Turbine Shortage Turns Used Gas Plants Into AI Data Center Gold

Global orders for gas turbines now top 100 gigawatts against worldwide production capacity estimated at 60 to 70 gigawatts, according to Reuters, and in the US a new turbine takes six years on average to deliver. That gap, reported on November 9, 2026, has turned gas turbines into the tightest bottleneck in the AI power chain. Data center developers are now hunting for used turbines, mothballed machines, converted jet engines and, in the most aggressive cases, entire operating gas plants.

The market stakes are straightforward. New turbines will not arrive before the 2030 to 2031 delivery window, so whoever owns working megawatts today, or the factory slots to build new ones, holds the pricing power in AI buildouts. A 24/7 Wall St. analysis frames the story around the manufacturer at the choke point, GE Vernova, and four merchant generators: Vistra, NRG Energy, Talen Energy and Constellation Energy.

Why is there a secondhand market for turbines?

The arithmetic is brutal. Orders exceed 100 GW. Capacity sits at 60 to 70 GW. Reuters reports that new turbines cost about $2 million to $2.5 million per megawatt for the equipment alone, and buyers still face the delivery queue. The result is a secondary market that runs from single used machines to whole-plant acquisitions priced at a premium to new-build costs.

All five companies in the story generate positive cash flow, but from different sources. GE Vernova earns from an equipment and services backlog. The four independent power producers earn from wholesale power prices, capacity auctions and hedges, and none has a regulated utility's rate base to guarantee its returns.

What is GE Vernova's position?

GE Vernova (NYSE: GEV) is the supplier everyone in this story is waiting on. In the third quarter it signed 11 gigawatts of gas orders and slot reservations, raising its total under contract from 116 to 122 gigawatts. The company expects to reach at least 130 gigawatts by the end of 2026, up from 83 gigawatts at the start of the year. Delivery slots are already sold into 2032, and chief executive Scott Strazik said aeroderivative capacity is "sold out so far".

Annual gas turbine output is set to rise from 20 GW in Q3 2026 to 24 GW in 2028 and 30 GW by 2030, which still leaves the order book ahead of the factories.

The financials show the leverage scarcity provides. Third-quarter revenue was $12.64 billion, up 26.8 percent year over year. GAAP diluted EPS of $4.81 beat the $4.01 consensus. Total backlog reached $197 billion, and management raised 2026 free cash flow guidance to $16 billion to $17 billion from $11.5 billion to $12.5 billion.

Scarcity gives pricing power. Management expects 2026 gas orders to be priced about 50 percent higher per kilowatt than 2025 orders. Power EBITDA margin reached 21.4 percent, up 830 basis points. Each gigawatt of its large HA-class turbines is expected to produce $0.5 billion of high-margin services revenue over the first 20 years. Data center customers make up about 20 percent of its roughly 100 gas power customers.

The risks: the Wind segment is guided to $400 million to $500 million of EBITDA losses for 2026, and Barron's linked recent pressure on the stock to a Democratic sweep in the elections. Shares traded at $829.12 on Monday morning, up 7.11 percent on the session, down 16.8 percent over one month and up 27.16 percent year to date.

How is Vistra buying megawatts instead of waiting?

Vistra (NYSE: VST) is the clearest example of the secondary market working at the scale of whole plants. It closed the Cogentrix acquisition on October 30, 2026, adding about 5,500 megawatts of mostly combined-cycle gas generation at a net price of about $4 billion, or about $729 per kilowatt. Vistra has now closed over 12 gigawatts of acquisitions at less than 7x forward EBITDA on average. Its fleet totals about 50,000 megawatts.

Third-quarter revenue rose 27.7 percent to $6.35 billion, and adjusted EBITDA came in at $2.378 billion. Management guided 2027 adjusted EBITDA to $7.7 billion to $8.5 billion. Vistra has also contracted existing gas plants directly to data centers, signing a 20-year, 207 MW power purchase agreement with New Era Energy and Digital at its Odessa combined-cycle plant in Texas.

Chief executive James Burke called flexible gas "the cheapest and quickest source of incremental generation." Vistra can contract plants it already owns at little added capital, and it has nuclear capacity at Beaver Valley and part of Comanche Peak still uncontracted.

The exposure is ERCOT, the Texas grid, where forward prices have been trending lower. Vistra is 78 percent hedged for 2028 overall but much less hedged in ERCOT. Shares traded at $133.49, up 6.96 percent Monday and down 16.88 percent year to date.

Why is NRG selling plants for more than new-build cost?

NRG Energy (NYSE: NRG) sits on the selling side of the secondary market. It signed a definitive agreement to sell just under 4.9 gigawatts of gas-fired plants in New York, Texas and New England to LS Power for $4 billion, eight times expected 2027 adjusted EBITDA. The deal implies a value of about $1,400 per kilowatt for the Jack County facility. NRG says it is developing 1.5 gigawatts of new Texas gas generation for just above $1,000 per kilowatt. Existing megawatts are selling for more per kilowatt than NRG expects to pay to build new ones.

Third-quarter adjusted EPS of $4.68 beat the $3.03 consensus, and revenue rose 24.0 percent to $9.47 billion. NRG plans $3 billion of total repurchases across 2026 and 2027 and $2 billion of debt reduction when the sale closes. The 2027 dividend is planned to rise to $2.05 from $1.90 annualized.

NRG holds turbine allocations under a development agreement with GE Vernova and Kiewit, and management says its project pipeline "exceeds the turbine allocations and EPC capacity" under that agreement. Management will hold the reserved turbines rather than resell them: "We're looking to put them to work for long-term contracts."

A 1.2-gigawatt Texas data center project with a hyperscaler has approved agreements but no formal announcement; management expects one by year end. The project is excluded from NRG's long-term financial framework, so it would add to that plan.

The LS Power sale still needs HSR, FERC and New York PSC approvals, and liquidity fell to about $6.0 billion from about $9.6 billion. Shares traded at $97.01, up 9.88 percent Monday after the earnings report but down 38.18 percent year to date.

What does Talen's PJM capacity auction tell us?

Talen Energy (NASDAQ: TLN) is also expanding through existing plants. It closed the Cornerstone acquisition on June 15, 2026, adding about 2.6 GW of gas generation at Waterford, Darby and Lawrenceburg. It then cleared more than 10 GW in PJM's 2028/2029 capacity auction at $325.00/MWd, a price that reflects scarcity on the largest US grid.

Chief executive Mac McFarland summed it up on the November 3 call: "The demand is here, the supply isn't, and we already own the assets the market needs."

Revenue rose 72.3 percent to $1.33 billion, and total generation reached 23.9 TWh versus 11.1 TWh a year earlier. GAAP EPS of $2.88 missed the $7.46 consensus, driven by $190 million of unrealized derivative valuation losses and $148 million of acquisition-related interest. Adjusted EBITDA was $669 million, and 2027 guidance calls for $2.50 billion to $2.85 billion.

McFarland put the all-in cost of new combined-cycle power north of $120 per MWh, which makes Talen's existing fleet a cheaper option for buyers. Talen holds 4 GW of powered-land sites that could connect to the grid in 2028 to 2029. It has not disclosed a new signed data center deal beyond its existing campus contract; McFarland's "They're coming. Trust me," remains a statement of intent without a signed contract.

Leverage is the risk. Long-term debt rose to $9.54 billion from $6.78 billion at year-end 2025. Talen has already sold about $1.5 billion of its future PJM capacity payments, and 2028 output is only about 35 percent hedged. Shares traded at $359.45, up 6.15 percent Monday and down 4.11 percent year to date.

How does Constellation price nuclear against new gas?

Constellation Energy (NASDAQ: CEG) pairs the largest US nuclear fleet with Calpine's gas plants, which generated 38,387 GWh in the third quarter. It is also buying gas capacity secondhand, agreeing to acquire the 609 MW Rhode Island State Energy Center for $715 million.

Management estimates a new combined-cycle plant costs $110 to $130 per megawatt hour, assuming $3,000 per kilowatt in capital costs, and uses that range as the benchmark when pricing nuclear contracts. Revenue rose 32.9 percent to $9.55 billion, and adjusted EPS of $5.06 beat the $3.88 consensus. The nuclear fleet ran at a 97.2 percent capacity factor.

Constellation has signed about 8,500 MW of long-term agreements so far this year, including a 20-year, 690 MW hyperscaler PPA backing more than $3 billion of investment at Calvert Cliffs and a 15-year, 2,700 MW load-following agreement. Management raised and narrowed 2026 adjusted operating earnings guidance to $12.50 to $12.80 per share.

Nuclear uprates are expected to add nearly 1,200 megawatts, mostly between 2029 and 2032, with no new turbine order required. Chief executive Joe Dominguez also pointed to unused capacity on existing plants: "You have a lot of plants just sitting idle on the grid."

Rules for large-load interconnection have not been finalized, and Constellation does not expect regulators to act on co-location until the first half of 2027. Shares traded at $270.06, up 8.05 percent Monday after the earnings report and down 23.21 percent year to date.

Where the shortage leaves the market

The turbine shortage gives pricing power to whoever owns working megawatts or the factory slots to build new ones. GE Vernova benefits from both its order book and decades of services revenue. Vistra, NRG, Talen and Constellation are making money on operating plants because new turbines will not arrive before the 2030 to 2031 delivery window.

Three things to track next: GE Vernova's fourth-quarter slot reservations, NRG's year-end data center announcement, and the December PJM capacity auction, which NRG and Talen both expect to clear at or near the top of its allowed range.