MSR and 10MNSR reserves counted toward 30MR. Spinning reserves are based upon NERC requirements. In addition, NYISO has locational requirements for the reserves on Long Island and near Central East. TCR assumes that hydro can provide regulation and spinning reserves for up to 50% of its available dispatch range. Non- spinning reserves could be provided by GTs and Internal Combustion (IC) units. Nuclear and renewable resources provide no reserves. Table 4 summarizes reserve requirements in NYISO.

Table 4. New York ISO reserve requirements Reserve Type Area Requirement (MW)

10MSR NYISO 665

10MNSR NYISO 665

30MR NYISO 665

10MSR ENY (Zones F-K) 330

10MNSR ENY 870

10MNSR K 120

30MR K 150 Off-peak /420 On-peak

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 183 of 210 CHAPTER 4: Generating Capacity

TCR obtains operating generation assets list from NYISO’s 2019 Load & Capacity Data Report (Gold Book). Based on this list of operating assets, TCR includes scheduled generation additions and retirements from NYISO publications, S&P Global database as well as information on clean energy procurements under contract from NYSERDA to capture the changes in NYISO’s generation mix during 2024-2046 simulation period for this project.

After introducing scheduled capacity additions and retirements, TCR performed a system and local capacity balance to ensure that the NYISO system has enough supply to meet growing demand. TCR added generic fossil fuel generators to localities that saw shortages in capacity.

4.1: Scheduled generator additions: TCR obtained scheduled capacity additions using the NYISO interconnection queue and S&P Global’ s generation asset database. TCR obtains a listing of projects that are currently under construction from both sources and then cross references them to obtain a complete collection of scheduled generation additions and upgrades. Table 5 summarizes TCR’s scheduled generator additions in the model.

Table 5. Scheduled Generation Additions and Update Summer Winter In- Energy Fuel Name Unit Type Capacity Capacity Service Area Type (MW) (MW) Date

Breesport Road Community Solar Farm C PV 2 2 1/1/2019 BOAS #4 Solar Project D PV 2.7 2.7 5/1/2019 Homeridae Solar Project A PV 3.24 3.24 5/1/2019 Hospital Road Solar Project E PV 1.4 1.4 5/1/2019 Pool Brook Road Solar Project E PV 1.98 1.98 5/1/2019 Kelly Bridge Road Community Solar Farm E PV 1.98 1.98 6/1/2019 PASTO10787_11662 C PV 16 16 6/1/2019 Riverhead Solar Farm Project K PV 20 20 6/1/2019 Capital Region Community Solar Garden F PV 5.5 5.5 1/1/2020 Cricket Valley CC4 G CCg100+ 147.5 147.5 1/1/2020 NG Cricket Valley CC5 G CCg100+ 147.5 147.5 1/1/2020 NG Cricket Valley CC6 G CCg100+ 147.5 147.5 1/1/2020 NG Middle Island Solar Farm K PV 19.2 19.2 1/1/2020 Cricket Valley CC1 G CCg100+ 209 209 3/1/2020 NG Cricket Valley CC2 G CCg100+ 209 209 3/1/2020 NG Cricket Valley CC3 G CCg100+ 209 209 3/1/2020 NG Baron Winds Project C Wind 242 242 12/1/2020 Cassadaga Wind Farm A Wind 126 126 12/1/2020 Eight Point Wind Project C Wind 101 101 12/1/2020 Branscomb Solar Project C PV 19.9 19.9 1/1/2021 Astoria Replacement Project CT1 J GTgo50+ 193 193 7/1/2022 NG D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 184 of 210 Summer Winter In- Energy Fuel Name Unit Type Capacity Capacity Service Area Type (MW) (MW) Date

Astoria Replacement Project CT2 J GTgo50+ 193 193 7/1/2022 NG Astoria Replacement Project CT3 J GTgo50+ 193 193 7/1/2022 NG In addition to those generators the Base Case also includes clean energy additions that are procured under contract by NYSERDA which are listed in Table 6.

Table 6. NYSERDA Generation Additions and Updates Summer Winter Energy Unit In-Service Name Capacity Capacity Area Type Date (MW) (MW)

SED Hills Solar E PV 20 20 6/1/2019 Swinging Bridge G Hydro 1.2 1.2 7/1/2019 Darby Solar F PV 20 20 8/1/2019 SED Clay Solar C PV 20 20 8/1/2019 SED Skyline Solar E PV 20 20 8/1/2019 Pattersonville F PV 20 20 11/1/2019 Ball Hill Wind Farm A Wind 100 100 12/1/2019 Columbia Solar 1 F PV 60 60 12/1/2019 ELP Stillwater Solar F PV 20 20 12/1/2019 Rock District Solar F PV 20 20 12/1/2019 Sky High Solar C PV 20 20 12/1/2019 Tayandenega Solar E PV 20 20 12/1/2019 Silver Lake Solar Project B PV 24.9 24.9 1/1/2020 Puckett Solar E PV 20 20 4/1/2020 SED Watkins Road Solar I E PV 20 20 4/1/2020 Grissom Solar F PV 20 20 7/1/2020 SED Dog Corners Solar C PV 20 20 8/1/2020 Janis Solar C PV 20 20 10/1/2020 High River Energy Center F PV 90 90 11/1/2020 Blue Stone Solar G PV 20 20 12/1/2020 Bluestone Wind E Wind 124.2 124.2 12/1/2020 East Point Energy Center F PV 50 50 12/1/2020 Flint Mine Solar G PV 100 100 12/1/2020 Greene County Energy Properties G PV 20 20 12/1/2020 Heritage Wind A Wind 200.1 200.1 12/1/2020 Little Pond Solar G PV 20 20 12/1/2020 Magruder Solar G PV 20 20 12/1/2020 Manchester Solar B PV 20 20 12/1/2020 Number Three Wind Farm E Wind 105.8 105.8 12/1/2020 Roaring Brook Wind E Wind 78 78 12/1/2020 Watkins Glen Solar Energy Center C PV 50 50 12/1/2020 Hecate Energy Greene County 1 G PV 49.99 49.99 1/1/2021 Bakerstand Solar 1 A PV 20 20 10/1/2021 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 185 of 210 Summer Winter Energy Unit In-Service Name Capacity Capacity Area Type Date (MW) (MW)

Morris Ridge Solar C PV 177 177 10/1/2021 High Bridge Wind and Battery E Wind 100.8 100.8 11/1/2021 Lyons Falls Mill Redevelopment E Hydro 2.5 2.5 11/1/2021 Alle-Catt Wind Farm A Wind 339.1 339.1 12/1/2021 Horseshoe Solar A PV 180 180 12/1/2021 Mohawk Solar F PV 98 98 12/1/2021 Hannacroix Solar Facility F PV 4.99 4.99 1/1/2022 Java Solar Energy Center A PV 1.53 1.53 1/1/2022 Daybreak Solar G PV 25 25 11/1/2022 Excelsior Energy Center - Solar + A PV 280 280 11/1/2022 Storage 2 North Light Energy Center - Solar C PV 80 80 11/1/2022 South Fork Wind Farm K Wind 96 96 12/1/2022 Empire Wind Offshore J Wind 816 816 1/1/2024 Sunrise Wind Offshore K Wind 880 880 1/1/2024

4.2: Scheduled retirements: TCR obtained approved NYISO generation retirements from 2019 Gold Book. Table 7 summarizes approved retirement.

Table 7. NYISO Approved Retirements Summer Winter Energy Retirement Name Unit Type Capacity Capacity Fuel Type Area Date (MW) (MW)

Astoria GT 2-1 J ICog50 36.3 45.1 2/1/2023 Oil Astoria GT 2-2 J ICog50 34.8 44.9 2/1/2023 Oil Indian Point 2 H NUC-PWR+ 1016.1 1025.9 4/1/2020 Uranium Indian Point 3 H NUC-PWR+ 1037.9 1039.9 4/1/2021 Uranium James A. FitzPatrick C NUC-BWR1000 845.4 854.5 10/1/2034 Uranium R. E. Ginna B NUC-PWR800 581 581.7 9/1/2029 Uranium Astoria GT 2-3 J ICog50 35.9 46.1 2/1/2023 Oil Astoria GT 2-4 J ICog50 35.8 47.4 2/1/2023 Oil Astoria GT 3-1 J ICog50 34.1 45.2 2/1/2023 Oil Astoria GT 3-2 J ICog50 35.8 44.8 2/1/2023 Oil Astoria GT 3-3 J ICog50 35.3 45.4 2/1/2023 Oil Astoria GT 3-4 J ICog50 36.8 46.2 2/1/2023 Oil Astoria GT 4-1 J ICog50 35.2 45.6 2/1/2023 Oil Astoria GT 4-2 J ICog50 34.7 45.5 2/1/2023 Oil Astoria GT 4-3 J ICog50 34.9 44.9 2/1/2023 Oil Astoria GT 4-4 J ICog50 33.1 44.5 2/1/2023 Oil D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 186 of 210 Summer Winter Energy Retirement Name Unit Type Capacity Capacity Fuel Type Area Date (MW) (MW)

Nine Mile Point 1 C NUC-BWR800 631.9 629 8/1/2029 Uranium Nine Mile Point 2 C NUC-BWR+ 1287.8 1299 10/1/2046 Uranium

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 187 of 210 4.3: Capacity balance and generic additions TCR performs capacity balance to ensure all NYISO locality capacity requirement are met. Projected Installed Capacity Requirement was calculated based on load peak forecast provided in 2019 Gold Book. Generic generator additions, as shown in Table 8, are then added to compensate the capacity shortfall in given locality.

Generic additions are mapped to retired nuclear plant’s electric node to compensate for lost nuclear capacity and minimize disruption to the transmission system.

Table 8. Generic Generator Additions Name Plate Name Energy Area Unit Type Online Date Primary Fuel Capacity (MW) Generic CCGT C CCNgo100+ 533 1/1/2034 NG Generic IC 1 H GTNgo50+ 338 1/1/2034 NG Generic CCGT J CCNgo100+ 533 1/1/2036 NG Generic IC 2 H GTNgo50+ 338 1/1/2036 NG Generic CCGT B CCNgo100+ 533 1/1/2037 NG Generic IC C GTNgo50+ 338 1/1/2038 NG

Figure 2 presents system wide capacity balance of NYISO. Figure 3 and Figure 4 illustrate local capacity balance.

45,000

40,000

35,000

30,000

25,000 MW 20,000

15,000

10,000

5,000

NYISO ICAP Supply TCR NYISO Generic Additions NYISO ICAP Demand

Figure 2. Capacity Balance for NYISO 2019-2039 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 188 of 210 18,000

16,000

14,000

12,000

10,000 MW 8,000

6,000

4,000

2,000

Zone G-J ICAP Supply TCR Zone G-J Generic Additions Zone G-J ICAP Demand

Figure 3. Capacity Balance for Zone G-J 2019-2039 12,000

10,000

8,000

6,000 MW

4,000

2,000

Zone J ICAP Supply TCR Zone J Generic Additions Zone J ICAP Demand

Figure 4. Capacity Balance for Zone J 2019-2039 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 189 of 210 CHAPTER 5: Generating Unit Operating Characteristics

5.1: Generator Aggregation To optimize model computation time, TCR aggregates all units below 20 MWs by type, fuel and energy area into a smaller set of units. Full load heat rates for the aggregates are calculated as the capacity weighted average of the individual units and all other parameters are inherited from the unit type.

5.2: Thermal Unit Characteristics Thermal generation characteristics are generally determined by a generator’s technology and fuel type. These characteristics include heat rate curve shape, non-fuel operation and maintenance costs, startup costs, forced and planned outage rates, minimum up and down times, and quick start, regulation and spinning reserve capabilities.

Each thermal unit type has a distinct normalized incremental heat rate curve. The normalized heat rate curve is scaled by the full load heat rate (FLHR) to produce unit specific heat curve. Table 9 summarizes the shape of normalized heat rate curve used in ENELYTIX.

Table 9. Normalized incremental heat rate curve Unit Type Blocks (Total) Block Capacity Range (% of Max) Heat Rate (% of FLHR) CT 1 1 100% 100% 1 50% 113% 2 51% ~ 67% 75% CC 4 3 68% ~ 83% 86% 4 84% ~ 100% 100% 1 0% ~ 50% 106% 2 51% ~ 65% 90% ST (Coal) 4 3 66% ~ 95% 95% 4 96% ~ 100% 100% 1 25% 118% 2 26% ~ 50% 90% ST (Other) 4 3 51% ~ 80% 95% 4 81% ~ 100% 100%

Source: ENELYTIX® data set

As an example, for a 500 MW CC with a 7,000 Btu/KWh FLHR, the minimum load block would be its minimum generation of 250 MW at a heat rate of 7,910 Btu/KWh, the 2nd incremental block would be 251 MW ~ 335 MW at a heat rate of 5,250 Btu/KWh, the 3rd increment would be 336 MW ~ 415 MW at a heat rate of 6,020 Btu/KWh, and the final block would be 416 MW ~ 500 MW at a heat rate of 7,000 Btu/KWh. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 190 of 210 Table 10 summarizes other operating character assumptions by unit type for thermal generators. The abbreviations in the unit type column are structured as follows: First 2-3 characters identify the technology type, the next 1-2 characters identify the fuel used (gas, oil, coal, biomass, refuse) and the numbers identify the size of generating units mapped to that type.

Table 10. Other thermal unit operating parameters by unit type Min Up Min Down Startup Cost Unit Type EFORd AvgNumFO VOM Time (h) Time (h) Cold ($/MWh) CCg100 (0-100MW) 6 8 4.29 6.29361 2.5 35 CCg100+ (100-9999MW) 6 8 4.29 6.29361 2.5 35 CCgo100 (0-100MW) 6 8 4.29 6.29361 2.5 35 CCgo100+ (100-9999MW) 6 8 4.29 6.29361 2.5 35 GTg20 (0-20MW) 1 1 18.6 7.17047 10 0 GTg50 (20-50MW) 1 1 12.97 5.97854 10 0 GTgo20 (0-20MW) 1 1 18.6 7.17047 10 0 GTgo50 (20-50MW) 1 1 12.97 5.97854 10 0 GTo20 (0-20MW) 1 1 18.6 7.17047 10 0 GTo20 (0-20MW) 1 1 18.6 7.17047 10 0 GTo50 (20-50MW) 1 1 12.97 5.97854 10 0 GTo50+ (50-9999MW) 1 1 9.29 8.83609 10 0 ICb+ (0-500MW) 1 1 11.63 5.36087 10 0 ICg20 (0-20MW) 1 1 21.16 8.15737 10 0 ICg50 (20-50MW) 1 1 11.54 5.31938 10 0 ICg50+ (50-500MW) 1 1 11.54 5.31938 10 0 ICgo20 (0-20MW) 1 1 21.16 8.15737 10 0 ICgo50 (20-50MW) 1 1 11.54 5.31938 10 0 ICgo50 + (50-500MW) 1 1 11.54 5.31938 10 0 ICo20 (0-20MW) 1 1 21.16 8.15737 10 0 ICo50 (20-50MW) 1 1 11.54 5.31938 10 0 ICo50 (20-50MW) 1 1 11.54 5.31938 10 0 ICo50+ (50-500MW) 1 1 11.54 5.31938 10 0 STb+ (0-500MW) 1 1 10.26 6.60348 0 35 STc100 (0-100MW) 24 12 8.32 6.62999 5 45 STc250 (100-250MW) 24 12 6.47 7.56834 4 45 STc600+ (600-9999MW) 24 12 7.05 8.24258 2 45 STg100 (0-100MW) 10 8 10.34 3.04348 6 40 STg200 (100-200MW) 10 8 8.42 6.23223 5 40 STg600 (200-600MW) 10 8 8.35 8.25635 4 40 STgo100 (0-100MW) 10 8 10.34 3.04348 6 40 STgo200 (100-200MW) 10 8 8.42 6.23223 5 40 STgo600 (200-600MW) 10 8 8.35 8.25635 4 40 STo100 (0-100MW) 10 8 10.34 3.39285 6 40 STo200 (100-200MW) 10 8 8.42 8.38989 5 40 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 191 of 210 Min Up Min Down Startup Cost Unit Type EFORd AvgNumFO VOM Time (h) Time (h) Cold ($/MWh) STo600 (200-600MW) 10 8 8.35 5.96487 4 40 STo600+ (600-9999MW) 10 8 14.55 22.7626 3 40 STr+ (0-500MW) 10 8 10.26 6.60348 2 40 NUC-BWR1000MW+ 164 164 2.19 1.26865 0 90 NUC-BWR (800-1000MW) 164 164 1.66 1.61458 0 90 NUC-BWR (400-799MW) 164 164 3.27 2.44982 0 90 NUC-PWR1000MW+ 164 164 4.02 2.29472 0 90 NUC-PWR (800-1000MW) 164 164 3.02 1.03991 0 90 NUC-PWR (400-799MW) 164 164 3.02 2.03373 0 90

Source: ENELYTIX® data set

5.2.1: Nuclear Unit Operating Characteristics Nuclear plants are modeled as special thermal units in ENELYTIX. In general, nuclear facilities are treated as must run units and assumed to run except for periods during generator maintenance and forced outage. Current refueling schedules are obtained from roadtech.com2. Future schedules are estimated per specified periodicity.

5.3: Hydro Electric Generator Characteristics TCR models hydro electric generators as energy constrained generators that output energy in relation to daily pattern of water flow, i.e. the minimum and maximum generating capability and the total energy for each plant. TCR obtains historic hydro generation MWh from EIA and S&P Global database. Based on this historic information, TCR develops daily maximum energy output for each hydro power plant in PJM. Subject to this maximum energy output constraint, TCR allows ENELYTIX® to optimize hourly energy output of each hydro electric generator to minimize system-wide production costs in each hour of the day.

5.4: Pumped Hydro Storage Facilities TCR models pumped storage with the following specifications obtained from the National Hydroelectric Power Resource Study prepared for the U.S. Army Engineer Institute of Water Resources.

• Max Storage: Unit Capacity * Number of Storage hours • Min Storage: 10% of Max Storage • Min MW: Pumping Capacity

• Efficiency: Annual Output/Annual Pumping Energy

2 https://www roadtechs.com/shutdown/shutdown.php?region=n D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 192 of 210 5.5: Wind Facilities Wind generation is represented as hourly generation profile in ENELYTIX®. TCR assembles wind generation profiles from the National Renewable Energy Laboratory (NREL)’s Wind Integration National Dataset (WIND) Toolkit dataset based on 2012 weather data.3 TCR maps each wind power plant to the nearest NREL site based on the plant’s location. For wind plants with known historic capacity factor, TCR further screens for NREL wind sites that have capacity factor within delta of 2% from historical average capacity factor inside a 50-mile radius range from the plant’s location. The resulting normalized NREL site schedule is scaled to the installed capacity of the corresponding wind site and then calendar-shifted for each forecast year making it synchronized with load profiles and interchange schedules.

5.6: Solar Photovoltaics Facilities Like wind facilities, photovoltaic (PV) generators are also represented as hourly generation profiles in ENELYTIX®. TCR obtains solar irradiation data from weather station closest to a PV generator’s location and uses NREL’s PVWatts® Calculator to estimate the site’s energy production. TCR assumes all utility scale PV facilities are fixed array installations with characteristics summarized in Table 11.

Table 11. Photovoltaic parameter assumptions PV Parameter Assumption Elevation (m) 5 Module Type Standard Array Type Fixed (Open Rack) Array Tilt (deg) 20 Array Azimuth (deg) 180 System Losses (%) 14 Invert Efficiency (%) 96

Source: ENELYTIX® data set

3 https://www.nrel.gov/grid/wind-toolkit.html D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 193 of 210 CHAPTER 6: Fuel Cost

6.1: Natural Gas Prices TCR obtained monthly spot gas price forecast for each natural gas market hub serving NYISO and neighboring system using OTC Global Holdings forward curves as of June 10th, 2019. The long-term forecast is the Reference Case forecast assuming no Clean Power Plan (CPP) from the Energy Information Administration (EIA) Annual Energy Outlook 2019 (AEO 2019). TCR uses forward prices in the near-term as they reflect current market conditions. and AEO 2019 forecast for the long-term as it reflects the outlook regarding fundamentals of demand and supply. Similar to the method used for New England, TCR develops the spot gas prices for each of the relevant NYISO hubs based on their basis differentials. The relevant hubs serving NYISO are Niagara, Iroquois Waddington, Iroquois Zone 1, Iroquois Zone 2, Millennium Pipeline, Transco Zone 6 NY.

Figure 5 below summarizes TCR’s natural gas hub price projection during the study period.

1 Annual Average NG Price Annual NG Price Average (2019$/MMBtu) 0

Iroquois Zone 1 Iroquois Zone 2 Niagara Transco Zone 6 NY Millennium Pipeline Iroquois Waddington

Figure 5. Projection of spot natural gas prices by NYISO pipeline hub (2019$/MMBtu)

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 194 of 210 6.2: Fuel Oil Prices TCR obtained annual distillate and residual fuel oil price forecast from EIA’s Annual Energy Outlook 2019 (AEO 2019) reference case projection. TCR uses fuel oil prices projection for electric power sector in MidAtlantic region from AEO 2019’s reference forecast case. TCR converted AEO 2019’s price, which is reported in 2018 real dollar value, to 2019 real dollar value to be consistent with other price data used in the model.

10 Fuel Oil Price Oil Fuel Price (2019$/MMBtu)

Distillate Fuel Oil (FO2) Residual Fuel Oil (FO6)

Figure 6. Projection of fuel oil price (2019$/MMBtu)

Source: EIA Annual Energy Outlook 2019 6.3: Uranium Prices TCR develops uranium prices using the pricing calculator created by the Bulletin of the Atomic Scientist4. The calculator estimates the cost of electricity assuming the nuclear fuel cycle is “Once- Through”. TCR omits all capital related cost associated with the cost of electricity from the calculator. The resulting uranium price is 0.99 Nominal $/MMBtu, which TCR assumed to be fixed.

4 http://thebulletin.org/nuclear-fuel-cycle-cost-calculator/model D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 195 of 210 6.4: Coal Prices TCR develops plant level coal price from S&P Global’s power plant operations data base. TCR derives coal cost in $/MMBtu by dividing S&P Global reported annual cost of coal delivered ($/ton) by annual average heat content of coal burned (Btu/lbs.). Based on this method, TCR calculates the exact coal cost for plants where data is available. For plants without sufficient data, TCR assumes the average cost from other coal plants in the same area and/or state.

Table 12 summarizes coal cost by NYISO unit.

Table 12. Coal price ($/MMBtu) Name Area Price ($/MMBtu)

Cayuga 1 C 2.5

Somerset A 2.5

Source: ENELYTIX® data set

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 196 of 210 CHAPTER 7: Emission Rates and Allowances

The two active emission control programs in the NYISO footprint are the Regional Greenhouse Gas Initiative (RGGI) programs for Carbon dioxide and the Cross-State Air Pollutions Rule (CSAPR) for sulfur dioxide and nitrogen oxides emissions. TCR models both programs in this model.

7.1: Emission Programs

7.1.1: Regional Greenhouse Gas Initiative New York participates in Regional Greenhouse Gas Initiative (RGGI) program. In this NYISO simulation,

TCR uses CO2 allowance price projection that it developed for New England, which is reproduced below in Figure 7.

Figure 7. Projection of RGGI allowance price ($/short Ton)

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 197 of 210 7.1.2: Cross State Air Pollution Rule

The state of New York is covered by Cross State Air Pollution Rule (CSAPR) for both fine particles (SO2 and annual NOx) and ozone (seasonal NOx). Figure 8 shows a map of CSAPR program coverage. In

CSAPR terminology, “Seasonal NOx” emission is the summer season from May 1 to October 31 while

“Annual NOx” emission refers to the rest of the year.

Figure 8. Map of states covered by CSAPR programs

Source: EPA

TCR obtains CSAPR programs’ emission allowance prices from S&P Global’s assessment of CSAPR program. Table 13 summarizes CSAPR prices used in the model which is assumed to be constant over the forecast.

Table 13. CSAPR emission allowance prices Emission Type $ per Allowance Allowance $/Ibs CSAPR NOx Seasonal 625 1 Allowance is 2000Ibs 0.3125 CSAPR NOx Annual 3.5 1 Allowance is 2000Ibs 0.0018 CSAPR SO2 2.75 2.86 Allowances is 2000Ibs 0.0039

Source: ENELYTIX® data set

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 198 of 210 7.2: Emission Rates TCR obtains generator unit level emission rates from three sources: S&P Global’s historic unit emissions data base, S&P Global’s simulated Generator Supply Curve (GSC) data base and EIA’s generic future unit characteristics. For existing thermal units, TCR uses S&P Global’s historic emission rates. For existing units without historic data, TCR uses GSC emissions data. Finally, for existing units without historic and GSC data, and future units not yet operating, TCR uses EIA’s generic rates. D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 199 of 210 GLOSSARY

Term Definition

10MNSR 10 Minute Non-Spinning Reserve

10MSR 10 Minute Spinning Reserve

30MR 30 Minute Reserves

ACP Alternative Compliance Payments

ADR Active Demand Response

AEO Annual Energy Outlook

AESC Avoided Energy Supply Cost

ALG Algonquin

BIO Biomass

BMPV/ BTM PV Behind-the-meter Photovoltaic

CAGR Compound Annual Growth Rate

CC Combined Cycle

CEA Concentric Energy Advisors

CEC Clean Energy Credits

CECP Clean Energy and Climate Plan

CEII Critical Energy Infrastructure Information

CELT Capacity, Energy, Loads, and Transmission

CES Clean Energy Standard

CMR Code of Massachusetts Regulations

COD Commercial Operation/Online Date

CPP Clean Power Plan

CSAPR Cross-State Air Pollutions Rule

CT Combustion Turbine

CT PURA Connecticut Public Utilities Regulatory Authority

DA Day-ahead

DEP Department of Environmental Protection

DERC Discrete Emission Reduction Credits D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 200 of 210 Term Definition

DFO Distillate Fuel Oil

E&AS Energy and Ancillary Services

EDC Electric Distribution Company

EEA Energy and Environmental Affairs

EFORd Effective Forced Outage Rates

EGU Electric Generating Units

EIA Energy Information Administration

EIPC Eastern Interconnection Planning Collaborative

EPA Environmental Protection Agency

FCA Forward Capacity Auction

FCM Forward Capacity Market

FERC Federal Energy Regulatory Commission

FLHR Full Load Heat Rate

FOM Fixed Operation & Maintenance

GHG Greenhouse Gas

Gold Book NYISO’s Load & Capacity Data Report

GSC Generator Supply Curve

GT Gas Turbine

GWSA Global Warming Solutions Act

HD Hydro Power

HVDC High Voltage Direct Current

IC Internal Combustion (reciprocating) Engine

ICAP Installed Capacity

ICR Installed Capacity Requirements

ITC Investment Tax Credit

Kirchhoff’s laws the current law and the voltage law

LDC Load Distribution Company

LMP Locational Marginal Price

LSE Load Serving Entity D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 201 of 210 Term Definition

LSR Local Sourcing Requirement

MA DEP Massachusetts Department of Environmental Protection

MIP Mixed Integer Programming

MLP Municipal Light Plant

MMD Market Model Database

NEL Net Energy Load

NEPOOL GIS New England Power Pool Generation Information System

NERC North American Electric Reliability Corporation

NG Natural Gas

NREL National Renewable Energy Laboratory

PDR Passive Demand Response

PME Power Market Explorer

PNGTS Portland Natural Gas

PPA Power Purchase Agreement

PS Pumped Storage Unit

PSO Power System Optimizer

PTC Production Tax Credit

PV Photovoltaic

PVWatts® NREL’s PV Calculator

RCSA Regulations of Connecticut State Agencies

REC Renewable Energy Certificate, Renewable Energy Credit

RFO Residual Fuel Oil

RFP Requests for Proposal

RGGI Regional Greenhouse Gas Initiative

RMR Reliability Must Run

RPS Renewable Portfolio Standard

RT Real-time

SCED Security Constrained Economic Dispatch

SCUC Security Constrained Unit Commitment D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 202 of 210 Term Definition

SENE Southeast New England

SMART Solar Massachusetts Renewable Target

ST Steam Turbine

SUN Solar Powered

TAO Trading and Agreement Orders

TARA tool Transmission Adequacy & Reliability Assessment tool

TGP Tennessee Gas Pipeline

TMNSR Ten-Minute Non-Spinning Reserve

TMOR Thirty-Minute Operating Reserve

TMSR Ten-Minute Spinning Reserve

VOM Variable Operation & Maintenance

WACC weighted average cost of capital

WAT Water

WIND (NREL) Wind Integration National Dataset

WT Wind Turbine

D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 203 of 210 APPENDIX A: Fuel Price Forecast

A.1: Natural Gas Prices Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 1/2022 5.515 8.111 2.859 7.409 5.256 2.592 2/2022 5.352 7.868 2.827 7.345 5.093 2.468 3/2022 3.701 5.377 2.711 3.491 3.443 2.258 4/2022 2.513 2.759 2.465 2.311 2.256 2.078 5/2022 2.427 2.656 2.380 2.317 2.170 1.981 6/2022 2.552 2.636 2.387 2.241 2.295 1.853 7/2022 2.574 2.757 2.408 2.174 2.318 1.969 8/2022 2.557 2.716 2.382 2.162 2.302 2.026 9/2022 2.439 2.431 2.376 2.028 2.185 1.930 10/2022 2.564 2.558 2.385 2.086 2.310 1.952 11/2022 2.648 3.756 2.353 2.752 2.394 2.157 12/2022 3.562 5.108 2.646 4.360 3.309 2.399 1/2023 5.454 7.859 2.946 7.393 5.202 2.647 2/2023 5.292 7.622 2.909 7.325 5.040 2.522 3/2023 3.722 5.274 2.808 3.575 3.471 2.334 4/2023 2.641 2.875 2.598 2.426 2.390 2.214 5/2023 2.572 2.790 2.529 2.447 2.322 2.135 6/2023 2.706 2.782 2.549 2.386 2.456 2.021 7/2023 2.739 2.910 2.579 2.331 2.489 2.146 8/2023 2.729 2.877 2.561 2.327 2.480 2.209 9/2023 2.616 2.602 2.558 2.199 2.368 2.117 10/2023 2.744 2.732 2.572 2.262 2.496 2.145 11/2023 2.796 3.823 2.541 2.936 2.548 2.378 12/2023 3.682 5.115 2.836 4.516 3.435 2.625 1/2024 5.552 7.781 3.179 7.530 5.305 2.919 2/2024 5.397 7.557 3.145 7.465 5.151 2.797 3/2024 3.893 5.332 3.048 3.803 3.647 2.613 4/2024 2.866 3.089 2.828 2.640 2.621 2.478 5/2024 2.795 3.001 2.756 2.656 2.550 2.394 6/2024 2.917 2.985 2.766 2.588 2.673 2.272 7/2024 2.940 3.102 2.787 2.527 2.696 2.388 8/2024 2.925 3.065 2.764 2.518 2.682 2.445 9/2024 2.815 2.796 2.761 2.393 2.572 2.353 10/2024 2.938 2.921 2.773 2.452 2.696 2.379 11/2024 2.955 3.908 2.738 3.073 2.713 2.603 12/2024 3.804 5.134 3.022 4.578 3.563 2.844 1/2025 5.674 7.743 3.427 7.527 5.433 3.202 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 204 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 2/2025 5.524 7.529 3.392 7.464 5.284 3.080 3/2025 4.107 5.443 3.327 4.000 3.867 2.926 4/2025 3.159 3.371 3.124 2.956 2.919 2.806 5/2025 3.086 3.283 3.051 2.969 2.847 2.719 6/2025 3.207 3.268 3.062 2.903 2.968 2.600 7/2025 3.232 3.384 3.085 2.845 2.994 2.717 8/2025 3.224 3.355 3.069 2.842 2.986 2.780 9/2025 3.117 3.094 3.068 2.720 2.880 2.690 10/2025 3.237 3.215 3.079 2.778 3.000 2.714 11/2025 3.220 4.105 3.037 3.318 2.984 2.928 12/2025 4.043 5.277 3.320 4.760 3.807 3.171 1/2026 5.749 7.669 3.617 7.486 5.513 3.424 2/2026 5.602 7.464 3.581 7.423 5.367 3.302 3/2026 4.236 5.476 3.514 4.112 4.001 3.146 4/2026 3.336 3.538 3.304 3.155 3.102 3.015 5/2026 3.260 3.447 3.228 3.163 3.026 2.925 6/2026 3.378 3.433 3.240 3.098 3.145 2.806 7/2026 3.404 3.548 3.263 3.041 3.171 2.923 8/2026 3.397 3.520 3.248 3.040 3.165 2.986 9/2026 3.297 3.269 3.251 2.923 3.065 2.901 10/2026 3.422 3.395 3.270 2.988 3.191 2.933 11/2026 3.381 4.203 3.229 3.460 3.150 3.144 12/2026 4.178 5.325 3.510 4.844 3.948 3.389 1/2027 5.774 7.558 3.751 7.403 5.544 3.587 2/2027 5.634 7.363 3.717 7.345 5.405 3.467 3/2027 4.316 5.468 3.650 4.178 4.087 3.311 4/2027 3.475 3.668 3.447 3.314 3.246 3.184 5/2027 3.404 3.583 3.376 3.326 3.176 3.098 6/2027 3.522 3.571 3.388 3.262 3.294 2.981 7/2027 3.548 3.684 3.413 3.207 3.320 3.098 8/2027 3.544 3.659 3.401 3.209 3.317 3.164 9/2027 3.447 3.415 3.404 3.095 3.220 3.081 10/2027 3.567 3.536 3.420 3.156 3.341 3.110 11/2027 3.495 4.258 3.371 3.557 3.269 3.308 12/2027 4.261 5.326 3.643 4.879 4.035 3.547 1/2028 5.752 7.408 3.830 7.281 5.527 3.693 2/2028 5.614 7.219 3.794 7.222 5.389 3.572 3/2028 4.343 5.413 3.727 4.192 4.119 3.416 4/2028 3.539 3.724 3.514 3.396 3.315 3.276 5/2028 3.463 3.634 3.438 3.401 3.240 3.183 6/2028 3.580 3.624 3.452 3.341 3.357 3.070 7/2028 3.614 3.743 3.484 3.295 3.392 3.194 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 205 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 8/2028 3.631 3.740 3.493 3.316 3.409 3.280 9/2028 3.545 3.510 3.505 3.213 3.323 3.206 10/2028 3.680 3.645 3.538 3.290 3.458 3.252 11/2028 3.581 4.290 3.484 3.628 3.360 3.441 12/2028 4.318 5.307 3.747 4.892 4.098 3.674 1/2029 5.765 7.417 3.848 7.291 5.541 3.711 2/2029 5.627 7.229 3.811 7.231 5.403 3.590 3/2029 4.359 5.426 3.745 4.209 4.136 3.434 4/2029 3.555 3.739 3.530 3.413 3.332 3.292 5/2029 3.479 3.649 3.454 3.417 3.256 3.200 6/2029 3.596 3.640 3.468 3.358 3.374 3.087 7/2029 3.630 3.759 3.501 3.312 3.408 3.212 8/2029 3.647 3.756 3.510 3.334 3.426 3.297 9/2029 3.562 3.527 3.522 3.230 3.340 3.223 10/2029 3.697 3.662 3.555 3.308 3.476 3.270 11/2029 3.599 4.306 3.502 3.645 3.379 3.459 12/2029 4.335 5.322 3.765 4.908 4.115 3.692 1/2030 5.799 7.447 3.886 7.321 5.575 3.750 2/2030 5.661 7.259 3.849 7.261 5.438 3.628 3/2030 4.395 5.460 3.782 4.245 4.172 3.472 4/2030 3.590 3.773 3.565 3.447 3.367 3.327 5/2030 3.513 3.683 3.488 3.452 3.291 3.235 6/2030 3.631 3.674 3.503 3.393 3.409 3.123 7/2030 3.666 3.794 3.536 3.347 3.444 3.248 8/2030 3.683 3.791 3.546 3.370 3.462 3.334 9/2030 3.598 3.563 3.559 3.267 3.377 3.260 10/2030 3.733 3.699 3.592 3.345 3.513 3.307 11/2030 3.637 4.343 3.540 3.683 3.417 3.497 12/2030 4.374 5.359 3.805 4.946 4.155 3.732 1/2031 5.780 7.426 3.870 7.299 5.556 3.734 2/2031 5.642 7.238 3.833 7.240 5.419 3.613 3/2031 4.379 5.442 3.766 4.229 4.156 3.457 4/2031 3.575 3.758 3.550 3.433 3.353 3.313 5/2031 3.499 3.669 3.474 3.437 3.277 3.221 6/2031 3.617 3.660 3.489 3.379 3.395 3.109 7/2031 3.651 3.779 3.522 3.333 3.430 3.234 8/2031 3.669 3.777 3.532 3.356 3.448 3.319 9/2031 3.583 3.549 3.544 3.253 3.363 3.246 10/2031 3.718 3.684 3.578 3.331 3.498 3.293 11/2031 3.622 4.327 3.525 3.668 3.402 3.482 12/2031 4.358 5.342 3.789 4.929 4.139 3.717 1/2032 5.922 7.566 4.015 7.439 5.699 3.879 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 206 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 2/2032 5.783 7.376 3.977 7.379 5.560 3.756 3/2032 4.518 5.580 3.907 4.368 4.296 3.598 4/2032 3.705 3.888 3.680 3.563 3.483 3.443 5/2032 3.628 3.797 3.603 3.566 3.406 3.350 6/2032 3.746 3.789 3.619 3.508 3.525 3.239 7/2032 3.782 3.910 3.653 3.465 3.561 3.365 8/2032 3.801 3.909 3.664 3.488 3.580 3.452 9/2032 3.716 3.681 3.677 3.386 3.496 3.379 10/2032 3.852 3.818 3.712 3.466 3.633 3.427 11/2032 3.758 4.462 3.662 3.805 3.539 3.619 12/2032 4.499 5.482 3.932 5.069 4.281 3.859 1/2033 5.983 7.624 4.079 7.498 5.760 3.944 2/2033 5.843 7.434 4.040 7.436 5.621 3.820 3/2033 4.579 5.639 3.969 4.430 4.357 3.661 4/2033 3.762 3.945 3.737 3.620 3.540 3.501 5/2033 3.685 3.854 3.659 3.623 3.463 3.407 6/2033 3.803 3.846 3.676 3.566 3.582 3.297 7/2033 3.840 3.967 3.711 3.523 3.619 3.423 8/2033 3.859 3.967 3.722 3.547 3.639 3.511 9/2033 3.774 3.740 3.735 3.445 3.555 3.438 10/2033 3.911 3.877 3.771 3.525 3.692 3.487 11/2033 3.819 4.521 3.722 3.865 3.600 3.680 12/2033 4.561 5.542 3.995 5.130 4.343 3.922 1/2034 6.026 7.664 4.126 7.538 5.804 3.990 2/2034 5.886 7.474 4.086 7.476 5.664 3.867 3/2034 4.623 5.681 4.013 4.474 4.401 3.706 4/2034 3.803 3.986 3.779 3.662 3.582 3.543 5/2034 3.726 3.894 3.701 3.664 3.505 3.449 6/2034 3.844 3.888 3.717 3.608 3.624 3.339 7/2034 3.881 4.009 3.753 3.565 3.661 3.466 8/2034 3.901 4.009 3.765 3.590 3.681 3.554 9/2034 3.817 3.782 3.778 3.488 3.597 3.481 10/2034 3.954 3.920 3.814 3.569 3.735 3.531 11/2034 3.863 4.564 3.766 3.909 3.644 3.724 12/2034 4.606 5.584 4.040 5.174 4.388 3.968 1/2035 6.068 7.703 4.171 7.578 5.846 4.036 2/2035 5.928 7.512 4.131 7.515 5.706 3.912 3/2035 4.666 5.722 4.058 4.517 4.445 3.751 4/2035 3.844 4.026 3.819 3.703 3.623 3.584 5/2035 3.766 3.934 3.741 3.705 3.545 3.490 6/2035 3.885 3.928 3.758 3.648 3.665 3.381 7/2035 3.922 4.049 3.794 3.607 3.702 3.508 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 207 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 8/2035 3.942 4.050 3.806 3.632 3.723 3.596 9/2035 3.858 3.824 3.819 3.530 3.639 3.523 10/2035 3.995 3.962 3.856 3.611 3.777 3.573 11/2035 3.905 4.605 3.809 3.951 3.687 3.766 12/2035 4.649 5.626 4.085 5.216 4.431 4.012 1/2036 6.148 7.780 4.255 7.654 5.927 4.121 2/2036 6.007 7.588 4.214 7.590 5.786 3.995 3/2036 4.745 5.799 4.139 4.597 4.525 3.832 4/2036 3.919 4.100 3.894 3.778 3.698 3.659 5/2036 3.840 4.008 3.815 3.779 3.620 3.564 6/2036 3.959 4.002 3.833 3.723 3.740 3.456 7/2036 3.997 4.124 3.869 3.683 3.778 3.584 8/2036 4.018 4.125 3.882 3.708 3.799 3.672 9/2036 3.934 3.900 3.896 3.607 3.716 3.600 10/2036 4.072 4.038 3.933 3.689 3.854 3.651 11/2036 3.984 4.682 3.888 4.030 3.766 3.845 12/2036 4.730 5.704 4.167 5.295 4.512 4.095 1/2037 6.166 7.793 4.277 7.668 5.945 4.143 2/2037 6.024 7.602 4.235 7.604 5.803 4.017 3/2037 4.765 5.816 4.160 4.617 4.545 3.854 4/2037 3.938 4.119 3.913 3.798 3.718 3.679 5/2037 3.859 4.027 3.834 3.798 3.640 3.584 6/2037 3.978 4.021 3.852 3.743 3.759 3.477 7/2037 4.017 4.143 3.889 3.703 3.798 3.604 8/2037 4.038 4.145 3.902 3.729 3.820 3.693 9/2037 3.954 3.920 3.916 3.628 3.736 3.621 10/2037 4.092 4.058 3.953 3.710 3.875 3.672 11/2037 4.004 4.701 3.909 4.050 3.787 3.866 12/2037 4.750 5.722 4.188 5.314 4.533 4.116 1/2038 6.172 7.796 4.288 7.671 5.952 4.154 2/2038 6.031 7.605 4.246 7.607 5.811 4.029 3/2038 4.774 5.823 4.170 4.626 4.555 3.865 4/2038 3.947 4.128 3.923 3.807 3.728 3.689 5/2038 3.869 4.036 3.844 3.808 3.650 3.595 6/2038 3.988 4.031 3.862 3.753 3.769 3.487 7/2038 4.026 4.152 3.899 3.713 3.808 3.615 8/2038 4.048 4.154 3.912 3.739 3.830 3.703 9/2038 3.964 3.930 3.926 3.639 3.747 3.632 10/2038 4.102 4.068 3.963 3.720 3.885 3.683 11/2038 4.015 4.710 3.919 4.061 3.798 3.877 12/2038 4.759 5.729 4.199 5.322 4.543 4.127 1/2039 6.192 7.812 4.312 7.687 5.972 4.178 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 208 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 2/2039 6.050 7.620 4.270 7.623 5.831 4.053 3/2039 4.796 5.842 4.193 4.648 4.577 3.889 4/2039 3.969 4.149 3.944 3.829 3.750 3.711 5/2039 3.890 4.057 3.865 3.829 3.671 3.616 6/2039 4.009 4.052 3.883 3.775 3.791 3.509 7/2039 4.047 4.173 3.920 3.735 3.830 3.637 8/2039 4.069 4.175 3.934 3.761 3.852 3.726 9/2039 3.986 3.952 3.948 3.661 3.769 3.654 10/2039 4.124 4.090 3.985 3.743 3.907 3.705 11/2039 4.037 4.730 3.942 4.083 3.821 3.900 12/2039 4.782 5.749 4.222 5.343 4.566 4.151 1/2040 6.252 7.868 4.377 7.744 6.033 4.244 2/2040 6.110 7.676 4.334 7.679 5.891 4.118 3/2040 4.857 5.901 4.256 4.710 4.638 3.953 4/2040 4.026 4.206 4.002 3.887 3.808 3.769 5/2040 3.947 4.114 3.922 3.887 3.729 3.674 6/2040 4.066 4.109 3.941 3.833 3.849 3.568 7/2040 4.106 4.231 3.979 3.794 3.888 3.696 8/2040 4.128 4.234 3.993 3.821 3.911 3.785 9/2040 4.045 4.011 4.007 3.721 3.829 3.714 10/2040 4.183 4.150 4.045 3.803 3.967 3.766 11/2040 4.098 4.789 4.003 4.144 3.883 3.961 12/2040 4.844 5.808 4.286 5.403 4.628 4.215 1/2041 6.235 7.847 4.365 7.723 6.016 4.231 2/2041 6.093 7.655 4.322 7.657 5.874 4.106 3/2041 4.843 5.884 4.244 4.696 4.625 3.941 4/2041 4.015 4.194 3.990 3.876 3.797 3.758 5/2041 3.936 4.102 3.911 3.875 3.718 3.663 6/2041 4.054 4.097 3.930 3.822 3.838 3.558 7/2041 4.093 4.219 3.967 3.783 3.877 3.685 8/2041 4.116 4.221 3.981 3.809 3.899 3.774 9/2041 4.033 3.999 3.995 3.710 3.817 3.703 10/2041 4.171 4.137 4.033 3.792 3.955 3.754 11/2041 4.086 4.775 3.991 4.131 3.871 3.949 12/2041 4.829 5.791 4.273 5.387 4.614 4.202 1/2042 6.275 7.883 4.410 7.759 6.057 4.277 2/2042 6.133 7.691 4.367 7.693 5.915 4.151 3/2042 4.886 5.924 4.288 4.739 4.668 3.986 4/2042 4.055 4.234 4.031 3.917 3.838 3.800 5/2042 3.976 4.142 3.951 3.916 3.759 3.705 6/2042 4.095 4.137 3.970 3.862 3.878 3.599 7/2042 4.134 4.259 4.008 3.824 3.918 3.727 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 209 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 8/2042 4.157 4.262 4.023 3.851 3.941 3.816 9/2042 4.074 4.040 4.036 3.752 3.859 3.745 10/2042 4.212 4.179 4.075 3.835 3.998 3.797 11/2042 4.129 4.816 4.034 4.174 3.914 3.992 12/2042 4.872 5.831 4.318 5.429 4.658 4.247 1/2043 6.337 7.940 4.477 7.817 6.119 4.345 2/2043 6.194 7.747 4.433 7.749 5.977 4.218 3/2043 4.948 5.983 4.352 4.802 4.732 4.051 4/2043 4.114 4.293 4.090 3.976 3.898 3.860 5/2043 4.035 4.200 4.010 3.975 3.819 3.764 6/2043 4.154 4.196 4.030 3.922 3.938 3.660 7/2043 4.194 4.318 4.068 3.885 3.979 3.788 8/2043 4.217 4.322 4.083 3.913 4.002 3.877 9/2043 4.135 4.101 4.097 3.814 3.920 3.807 10/2043 4.273 4.240 4.136 3.897 4.059 3.859 11/2043 4.191 4.876 4.097 4.236 3.977 4.055 12/2043 4.935 5.891 4.382 5.490 4.722 4.312 1/2044 6.418 8.015 4.564 7.893 6.201 4.432 2/2044 6.274 7.822 4.518 7.825 6.057 4.304 3/2044 5.030 6.062 4.436 4.885 4.814 4.136 4/2044 4.192 4.369 4.167 4.054 3.976 3.938 5/2044 4.111 4.276 4.087 4.052 3.896 3.842 6/2044 4.231 4.273 4.107 4.000 4.016 3.738 7/2044 4.272 4.396 4.146 3.964 4.057 3.867 8/2044 4.295 4.400 4.162 3.992 4.081 3.957 9/2044 4.214 4.180 4.176 3.894 4.000 3.887 10/2044 4.353 4.320 4.216 3.977 4.139 3.940 11/2044 4.272 4.955 4.178 4.317 4.059 4.137 12/2044 5.018 5.972 4.467 5.571 4.806 4.397 1/2045 6.491 8.084 4.644 7.961 6.275 4.512 2/2045 6.347 7.890 4.597 7.892 6.131 4.384 3/2045 5.105 6.133 4.513 4.960 4.890 4.214 4/2045 4.262 4.440 4.238 4.125 4.047 4.009 5/2045 4.182 4.346 4.157 4.122 3.967 3.913 6/2045 4.301 4.343 4.178 4.071 4.087 3.810 7/2045 4.343 4.466 4.218 4.036 4.129 3.939 8/2045 4.367 4.472 4.235 4.065 4.154 4.030 9/2045 4.286 4.252 4.248 3.967 4.073 3.960 10/2045 4.425 4.392 4.289 4.051 4.213 4.014 11/2045 4.347 5.027 4.253 4.391 4.135 4.212 12/2045 5.094 6.044 4.545 5.645 4.882 4.475 1/2046 6.540 8.127 4.699 8.005 6.325 4.568 D.P.U. 20-16/20-17/20-18 Exhibit JU-4 Page 210 of 210 Month Iroquois Iroquois Niagara Transco Zone Iroquois Millennium Zone 1 Zone 2 6 NY Waddington Pipeline 2/2046 6.395 7.933 4.652 7.935 6.180 4.439 3/2046 5.157 6.181 4.566 5.012 4.942 4.269 4/2046 4.312 4.488 4.287 4.175 4.097 4.059 5/2046 4.231 4.394 4.206 4.171 4.017 3.963 6/2046 4.350 4.392 4.227 4.121 4.137 3.861 7/2046 4.392 4.515 4.268 4.086 4.179 3.990 8/2046 4.417 4.521 4.285 4.116 4.205 4.081 9/2046 4.336 4.303 4.299 4.018 4.124 4.012 10/2046 4.476 4.443 4.340 4.103 4.264 4.066 11/2046 4.399 5.077 4.306 4.443 4.187 4.264 12/2046 5.146 6.093 4.599 5.695 4.935 4.529