In the spring of 2023, the Texas Energy Fund seemed poised to deliver on its mission of jump-starting the construction of new fossil gas power plants. As the state’s answer to blackouts during Winter Storm Uri a few years prior, legislators funneled up to $9 billion via low-interest loans and grants, in a move supporters said was necessary to improve grid reliability and meet growing demand.
The idea of the TEF caters to the unique characteristics of ERCOT, which doesn’t have a capacity market, and instead uses scarcity pricing and a price cap to help projects get paid above and beyond the cost of building. That setup can mean that revenue is unstable, which deters investment in costly new plants. State intervention via the TEF, the theory goes, would spur new generation by offering financing that might otherwise be scarce.
Initially, the proposal appeared to be paying off. By the summer of 2024 the fund had received more than 70 loan applications representing over 38 gigawatts of dispatchable power generation across ERCOT. In August of last year the Public Utility Commission of Texas announced its selection of 17 projects — totaling 9.7 GW and seeking $5.38 billion in loan requests — to move into due diligence.
At the beginning of 2025, the AI-induced energy crunch was in full swing — and it was getting harder to build a new gas project. Even with state financing via TEF, getting a project ready to take on debt is onerous and time consuming, requiring land with access to gas pipelines, a willing host community, transmission and interconnection studies, and of course, equipment.
By January, the TEF project withdrawals had started. Project economics and timelines started to unravel, thanks in large part to a data center-fueled run on turbines — which have jumped in price, and are slated to keep getting more expensive and more scarce in the next five years. Ironically, many of the gas plants in the TEF financing pipeline are slated to supply massive data center campuses popping up around the state.
As of early November, at least eight projects — representing around 35% of the capacity originally proposed through the TEF loan program — have now withdrawn from the pipeline.
A wave of withdrawals
In January, the first project, a Corpus Christi plant to be developed by Howard Energy Partners, notified the PUC of its decision not to pursue a finalized loan. Then, in February, Engie pulled two more projects from the running, citing equipment constraints. March saw independent power producer WattBridge pull four projects from the queue, followed closely by Constellation Energy; the latter cited permitting delays and local opposition.
Each project experienced slightly different challenges, but taken together it’s clear that the math for many TEF loans just didn’t add up — despite the improved financing terms — given the market realities in Texas right now.
Meanwhile, five projects have officially finalized loans under the program to date. The latest (and largest) loan, for a 1,350 MW plant developed by Competitive Power Ventures, was finalized in early November. That project will receive a 20-year loan of $1.12 billion, 60% of the total project cost, at a 3% interest rate through late 2045.
That project, though, isn’t exactly net new generation spurred by the TEF. It first entered active development in the ERCOT interconnection queue in August 2020. Its estimated completion date at that time was the same as with the Fund’s help — 2028. And it’s not the only one: Calpine’s 460 MW plant Fairfield, Texas, which finalized a $278.3 million loan via TEF in mid-October, started construction in early 2023.
In fact, according to Brent Nelson, managing director of markets and strategy at Ascend Analytics, most of the projects that have been approved so far were in development as far back as 2020.
That means, Nelson explained, that the approved funding from TEF hasn’t gone toward any new development, “it just created cheap loans for projects that were already being developed.” That’s not to say that the fund isn’t having an impact; it may be key in ensuring those projects get over the finish line. “If you provide financing to a project that was in development, it helps ensure that project gets built,” he added. “But to say that it’s [supporting] new development just isn’t true.”
Nelson pointed to a $526 million loan granted in September to NRG Energy, the third loan finalized under the fund, as an example. The cost of that plant is around $800 per kilowatt, compared to the nearly $2,500 per kw of most projects today. NRG was able to do that, Nelson explained, because that project started the interconnection process in 2022, and already had turbines on site and ready to go. (NRG has since requested an extension for a third loan in the TEF pipeline, which isn’t yet finalized, citing “an abundance of caution.”)
The math isn’t working
NRG isn’t alone in its timeline concerns. There are around 15 projects still in the queue that have been selected for funding but haven’t finalized their loans, totaling more than 5.8 GW of capacity. By early November, at least a dozen of the pending projects had requested extra time.
Their filings with the PUC cite the growing demand for gas turbines driven by data center availability and pricing, further complicating procurement and construction schedules. The requested extensions range from March 31, 2026 (the third NRG project) to December 31, 2027 (two projects managed by Nightpeak Energy).
Nightpeak, for its part, cited difficulties procuring turbines and “alignment of offtake commitments with the extended turbine procurement period.” Other projects pointed to yet more complications: Raburn Electric Cooperative, which is seeking an extension to next summer, pointed to problems with EPC availability, environmental permitting, and electrical interconnection timing.
Invenergy, which is seeking to push its deadline to the end of 2026, also cited inflation and tariffs, in addition to supply chain challenges. And private equity firm Rockland Capital, which manages funds that own the 340 MW New Gulf Project, is seeking a delay to September 2026.
“ERCOT market forwards have not kept up with rising costs, and as such do not support near-to-medium energy hedgings at values that allow Rockland Capital…to make a final investment decision,” the firm said in its PUC filing. The New Gulf team has been working to make the project more financially stable, Rockland added, by finding a long-term buyer in the form of a utility or large industrial user. As of the November 7 filing, however, that effort has been unsuccessful.
The nine month extension, the filing added, should allow time for one of two things to happen: either market prices rise enough to make the project profitable, or the project secures a long-term contract with a reliable buyer — likely a data center.
