Duke Energy intends to submit an application to South Carolina’s Public Service Commission (PSC) for approval to build a 1.4-GW gas-fired combined cycle plant with hydrogen capability in Anderson County. If approved, the project, which could come online in 2031, will mark the company’s first new generation proposal in the state in a decade.

The utility on June 9 announced it intends to file a construction application to the PSC later this year to build the proposed plant on a on a 200-acre site along Highway 81 South near True Temper Road.

“The project is currently in the early stages of planning, engaging, and permitting,” it said on a company page. “Public engagement is an important part of the development process, as it helps us understand local interests, priorities and identify opportunities to have a meaningful and positive presence in the community.” The project has yet to undergo “several more years of study and due diligence before committing to move forward,” it said.

“If we proceed with the project and obtain all necessary approvals and permits, construction could begin in mid-2027 with operations targeted for as early as  January 2031. Updates and milestones will be shared throughout the process,” it said.

Duke Energy’s most recent gas-fired power plant built in the Palmetto State is the W.S. Lee Station in Anderson County, South Carolina, which began operating on April 5, 2018. The 750-MW combined-cycle natural gas plant powers up to 600,000 homes using high-efficiency technology that captures exhaust heat to generate additional electricity. The company’s newly proposed 1,400-MW hydrogen-capable combined-cycle plant—announced in June 2025 for a site in the same county—will mark Duke Energy’s first new generation project request in South Carolina in over a decade. Courtesy: Duke Energy

Duke Energy’s Anderson facility will deploy GE Vernova’s gas turbines and associated equipment, manufactured at the company’s Greenville, South Carolina, plant. The effort will leverage a sweeping April 2025 agreement between the two firms that could secure up to 11 7HA units across Duke’s service territories, where surging industrial and data center demand is driving rapid capacity expansion.

The partnership is the latest between an array of original equipment manufacturers (OEMs) and utilities and power companies, which are seeking to address an intensifying push to lock in dispatchable generation. As POWER reported in its April 2025 cover story, “Gas Power’s Boom Sparks a Turbine Supply Crunch,” utilities are facing long lead times and competitive bidding for production slots, with some deliveries stretching into 2029 or beyond. The gas turbine crunch has prompted a return to practices not seen since the early 2000s—including upfront reservation fees and multi-year turbine procurement planning.

GE Vernova, which booked 22 GW in gas turbine orders in 2024 (and appears to have reclaimed the global lead for advanced-frame units), is aggressively expanding its U.S. manufacturing capacity to meet surging demand. In January, the company announced a $160 million investment at its Greenville, South Carolina, facility—its largest since the company’s spinoff from GE in April 2024. The expansion is expected to support increases in turbine production, quality, testing capabilities for hydrogen fuel, and delivery speed.

The Greenville site, which has produced turbines since 1968, is central to GE Vernova’s broader $600 million U.S. manufacturing initiative and part of a $9 billion global capital and research and development plan through 2028. GE Vernova CEO Scott Strazik on April 23 noted that the upgrades will raise global heavy-duty turbine capacity by more than 25%—from 55 units per year to between 70 and 80 by 2026.

Duke Energy, however, has not disclosed the terms of its agreement with GE Vernova or contingency plans if supply chain disruptions occur. While the company cites reliability as a key driver for the Anderson County plant, it also notes its effort is backed by its future planning and recent policy developments in South Carolina, including the Energy Security Act, which Governor Henry McMaster signed into law on May 12, 2025.

“The significant, wide-ranging energy legislation is the result of bipartisan efforts to holistically address the unprecedented economic growth and corresponding generation needs of the state,” noted law firm McGuirWoods in May. “The 72-page law seeks to achieve this goal through measures including provisions impacting South Carolina ratemaking, integrated resource planning, facilitation of new generation, expanded policy support for advanced nuclear resources, energy efficiency initiatives, new economic development rate design framework, and refinements to the existing regulatory process and state energy policy.”

Notably, the Energy Security Act specifically urges Duke Energy Carolinas and Duke Energy Progress to evaluate and deploy hydrogen-capable or conventional natural gas facilities as part of their integrated resource plans, reflecting the state’s push for both immediate reliability and future fuel flexibility. In parallel, the law directs Dominion Energy South Carolina and the state-owned Santee Cooper to jointly develop new natural gas generation at or near the former Canadys coal plant—a site that, once converted, is expected to become one of the nation’s largest gas power stations and a linchpin in replacing retiring coal assets.

 The law also encourages Duke to expand energy storage, including pumped hydro at its Bad Creek facility, and instructs Santee Cooper to consider using domestic wood products as auxiliary fuel sources. And, more broadly, the law emphasizes expedited siting and permitting of brownfield energy projects—such as Duke’s Anderson County proposal—by instructing all state agencies to prioritize reviews and approvals of energy infrastructure over the next decade, recognizing these projects as “crucial to the welfare of the state.” Agencies will be required to provide accelerated consideration and assistance, with strict deadlines for permit decisions, to ensure that new generation and grid upgrades can keep pace with South Carolina’s surging economic and population growth.

According to Duke Energy, the Anderson plant is consistent with “near-term actions approved in the company’s Carolinas Resource Plan in 2024.” In November 2024, the North Carolina Utilities Commission (NCUC) issued an order accepting a broad stakeholder settlement that endorsed Duke Energy’s revised load forecasts, affirmed a more diverse resource mix, and approved near-term development of three new combined cycle gas units and four combustion turbine units by 2031. Those additions—CC1 through CC3 and CT1 through CT4—are now being actively implemented. However, the NCUC also directed Duke Energy to continue refining its long-term modeling, especially in light of growing demand and technology shifts, and to submit a fully updated Integrated Resource Plans (IRP) in fall 2025.

For now, Duke Energy is working to finalize its next IRP for the Carolinas, which is due to the NCUC in September 2025 and to the Public Service Commission of South Carolina by November 2025. The utility, which serves over 4.6 million retail customers in the region, has spent the first half of 2025 holding a four-part public engagement series—facilitated by the Great Plains Institute—to review evolving grid needs, technology assumptions, and long-term resource strategies.

During a May 22 IRP session, the utility stressed its strategy will be essential to keeping pace with projected annual load growth of 4% to 5% in the Carolinas, driven by more than 1,000 MW of new commercial and industrial demand now backed by signed or near-final customer commitments. The company’s current efforts detail a framework to evaluate capacity additions through 2040, and place a sharp focus on firm, dispatchable resources that can meet rising peak demand amid a rapid influx of large industrial loads, data centers, and advanced manufacturing facilities across both states.

Notably, the May session suggests that Duke Energy is modeling up to five new combined cycle gas plants and at least four new combustion turbine units by 2040. The company’s modeling caps combined cycle additions at two projects per year, with cumulative limits that trigger additional infrastructure requirements beginning with the fourth unit.

Owing to persistent constraints in the Transcontinental Gas Pipe Line Zone 5 pipeline corridor, Duke confirmed that any gas project beyond CC3 could require incremental fuel security—either through firm interstate transportation (FT) or the development of intrastate liquefied natural gas (LNG) storage. Internal modeling, notably, assumes 14 days of full-load burn coverage per CC unit, and Duke Energy is currently evaluating capital costs and seasonal dispatch scenarios to determine whether LNG could provide a more cost-effective hedge against both fuel volatility and renewable intermittency.

The May meeting also focused heavily on hydrogen-capable gas turbines. Duke planners discussed leveraging OEM forecasts, such as GE Vernova’s projection of 100% hydrogen capability in advanced-class turbines by 2030, to inform fuel flexibility scenarios. It suggests the IRP will include sensitivity runs incorporating hydrogen price projections, tax credit trajectories, and potential hydrogen blending timelines, especially as federal support for Southeast Hydrogen Hub development remains uncertain. Modeling from the utility indicates that hydrogen readiness may be a critical differentiator for new gas units, which may remain operational through 2050 and beyond.

While the Carolinas IRP is also modeling significant additions of solar, battery storage, and long-duration energy storage (LDES), Duke Energy made clear that firm capacity remains a near-term priority. The company is simultaneously advancing early site permitting for new nuclear units—including small modular reactors—and exploring expanded pumped hydro, even if those resources are unlikely to be online this decade.

In its November 2024 order, for example, the NCUC approved $440 million in early development costs to advance Duke Energy’s next wave of nuclear capacity, targeting 300 MW of advanced nuclear online by 2034 and 600 MW by 2035. The May 2025 IRP meeting suggests Duke is preparing to submit an early site permit application this year for small modular reactors (SMRs) at its Belews Creek site in North Carolina, while also conducting feasibility work for deploying AP1000 large light-water reactors at the W.S. Lee site in South Carolina.

Additional reactors at Harris Nuclear Plant in North Carolina are also under study. The company is modeling technologies including the GEH BWRX-300, X-energy’s Xe-100, and TerraPower’s Natrium design, and participating in DOE-supported collaborative efforts to accelerate licensing and reduce costs through standardized reactor design.

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).