Overview

Since 2023, US electricity demand projections have surged, primarily driven by data centres and large industrial consumers. In response, many electric utilities are proposing extensive expansions of gas-fired generating fleets over alternatives such as wind, solar, and battery storage. However, the planning processes underlying this nationwide “rush to gas” often fail to reflect the total system costs. Research indicates that planning assumptions frequently understate current market conditions for generator capital costs and omit the significant fuel supply and transportation infrastructure costs required to support these new plants.

Global Energy Monitor identifies over 250 GW of gas power plants in development in the US, equating to approximately 38 Bcf/d of peak gas demand—roughly 17 times the amount of interstate pipeline capacity added in 2025. To ensure these plants are dispatchable, new firm transportation (FT) rights and expanded gas infrastructure are required, including interstate pipelines, compressor stations, and liquefied natural gas (LNG) storage facilities.

The fuel supply chain

Gas-fired generation requires both physical delivery infrastructure and security of supply. Physical delivery involves a chain of pipelines spanning interstate systems and plant-level connections, such as onsite laterals and storage. Security of supply is typically managed through FT agreements that reserve pipeline capacity in exchange for fixed reservation charges. Without these, plants face curtailment risks during peak demand. These infrastructure layers carry significant fixed costs that are rarely evaluated in an integrated manner during electric utility resource planning, which can materially understate the true cost of new generation.

Fragmented oversight

The report highlights a “sequencing problem” caused by the fragmented regulatory structure governing electric and gas systems. Typically, a generation plant is approved first, with fuel security issues addressed in separate, later proceedings. This bifurcation means the total cost exposure for ratepayers is dispersed across various mechanisms, obscuring the full financial picture. Ratepayers often bear the risk if investment costs exceed initial estimates and face potential stranded-asset risks if the gas infrastructure outlives the useful life or high utilisation of the power plant.

Case study | We Energies (wisconsin)

Reviewing We Energies’ filings illustrates these challenges in practice. In 2024, the company updated its resource plan to incorporate over 2,000 MW of new load, coinciding with a new Microsoft data centre. This prompted concurrent applications for new gas-fired generation, including the 1,110 MW Oak Creek project. To support this, an affiliate proposed over $600 million in new pipeline and storage projects. These initial infrastructure costs represented over 30% of the proposed capital spending to support the new data centre load. Projected needs have since grown to 6 Bcf of LNG storage and 3,300 MW of capacity through 2030.

The hidden 30%

While power plant construction requires upfront capital, supporting gas transmission infrastructure can add hundreds of millions in fixed expenses. Analysis suggests these “hidden costs” typically range between 10% and 50% of the proposed capital spending, with 30% being an indicative value. In South Carolina, Santee Cooper’s planned expansion at Canadys Station is supported by a $5.6 billion investment in gas infrastructure, where the infrastructure share comprised approximately 25% of the total cost.

A nationwide rush to gas

New power plants are increasingly proposed alongside related gas infrastructure projects. In Georgia, 95% of Georgia Power’s demand increase is driven by data centre growth. Similarly, Duke Energy in North Carolina is proposing new LNG storage to support several combined cycle plants. In some regions, requests for firm delivery from new power generation have overwhelmed existing customer growth; for example, We Energies received requests to increase firm deliverability by 85% for power plants compared to 4% for its existing customer base.

Solutions

The report suggests several pathways to improve transparency, including the creation of standardised gas infrastructure planning documents and clearer delineation of FT rights. To ensure affordability, it recommends establishing rules so that new large loads bear the incremental costs they trigger, rather than subsidising these through existing customer rates. Addressing “capital bias” is also critical, particularly where a common holding company owns both the electric and gas utilities, potentially incentivising gas projects over more affordable alternatives.

Conclusions and next steps

The research concludes that power generation needs represent a growing fraction of pipeline demand and that utilities often pass costs and risks directly to retail customers. Key recommendations for regulators and policymakers include:

• Aligning planning and approval processes for major gas and electric projects to ensure total costs are considered.
• Creating a unified gas-electric reliability modelling framework using integrated assumptions for fuel deliverability and extreme-weather performance.
• Requiring a unified cost test for new generation that combines plant capital expenditure with all associated gas-system costs.
• Building a standardised public database of gas infrastructure projects linked to new power generation.
• Establishing cost allocation rules to protect existing customers from subsidising infrastructure for large new loads.