Massachusetts Building Sector Model and Policy Analysis

Client: Executive Office of Energy and Environmental Affairs

Author: Elizabeth A Stanton, PhD, Sagal Alisalad, Joshua R. Castigliego, Bryndis Woods, PhD, Tanya Stasio, PhD, Jordan Burt, PhD, and Elisabeth Seliga

August 2026

On behalf of the Massachusetts Executive Office of Energy and Environmental Affairs (MA EEA), AEC staff collaborated with Introba and Massachusetts Institute of Technology to develop the Massachusetts Building Energy Scenario Tool (MassBEST), a flexible modeling platform that integrates building-level energy modeling, adoption and propensity modeling, policy representation, and electric grid impact analysis to support the Commonwealth’s decarbonization decision-making. In this project, AEC designed a heuristic model of commercial clean technology adoption and addressed equity in the MassBEST model in response to the input of Massachusetts agency staff.

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Comments on Ameren Missouri LLC Integrated Resource Plan Initial Assumptions

Client: Sierra Club

Authors: Bryndis Woods, PhD and Joshua R. Castigliego

July 2026

AEC assisted Sierra Club with its submission of Comments on Ameren Missouri, LLC’s 2026 Integrated Resource Plan Initial Assumptions. Sierra Club’s comments addressed recommendations for Ameren in its forthcoming IRP, including issues related to the Company’s assumptions regarding: energy efficiency, large load customers, coal plant retirements, tax credit eligibility for wind and solar resources, carbon price forecasts, costs of new gas resources, gas price forecasts, and carbon capture and storage costs.

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Kentucky Ratepayers Absorb Losses at Coal-Fired Power Plants in PJM

Client: Kentucky Resources Council (KRC)

Authors: Bryndis Woods, PhD, Joshua R. Castigliego, and Tyler Comings

July 2026

This Applied Economics Clinic (AEC) report assesses the energy market losses of three Kentucky-owned coal-fired generating units operating in the PJM wholesale energy market: East Bend Generating Station Unit 2 and Mitchell Power Plant Units 1 and 2. In PJM, electric generators are selected in least cost-rank order when they bid into the market (that is, PJM dispatches generators from least expensive to most expensive each hour of the day). However, owners of generator units can decide to run their units uneconomically without subjecting them to the grid operator’s least cost-rank order decision-making—a practice known as “self-commitment” or “must-run”—which passes the costs of running uneconomic units on to ratepayers.

Over a two-year period spanning November 1, 2022 to October 31, 2024, AEC finds that the East Bend and Mitchell coal-fired units fared poorly in the energy market: the units collectively lost nearly $63 million on net, with each unit costing Kentucky ratepayers between $20 and $21 million. All three units had negative net revenues about 80 percent of the time over the two-year period, and when you sum across months with net negative revenues, total losses are about $90 million. Much of these losses can be attributed to the units’ owners (Duke Energy Kentucky and Kentucky Power Company) forcing these units to run uneconomically.

Link to Report

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Comments on Rhode Island's Draft Least Cost Procurement Standards

Client: Conservation Law Foundation (CLF)

Authors: Elizabeth A. Stanton, PhD and Joshua R. Castigliego

June 2026

On behalf of Conservation Law Foundation, Principal Economist Dr. Elizabeth A. Stanton and Senior Researcher Joshua R. Castigliego provided expert comments in Docket No. 26-15-EE on the proposed amendments to the Rhode Island Public Utilities Commission's Least Cost Procurement (LCP) Standards. In their comments, Dr. Stanton and Mr. Castigliego discuss several issues pertaining to the proposed amendments, including: (i) concerns regarding changes to the definitions of Cost of Supply and Cost of Energy Efficiency or Conservation; (ii) provisions related to the Demand Side Management Investment Proposal; and (iii) additional issues raised by other stakeholders in their comments on the proposed amendments. Dr. Stanton and Mr. Castigliego recommend revisions to ensure consistency with the Rhode Island Benefit Cost Test (RI Test) framework, improve clarity and comprehensiveness of the LCP Standards, and strengthen the evaluation of demand-side management investments and their associated costs and benefits.

Link to Comments

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Sierra Club Comments on the Commission's Draft Integrated Resource Planning Rule in Missouri

Client: Sierra Club

Authors: Liz Stanton, PhD and Joshua R. Castigliego

June 2026

AEC assisted Sierra Club with its submission of Comments on the Missouri Public Service Commission’s draft Integrated Resource Planning (IRP) Rule in File No. EW-2026-0091. Sierra Club’s comments propose revisions to strengthen the IRP process by increasing transparency, clarifying regulatory requirements, enhancing stakeholder participation and access to information, and promoting more robust, data-driven utility planning.

Link to Comments

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Risks of New Gas-Fired Plants in Southeastern States

Client: Southern Environmental Law Center (SELC)

Authors: Tanya Stasio, PhD, Joshua R. Castigliego, and Elisabeth Seliga

June 2026

Across the Southeastern United States, rising electric demand and ongoing reliability challenges are prompting utilities to propose new gas-fired resources to help meet future system needs. At the same time, regulators are looking for solutions to provide greater energy affordability in the face of high electricity and fuel costs. Major investments in gas-fired power plants, pipelines, and related facilities put customers at risk for increasing electric rates and energy bills. This Applied Economics Clinic (AEC) report, prepared on behalf of Southern Environmental Law Center (SELC), identifies eight risks to electric utility customers that could cause higher energy rates and bills:

1. Growing cost of gas-fired power plants

2. Supply chain constraints

3. Volatile and uncertain gas fuel prices

4. Lack of resource diversity

5. Dependence on out-of-state gas supply

6. Stranded assets due to uncertain forecasts

7. Stranded assets due to more stringent climate policy

8. Stranded assets from existing or more stringent environmental regulations

To ensure that customers’ electric bills remain affordable, while also considering how states will adapt to the region’s anticipated growth in electric demand, policymakers, regulators, and utilities must assess whether pursuing additional gas-fired resources would expose ratepayers to unnecessary risk.

Link to Report

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Low-to-Moderate Income Emissions Reductions in Massachusetts: A Marginal Cost of Abatement Analysis

Client: Green Energy Consumers Alliance (GECA)

Authors: Sagal Alisalad, Joshua R. Castigliego, Liz Stanton, PhD

May 2026

On behalf of Green Energy Consumers Alliance (GECA), Researcher Sagal Alisalad, Senior Researcher Joshua R. Castigliego, and Principal Economist Liz Stanton, PhD, prepared a report analyzing the costs of low-to-moderate income (LMI) emissions reductions measures in Massachusetts. AEC staff assessed LMI-specific emissions reduction measures that could be implemented in Massachusetts by 2030 and developed a marginal abatement cost curve showing eight measures from lowest to highest cost. AEC’s analysis found that the eight measures would reduce emissions by 0.2 million metric tons (MMT) in 2030, about 7 percent of the 2.9 MMT needed to meet the Commonwealth’s 2030 climate targets, and that the eight measures total 2.8 MMT of lifetime CO2e reductions and have a net societal benefit, or cost savings, of $7.3 billion.

Link to Report

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Electrification with Equity, Part 1: The Opportunity for Behind-the-Meter Solar and Storage in Massachusetts

Clients: Clean Energy Group and Vote Solar

Authors: Tanya Stasio, PhD, Elizabeth A. Stanton, PhD and Joshua R. Castigliego

May 2026

Massachusetts electric demand is expected to increase substantially by 2050, creating the need for additional electric generating capacity. Behind-the-meter (BTM) solar and solar paired with storage resources provide an opportunity for meeting this demand while reducing energy bills for customers, increasing renewable energy integration, and improving grid resiliency. On behalf of the Clean Energy Group and Vote Solar, AEC Senior Researcher Tanya Stasio, PhD, Principal Economist Elizabeth A. Stanton, PhD, and Senior Researcher Joshua R. Castigliego prepared a report that estimates the technical potential for BTM solar and solar paired with storage and the opportunity for these distributed energy resources to reduce expected increases in Massachusetts’ peak electric demand.

Link to Report

Link to Electrification with Equity, Part 2 Report

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Savings from Coal to Gas Conversion: Florida’s Northside 1 and 2

Client: Sierra Club

Author: Liz Stanton, PhD, Joshua R. Castigliego, Jordan Burt, PhD, and Bryndis Woods, PhD

April 2026

AEC-2026-04-WP-01

On behalf of Sierra Club, Principal Economist Elizabeth A. Stanton, PhD, Senior Researcher Joshua R. Castigliego, Researcher Jordan Burt, PhD, and Principal Analyst Bryndis Woods, PhD, prepared a white paper that investigates the potential cost savings associated with transitioning JEA’s Northside Generation Station to retire its coal-fired operations and run exclusively on natural gas. Using a simple model of annual expenses and revenues at the unit for the period 2026 to 2035, AEC compared net costs under a “business-as-usual” scenario in which the operations of recent historical years continue into the future with a “gas conversion” scenario in which full-time gas operations commence in 2030. Over the 10-year modeling period, elimination of all coal operations at Northside Units 1 and 2 result in a total savings of $122.8 million, or $51.9 million at Northside Unit 1 and $70.9 million at Unit 2. Northside Unit 1’s levelized costs fall by $11.4 per MWh and Unit 2’s by $8.5 per MWh.

A cost savings opportunity of this magnitude—approximately 12 percent reduction from current Northside 1 and 2 costs—deserves careful and transparent examination. Utility decisions regarding capital investments, maintaining aging infrastructure, and day-to-day operations must consider affordability and keep an open mind to new options for lowering costs. To achieve a successful conversion at Northside Units 1 and 2, AEC recommends that JEA conduct and publicly share a comparative analysis of its future operations (including all fixed, variable, and capital costs and financing) under current mixed fuel operations and under all gas operations. All assumptions, data, and methodologies should be fully transparent and made publicly available, and JEA’s analysis should also assess the conversion’s impact on rates and customer bills.

Link to White Paper

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Savings from Coal to Gas Conversion: Florida’s Deerhaven 2

Client: Sierra Club

Author: Liz Stanton, PhD, Joshua R. Castigliego, Jordan Burt, PhD, and Bryndis Woods, PhD

April 2026

AEC-2026-04-WP-02

On behalf of Sierra Club, Principal Economist Elizabeth A. Stanton, PhD, Senior Researcher Joshua R. Castigliego, Researcher Jordan Burt, PhD, and Principal Analyst Bryndis Woods, PhD, prepared a white paper that investigates the potential cost savings associated with transitioning Gainesville Regional Utilities’ (GRU) Deerhaven Generation Station to retire its coal-fired operations and run exclusively on natural gas. Using a simple model of annual expenses and revenues at the unit for the period 2026 to 2035, AEC compared net costs under a “business-as-usual” scenario in which the operations of recent historical years continue into the future with a “gas conversion” scenario in which full-time gas operations commence in 2030. Over the 10-year modeling period, elimination of all coal operations at Deerhaven Unit 2 results in a total savings $31.3 million (or a reduction in levelized costs of $7.4 per MWh).

A cost savings opportunity of this magnitude—approximately a 7 percent reduction from current Deerhaven Unit 2 costs—deserves careful and transparent examination. Utility decisions regarding capital investments, maintaining aging infrastructure, and day-to-day operations must consider affordability and keep an open mind to new options for lowering costs. To achieve a successful conversion at Deerhaven Unit 2, AEC recommends that GRU conduct and publicly share a comparative analysis of its future operations (including all fixed, variable, and capital costs and financing) under current mixed fuel operations and under all gas operations. All assumptions, data, and methodologies should be fully transparent and made publicly available, and GRU’s analysis should also assess the conversion’s impact on rates and customer bills.

Link to White Paper

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Rhode Island Heat Pump Rate “RI Test” Report

Client: Conservation Law Foundation and Environmental Defense

Author: Elizabeth A. Stanton, PhD, Joshua R. Castigliego, and Jordan Burt, PhD

April 2026

On behalf of Conservation Law Foundation and Environmental Defense, Principal Economist Elizabeth A. Stanton, PhD, Senior Researcher Joshua R. Castigliego, and Researcher Jordan Burt, PhD, prepared a report assessing the results of a “Rhode Island Benefit Cost Test” (RI Test) cost-benefit analysis comparing the monetized costs and benefits of a new heat pump electric rate proposed in Rhode Island Public Utility Commission Docket No. 25-45-GE.

AEC found that the net impact of a heat pump rate is a system-wide cost savings of $11.9 million, or benefit to cost ratio of 1.3. The proposed residential heat pump rate shows greater benefits than costs under the RI Test methodology.

Link to Report

Testimony on the Proposed Rhode Island Residential Heat Pump Rate

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Background Report: Evaluation of Connecticut Medical Protections

Client: Connecticut Public Utilities Regulatory Authority

Authors: Tanya Stasio, PhD, Sagal Alisalad, Elizabeth A. Stanton, PhD, Jordan Burt, PhD, Joshua R. Castigliego, and Bryndis Woods, PhD 

March 2026

On behalf of Connecticut Public Utilities Regulatory Authority, Senior Researcher Tanya Stasio, PhD, Researcher Sagal Alisalad, Principal Economist Liz Stanton, PhD, and AEC staff prepared a background report that evaluates Connecticut's electric and gas utility shutoff policies for medically protected customers. Most of Connecticut's medically protected customers have year-round shutoff protection and, as a result, maintain average arrearages that are thousands of dollars more than customers without medical protections. While limiting shutoff protections may increase utility revenues and reduce ratepayer costs, AEC finds that introducing payment or financial hardship requirements to Connecticut shutoff protections for medically protected customers could cost the State of Connecticut millions by way of increased need for social services. 

This report was included as an Appendix to Connecticut Public Utilities Regulatory Authority's Report to the General Assembly Regarding the Evaluation of Medical Protection available here.

Link to Report

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Assessing Ratepayer Risks of the Proposed Edisto Gas Plant in South Carolina

Client: Conservation Voters of South Carolina (CVSC)

Authors: Joshua R. Castigliego, Elisabeth Seliga, Jordan Burt, PhD, Sagal Alisalad, and Bryndis Woods, PhD

March 2026

On behalf of the Conservation Voters of South Carolina (CVSC), Senior Researcher Joshua R. Castigliego, Assistant Researcher Elisabeth Seliga, Researchers Jordan Burt, PhD and Sagal Alisalad, and Principal Analyst Bryndis Woods, PhD prepared a report that evaluates Santee Cooper and Dominion Energy South Carolina’s December 2025 Joint Application to build a new jointly owned, 2,180-MW natural gas-fired combined cycle generating facility—the proposed “Edisto Gas Plant” or Canadys Joint Resource—on the banks of the Edisto River. The report examines the risks that the project could pose to South Carolina ratepayers if approved by the South Carolina Public Service Commission.

In the report, AEC identifies three primary risks to ratepayers (i.e. the potential for electric customers to face higher costs) as a result of new gas-fired capacity like the proposed Edisto Gas Plant to meet increasing electric demand: (1) uncertain forecasts of customer demand, which could leave ratepayers paying for unused capacity; (2) higher-than-expected capital costs, including from construction delays and cost overruns; and (3) fuel price uncertainty, which can increase operating expenses and, ultimately, electric rates and customer bills. AEC's review of the Companies’ Joint Application reveals several significant concerns related to these risks.

Understanding risks to South Carolina ratepayers, individually and collectively, underscores the importance of prudent utility planning and the need for the Commission to carefully consider whether approving the Companies’ Joint Application for the proposed Edisto Gas Plant would expose ratepayers to unnecessary risk, particularly when alternative, lower-risk pathways may exist that the Companies have not fully evaluated.

Link to Report

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Lower Heating Costs with Thermal Networks

Client: Green Energy Consumers Alliance (GECA) and Black Swan Lab

Authors: Sagal Alisalad and Joshua R. Castigliego

December 2025

On behalf of Green Energy Consumers Alliance (GECA) and Black Swan Lab, Researcher Sagal Alisalad and Senior Researcher Joshua R. Castigliego prepared a white paper analyzing the near-term operational costs of heating for an average Massachusetts household using thermal energy networks compared to gas furnaces. AEC examined two seasonal heat pump rate scenarios for thermal energy networks with a range of efficiency levels from a coefficient of performance (COP) between 6 and 8: (1) HP 1.0: Massachusetts Department of Public Utilities (DPU)-approved seasonal heat pump rates, and (2) HP 2.0: Massachusetts Department of Energy Resources (DOER)-proposed seasonal heat pump rates. The analysis highlights thermal energy networks as the far more cost-effective and energy-efficient choice for an average-sized, average-energy-use household.

Link to White Paper

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Assessing the Net Emissions Benefit for Clean Energy Facilities in Rochester, Massachusetts

Client: New Leaf Energy, Inc.

Authors: Joshua R. Castigliego and Jordan Burt, PhD

November 2025

On behalf of New Leaf Energy, Inc., Senior Researcher Joshua R. Castigliego and Researcher Jordan Burt, PhD conducted an analysis estimating the net change in carbon dioxide (CO2) emissions associated with New Leaf Energy’s two proposed clean energy facilities on High Street in Rochester, Massachusetts. Each proposed facility will house solar photovoltaics (PV) and an energy storage system (ESS) (collectively referred to as a “PV+ESS facility”). Development of Site A requires clearing approximately 23.5 acres of forested land, while Site B requires clearing of approximately 20.6 acres.

AEC estimated the net emission impact of the Site A and Site B PV+ESS facilities by combining (1) “positive” CO2 emissions savings (i.e., reduced emissions) from the electric grid due to renewable energy generation and (2) “negative” CO2 emissions (i.e., increased emissions) due to land-use conversion from forestland to grassland. When these two factors are considered together, the proposed facilities yield substantial net emissions savings (i.e., reduced emissions). AEC’s analysis indicates that the facilities’ grid emissions reductions would outweigh added, by a factor 4.9 times greater for Site A and 4.3 times greater for Site B.

Link to Site A Report

Link to Site B Report

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Duke Indiana Resource Plan Comments

Client: Sierra Club

Authors: Tyler Comings, Joshua R. Castigliego, and Jordan Burt, PhD

September 2025

Principal Economist Tyler Comings, Senior Researcher Joshua Castigliego, and Researcher Jordan Burt, PhD, co-wrote comments on the Duke Energy Indiana 2024 Integrated Resource Plan (IRP) with Sierra Club. The comments argue that Duke should have chosen a different preferred plan that was lower-cost and lower-risk--a portfolio with a lower gas buildout and that converted the Edwardsport coal plant to natural gas as soon as feasible.

Link to Comments

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Accounting for Indirect Fiscal Impacts in Connecticut’s Legislative Review

Client: Connecticut Roundtable on Climate and Jobs (CRCJ)

Authors: Jordan Burt, PhD, Elisabeth Seliga, and Joshua R. Castigliego

August 2025

On behalf of the Connecticut Roundtable on Climate and Jobs (CRCJ), Researcher Jordan Burt, PhD, Assistant Researcher Elisabeth Seliga, and Senior Researcher Joshua R. Castigliego prepared a policy brief that evaluates the use of fiscal notes in Connecticut’s legislative review process and identifies the key limitations in capturing the full extent of a bill’s impact in Connecticut. Fiscal notes summarize the expected impacts on government revenues and expenditures, helping lawmakers evaluate a bill’s impact on government budgets. To best inform decision-making, fiscal notes must accurately reflect the true cost of legislation. In Connecticut, fiscal notes exclude indirect fiscal impacts. The result is a misestimation of a bill’s effect on the state’s budget that can result in beneficial proposals being rejected or flawed legislation being passed. As a first step toward improving the accuracy of fiscal notes, AEC recommends that Connecticut adopt “enhanced fiscal notes” that incorporate both direct and indirect fiscal costs to provide a more complete picture of a bill’s fiscal consequences during the legislative review process.

Link to Policy Brief

Link to Summary

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Alabama Power’s Plant Miller: An Economic Assessment of Alternative Portfolios

Client: Southern Environmental Law Center (SELC)

Authors: Joshua R. Castigliego, Jordan Burt, PhD, and Tyler Comings

July 2025

On behalf of the Southern Environmental Law Center, Senior Researcher Joshua R. Castigliego, Researcher Jordan Burt, PhD, and Principal Economist Tyler Comings prepared a report that evaluates four alternative portfolios to demonstrate that the continued business-as-usual (BAU) operation of Alabama Power’s James H. Miller Jr. Electric Generating Plant (also known as “Plant Miller”) is uneconomic and not in the best interest of customers.

One method of comparing alternative resource portfolios is to examine customer costs on a “levelized” basis—which normalizes total costs by total generation (in megawatt-hours or “MWh”) over an assumed time period. The levelized cost of energy (LCOE, in $ per MWh) provides insight into how each of the alternative portfolios compare to one another regardless of the total energy provided by each portfolio. Among its four modeled alternatives, AEC finds that replacing Plant Miller with clean energy and storage resources is cheaper on a levelized cost basis than keeping the plant operational into the 2040s.

Alabama Power should also continually evaluate the costs and risks of keeping the plant on-line by looking at viable alternatives. Although the alternative portfolios presented in this report are meant to be illustrative, the results of the analysis have demonstrated that the continued operation of Plant Miller (with or without carbon sequestration retrofits) is uneconomic, and Alabama Power would be able to provide customers with cost savings by investing further in clean energy resources. In order to determine the most cost-effective replacement of Plant Miller, Alabama Power should periodically conduct capacity expansion modeling that considers the retirement of Plant Miller in the context of the Company’s entire system.

Link to Report

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Basin Electric's Coal Fleet: Risks to Continued Operation and Opportunities for Replacement

Authors: Bryndis Woods, PhD, Joshua R. Castigliego, Jordan Burt, PhD, Elisabeth Seliga

Client: Western Organization of Resource Councils

June 2025

On behalf of the Western Organization of Resource Councils, this AEC report evaluates the risks associated with continued operation of Basin Electric’s coal-fired plants and outlines opportunities for replacement with lower-cost clean energy resources. The continued operation of Basin Electric’s coal plants entails important risks to Basin Electric, its members and members’ ratepayers, including risks presented by: 

1. Federal oversight: In 2019, Basin Electric became subject to Federal Energy Regulatory Commission (FERC) oversight, which means Basin Electric is facing greater scrutiny of whether continued operation of its coal plants is most prudent for its members and their ratepayers. 

2. Competition in Southwest Power Pool (SPP): Basin Electric’s forthcoming full membership in the Southwest Power Pool (SPP) risks that Basin Electric’s coal plants will operate less often because more of its coal generation will compete in every hour of the day with every other resource in SPP’s marketplace.

3. Environmental regulations: There are cost risks for Basin Electric’s coal-fired power plants related to new emission and pollution control technologies to comply with federal environmental regulations including: the Regional Haze Rule, the coal ash waste rules, and carbon pollution standards.

AEC finds that Basin Electric can hedge against risks to its coal-fired resources by taking advantage of cost-saving opportunities to replace coal resources with cheaper wind and solar resources—resources which become even more cost-effective when coupled with federal incentives, funding, and financing streams targeted specifically at electric cooperatives to pursue them. 

Link to Report

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LG&E-KU’s 2024 Integrated Resource Plan: An Assessment

Client: Mountain Association (MA), Kentuckians for the Commonwealth (KFTC), Kentucky Solar Energy Society (KYSES), and Metropolitan Housing Coalition (MHC)

Authors: Joshua R. Castigliego, Elizabeth A. Stanton, PhD

March 2025

On behalf of the Mountain Association (MA), Kentuckians for the Commonwealth (KFTC), Kentucky Solar Energy Society (KYSES), and Metropolitan Housing Coalition (MHC) (collectively, the “Joint Intervenors”), Senior Researcher Joshua R. Castigliego and Principal Economist Elizabeth A. Stanton, PhD prepared a white paper that sets out best practices for IRP modeling and reporting, and assesses the Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU) (collectively, LG&E-KU) 2024 IRP filed on October 18, 2024 in Case No. 2024-00326 based on those criteria.

AEC’s best practices are organized into five categories: (A) Demand-Side Analysis; (B) Supply-Side Analysis; (C) Modeling Structure; (D) Selection of Recommended Plan; and (E) Stakeholder Input. Through its best-practices assessment, AEC finds that LG&E-KU’s 2024 IRP is missing critical components and includes errors in forecasting key assumptions, resulting in an overall flawed least-cost resource plan selection. LG&E-KU’s failure to follow IRP best practices results in resource decisions that are not properly informed (or justified) by comprehensive IRP modeling, leading to possible adverse effects on ratepayers. In particular, the flawed IRP findings may result in support for uneconomic resource additions in near-term CPCN applications.

Link to White Paper

Link to Joint Intervenors’ Comments

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