Two years ago, JEA, Florida’s largest municipal utility that provides electric and water services for over a million residents and businesses in the City of Jacksonville and Duval County, produced an integrated resource plan (IRP) that claimed that a gas plant would provide the most affordable option to provide new electricity generation to meet the county’s growing needs. However, much has changed in the past two years — power demand from data centers has pushed up the demand for gas turbines, and recent federal policy changes have increased projections of natural gas exports while simultaneously reducing incentives for clean energy. These changes warrant a fresh look at the possibilities to meet Jacksonville’s energy needs.

As a municipal utility, JEA’s decisions are largely approved by its board, but any large energy projects over 75 megawatts (MW) must be approved by the Florida Public Service Commission (PSC) through a need determination process.

In its 2023 IRP, JEA proposed to build a 571 MW gas plant in 2029. This would further increase JEA’s overreliance on gas and the need to purchase power. Last year, 63% of the utility’s energy came from gas, and 14% from purchased power. This overreliance on gas means electric bills are more sensitive to gas price fluctuations, making energy costs higher and more volatile.

A lot has changed since 2023. The utility landscape has shifted from an era of minimal load growth to one where large but uncertain loads are triggering massive generation projects and grid upgrades, often at the expense of other ratepayers. This increased demand for power has driven up the demand for gas, for both the fuel commodity and the physical turbines that can generate electricity, leading to price spikes and even supply chain shortages that are causing delays in the construction of new gas plants.

The federal landscape has shifted as well. Under the current Congress and administration, tax credits for solar and wind will soon be unavailable without decisive action, and other carbon-free energy resources like battery storage, geothermal, and nuclear are subject to strict foreign entity of concern (FEOC) rules that may severely limit the ability for these resources to receive tax incentives. Furthermore, the approval of liquified natural gas (LNG) terminals to send gas abroad will likely constrict the supply of domestic natural gas by linking gas to the global markets, which will further increase fuel costs.

Given all these changes,  rather than requiring JEA’s customers to pay for a potentially expensive gas plant for the next three decades based on assumptions that no longer hold true, there is an imperative to revisit the potential for cleaner and more affordable alternatives. RMI conducted analyses of potential alternative clean energy portfolios (CEPs) that would meet the energy and reliability standards of the proposed gas plant, comparing the financial cost and the health impacts. We also looked at the potential economic development benefits from the CEPs. We modeled 72 different scenarios and sensitivities around gas and CEP costs; however, we exclude our lowest gas plant cost estimates, which were based off of JEA’s 2023 IRP, because of how much lower these estimates were compared to recent cost estimates from JEA and other recent industry estimates.

We found that CEPs are less expensive than a gas plant in over 80% of our scenarios. Overall, CEPs are less expensive, less risky, would avoid $2 billion in local air pollution impacts, and provide at least $300 million in economic benefits to the region.

On August 26^th, JEA’s board voted to approve construction of a 657 MW natural gas plant that will cost $1.57 billion, or $2,326 per kilowatt (kW), to be deployed in 2031 or 2032. While RMI’s analysis uses JEA’s 2023 IRP proposal of 571 MWs deployed in 2029, the high-cost gas plant scenarios use a very similar cost based on recent gas plant procurements of $2,277 per kW. Given JEA made its initial decision based on gas cost projections of $919/kW, which thoroughly underestimates JEA’s most recent stated costs of $2,326/kW, our analysis provides strong evidence that clean energy portfolios are lower cost and lower risk than the proposed gas plant.

Energy efficiency is heavily underutilized and could help meet energy and capacity needs

To compare how CEPs could reliably replace the proposed gas plant, we created portfolios that both match the projected annual generation and accredited summer and winter capacities of the gas plant. We created four CEPs that look at varying levels of reliability assumptions and energy efficiency utilization. RMI analysis predated an announcement by JEA on August 26, where the utility announced it would pursue building a 675 MW gas plant, instead of a 571 MW plant as proposed in its 2023 IRP, although the same principles would apply to a follow-up analysis.

In its 2023 IRP, JEA both undervalued the ability of clean energy resources like solar to contribute to reliability, as well as underutilized energy efficiency. Energy efficiency encompasses measures such as improved insulation, window upgrades, and more efficient appliances, which reduce energy demand while also improving indoor air quality and maintaining safe temperatures, critical in extreme heat. On the commercial and industrial side, efficiency opportunities such as advanced lighting, HVAC upgrades, and optimized industrial processes can yield significant cost savings while lowering peak demand.

According to a 2021 ACEEE report, JEA spent 0.42% of its revenue on energy efficiency efforts, compared to the regional and national averages of 1.64% and 2.58%, respectively. JEA’s current and high energy efficiency scenarios reach only 14% and 25% of technical potential, respectively; economic and achievable potentials are significantly higher, estimated at 65% and 40%–55%, respectively.

One of the reasons for Florida’s shortcomings in energy efficiency is because Florida is the only state that uses the ratepayer impact measure (RIM) test to measure energy efficiency. The RIM test is a faulty measure of cost-effectiveness, can produce perverse outcomes by penalizing utilities that succeed in installing energy efficiency, and is not applied to other supply-side utility investments. Greater utilization of energy efficiency measures could help support JEA’s energy and capacity needs.

JEA’s IRP also assumes low solar capacity accreditation values — 20% in summer and 0% in winter — compared to the North American Electric Reliability Corporation’s (NERC) estimates of 54% (summer) and 17% (winter) for the Florida Peninsula region. The proposed gas plant’s capacity accreditation assumptions (91% summer/100% winter) are higher than NERC’s regional benchmarks (77%/86%), which account for weather-related risks. JEA’s and NERC’s capacity accreditation values both undervalue solar and overvalue gas in terms of their contribution to reliability.

We modeled four clean energy portfolios that match the accredited capacity and annual generation of the proposed gas plant, each varying by energy efficiency levels and ELCC assumptions for solar and gas.

• JEA’s Reliability Assumptions portfolio uses JEA’s capacity accreditation values and assumes energy efficiency growth between JEA’s current outlook and high scenario.
• Realistic Reliability Assumptions portfolio keeps the same energy efficiency assumptions but replaces capacity accreditation values with NERC regional standards for solar and gas.
• Middle Energy Efficiency applies NERC-standard capacity accreditation and assumes energy efficiency reaches 45% of technical potential, aligning with levels often deemed achievable by other utilities.
• High Energy Efficiency increases energy efficiency to 64% of technical potential, reflecting the highest economic potential considered for JEA.

Maximizing energy efficiency potential allows JEA to reduce overall demand, enabling smaller clean energy portfolios to meet both capacity and generation needs. By fully leveraging achievable efficiency levels, JEA could right-size its investments, lower costs, and avoid unnecessary overbuilding of generation assets.

Current industry costs show CEPs are lower cost and lower risk than gas plants, even with reduced tax incentives

We next compared these four CEPs and the proposed gas plant using a version of RMI's Co-op Federal Funding Calculator, modified specifically to incorporate a potential new gas plant and to calculate energy efficiency costs. Three major components drive our sensitivity analysis and have injected uncertainty since JEA's 2023 IRP.

On the gas side, gas turbines are in high demand and short supply, causing capital costs for gas power plants to be two to three times more expensive than they were a few years ago. And that is assuming a turbine can be procured in the first place, as the earliest new turbines can be secured is in 2030 according to major turbine manufacturers.

In addition to JEA's assumed costs in its 2023 IRP, which were $973/kW in 2025 dollars, we also use the National Renewable Energy Lab's (NREL) 2025 Annual Technology Baseline (ATB) projected costs for a new gas plant ($1,904/kW in 2025 dollars) and a recent procurement for a similar gas turbine in Indiana by Duke ($2,277/kW in 2025 dollars), to model a central and high capital cost case that more accurately reflect current market conditions.

RMI analysis predated JEA's August 26 announcement updating cost estimates for the gas plant, which translates to $2,326/kW. Normalized to 2025 dollars, these numbers are 139% higher than JEA's 2023 estimate, 34% higher than our assumed central estimate from NREL, and 2% higher than our high estimate from Duke Indiana's recent gas turbine procurement. Because of how far JEA's 2023 IRP gas plant cost estimates are from the utility's August 2025 announcement, we excluded JEA's initial cost estimates from our following charts.

Furthermore, the recent push to approve LNG terminals alongside commitments from Europe and South Korea to purchase a minimum amount of LNG will both increase demand for US-produced LNG, as well as further link the US natural gas market to the international gas market, raising the possibility of increased and more volatile fuel prices. We model a high fuel price scenario to reflect this possibility, using the Energy Information Administration's 2025 Annual Energy Outlook scenarios for normal and high gas prices in the South Atlantic region.

On the clean energy side, recent federal legislation known as the One Big Beautiful Bill (OBBB) has significantly impaired the tax incentives for solar and wind, and potentially even battery storage. Solar and wind must either commence construction by July 4, 2026, or be placed in service by 2027, to qualify for the production tax credit (PTC) or investment tax credit (ITC). Furthermore, recent guidance from the Internal Revenue Service has narrowed the definition of commencing construction, making this safe harbor stricter and harder to qualify for.

Moreover, starting for all projects beginning construction in 2026 or later, OBBB implemented FEOC rules that will prevent energy projects from receiving the PTC or ITC if there is too high a percentage of equipment from "prohibited foreign entities." There are many uncertainties around the implementation of the FEOC rules; however, as a public utility receiving elective pay, JEA would still need to use a certain percentage of domestic content to qualify for direct pay tax credits.

As a result of all these uncertainties, we modeled three tax credit sensitivities: an optimistic sensitivity where both solar and storage receive the tax credits, a middle case where only storage receives the tax credit, and a worst-case sensitivity where neither solar nor storage receive tax credits. Overall, we modeled three gas scenarios (low, medium, and high capital and O&M costs; although we only display the central and high gas plant costs because of the wide disparity between JEA's 2023 IRP gas plant cost estimates and its August 2025 estimate) with two fuel sensitivities (central and high fuel prices), and four CEP scenarios with three tax credit sensitivities (solar and storage receiving tax credits, only storage receiving tax credits, and neither resource receiving tax credits).

Our analysis finds that CEPs are both lower cost and lower risk than building a gas plant. However, with gas capital costs from JEA's 2023 IRP and normal fuel costs, building a gas plant is less expensive than building a CEP. We estimate that building and operating this proposed gas plant would cost $2.3 billion in net present value (NPV) using these assumptions. However, both of these cost assumptions have significantly changed in the past two years.

For fuel costs, using higher fuel cost assumptions adds nearly $1 billion in overall NPV costs to the gas plant. And higher capital cost assumptions add between another $1 billion (using NREL ATB costs) to $1.5 billion (using recent Duke Indiana gas procurement costs). This means that JEA's gas plant may incur an additional $2.5 billion in NPV costs for a total of $4.8 billion — more than double the costs of the gas plant proposed using JEA's cost assumptions and normal projected fuel costs.

Losing the ability to use clean energy tax credits can significantly increase costs, but the magnitude depends on the size of the portfolio. Increased energy efficiency can reduce the need to overbuild solar and storage. Using JEA's reliability assumptions around solar and gas, which requires the most solar and storage build out, going from full tax credits to no tax credits causes over $1 billion in additional NPV costs, or from $3.4 billion to $4.4 billion. However, in the High Energy Efficiency and Medium Energy Efficiency scenarios, the loss of tax incentives only increases costs between $510 and $657 million.

Using realistic assumptions around both gas and clean energy assets, costs vary from $2.7 to $3.4 billion NPV. This is lower than both the central and high capital and O&M cost scenarios for gas plants, which are more accurately reflective of costs today. And the Middle Energy Efficiency portfolio costs between $2.4 and $3.1 billion, and the High Energy Efficiency costs between $2.1 and $2.6 billion, portraying that incorporating more energy efficiency can significantly reduce costs.

Our findings include the following:

• Two-thirds of the CEP scenarios and sensitivities we modeled are lower cost than the gas plant scenarios and sensitivities; however, this is inclusive of the "Low Capital and O&M Cost" scenarios, which uses cost data from JEA's 2023 IRP. The August 2025 announcement from JEA has estimated capital costs that are 139% more expensive than these 2023 cost assumptions.
• When excluding these low capital cost assumptions for the gas plants, over 80% of CEP scenarios and sensitivities are less expensive than the gas plant scenarios and sensitivities.
• Finally, JEA's August 2025 projected gas plant capital costs are very close — 2% higher — to the "High Capital and O&M Cost" scenarios we modeled based off a recent Duke Indiana gas plant procurement. Comparing just these scenarios to clean energy alternatives, 91% of CEP scenarios are lower cost.

Furthermore, a gas plant is not only higher cost, but also higher risk, especially given concerns around gas turbine availability and rising fuel prices from increased LNG exports. JEA has already had to delay its gas plant from 2029 to 2031 at the earliest. Overall, using more realistic assumptions around both gas and renewable reliability, updating gas plant construction costs to reflect how high gas plant costs are today relative to just a few years ago, and increasing the use of energy efficiency measures, show that CEPs are less costly than gas plants, and may be the only option to get electricity access in the near term. Even without tax credits for solar and storage, the Middle Energy Efficiency and High Energy Efficiency portfolios are lower cost than nearly every gas portfolio.

A new gas plant would cause nearly $1 billion in local health impacts, and over $2 billion in state health impacts

RMI used the Environmental Protection Agency’s (EPA) CO-Benefits Risk Assessment (COBRA) tool to estimate health impacts from the proposed 571.3 MW gas plant in Duval County, based on IRP-projected capacity factors. The tool models emissions-related pollutants that harm human health (specifically PM2.5, SO₂, NOₓ).

Total health-related economic impacts from the plant’s emissions are projected to exceed $2 billion in Florida, including ~$1 billion in Duval County alone. COBRA translates these effects into economic health costs, as well as specific outcomes like asthma cases, hospital visits, work/school days lost, and mortality.

Over the gas plant’s lifetime, EPA’s COBRA tool estimates these pollutants will lead to 155 premature deaths, 665 new asthma cases, more than 105,000 asthma symptom incidents, 56,000 school day losses, and 3,600 workday losses. These health costs significantly affect local communities and represent externalities not captured in the plant’s dollar cost alone. But incorporating the $974 million in health impacts on Duval County into the plant’s NPV costs could increase costs by 43% using JEA’s lowest capital cost and central fuel cost gas scenario.

CEPs would provide between $429 and $757 million in local economic benefits

RMI estimated the economic impact of each CEP using a modified and updated approach used in RMI’s Seeds of Opportunity report. Each CEP’s buildout of solar, storage, and energy efficiency was used to estimate direct local economic benefits in Florida. These benefits include land lease payments, tax revenues, and construction and O&M wages. These portfolios would support 3,331–5,251 construction jobs and 35–66 operations and maintenance jobs, which translates to 4,206–6,206 job years.

These findings underscore that clean energy portfolios offer not only environmental and reliability benefits, but also meaningful, tangible economic value to local communities. As Florida considers future energy investments, the economic returns from clean energy buildouts present a compelling case for accelerating their deployment.

Changes in market conditions and policies have altered the economics of both gas plants and renewables. RMI analysis that accounts for these changes and makes realistic assumptions around reliability contributions finds that CEPs are lower cost and lower risk than JEA’s original proposed gas plant while providing the same level of reliability.

Updated assumptions around reliability based on the latest NERC study show that gas plants contribute less to reliability and clean energy contributes more to reliability than JEA assumed in its 2023 IRP. Combined with the increasing costs for gas, both in terms of capital costs and fuel prices, this shows that the right portfolio of solar, storage, and energy efficiency can provide the same reliability and energy benefits at a lower cost to JEA customers. Furthermore, the gas plant will cause $2 billion in negative health impacts to Floridians at large, with $1 billion in these impacts concentrated in Jacksonville and Duval County. Finally, CEPs can provide significant economic benefits for the local community, with 3,331–5,251 construction jobs and 35–66 long-term operations and maintenance jobs.

Much has changed since JEA’s 2023 IRP. Nevertheless, JEA has begun the process of locking in the gas plant, despite a 139% increase in costs from its 2023 IRP and a delay of at least two years. The costs JEA has projected for this gas plant are nearly identical to our “High Capital and O&M Costs” gas plant scenarios, where 91% of CEP scenarios are lower cost comparatively. Despite these changes, JEA has not reevaluated other alternatives and is actively betting its future, and the future of Jacksonville households, on gas. Our findings show that at the very least, a more updated analysis should be conducted to make sure the city’s electricity needs are met by the lowest-risk, lowest-cost option.