Infrastructure – The data center industry is growing rapidly and creating significant upside for natural gas consumption. East Daley Analytics’ base case projects up to 6 Bcf/d of additional gas demand by 2030 to make electricity for data centers, accounting for 290 projects totaling ~81 GW of new power capacity.
We track data center projects in the new Data Center Demand Monitor, pictured in the image below. In our base case, EDA forecasts 4.2-6.1 Bcf/d of new gas demand. This range is based on existing projects, and the swift pace of new announcements suggests that actual demand could surpass our outlook. An increase of just 15 projects, each averaging 280 MW, would raise our gas demand projections by 5%.
Furthermore, the sector is trending toward onsite gas-fired generation. Data centers are favoring behind-the-grid solutions, often using single-cycle ‘peakers’ with heat rates of 10–11 MMBtu/MWh, compared to the 6.8 MMBtu/MWh heat rate we assume for combined-cycle plants. This shift could lead to a 5% increase in our gas demand estimates for every 10% load moved to less efficient onsite generation.
Natural gas also maintains a cost advantage over renewable energy sources. According to a 2022 study by the Energy Information Administration (EIA), the capacity-weighted average construction cost for natural gas-fired generation was ~$820,000 per MW, while solar and wind projects cost $1.6MM and $1.45MM per MW. Despite advancements in renewables, natural gas remains the most affordable and reliable option for meeting the baseload demands of data centers.
If natural gas captures a larger share of the power load than our current assumption of 40%, demand could increase significantly. For instance, if 50% of new data center power demand is met by natural gas, it would add 1.13 Bcf/d to our projections.
Users can test these sensitivities in the Data Center Demand Monitor, available as part of the Macro Supply & Demand package. This tool gives a bottoms-up approach to quantifying gas demand for data centers. We track and map nearly 300 projects by county across the US to visualize where new demand could materialize. Reach out to East Daley to learn more.
Infrastructure – The Trump administration on February 14 granted its first gas export license to Kimmeridge-backed Commonwealth LNG. The license allows LNG exports to countries without US free trade agreements, the first since the incoming administration lifted a pause on license to non-FTA countries.
The license from the Department of Energy is conditional, likely subject to the Federal Energy Regulatory Commission (FERC) granting a final certificate to the project. That decision from FERC is expected in July 2025. Subject to these, Commonwealth CEO Farhad Ahrabi said the project expects to make a final investment decision (FID) in September 2025 and produce first LNG in 1Q29.
Historically, an LNG project needs at least 80% of its capacity contracted under binding sales and purchase agreements (SPAs) to make FID. Commonwealth LNG still needs nearly 0.6 Bcf/d of new commitments to reach that 80% threshold.
Commonwealth is the first of several projects East Daley expects to make FID this year under the new administration. Other likely candidates are Energy Transfer’s (ET) Lake Charles LNG and Venture Global’s (VG) CP2, both of which still need their non-FTA licenses. ET said on its latest earnings call that it expects to make FID by 4Q25. In December, ET signed a 20-year SPA with Chevron for 2.0 Mtpa at the Lake Charles LNG facility, the first new contract in over two years. Lake Charles LNG needs another 0.46 Bcf/d of commitments and CP2 needs ~0.9 Bcf/d to meet the 80% threshold.
Looking beyond 2030, we expect several other facilities to gain commercial momentum. Woodside’s Louisiana LNG (formerly Tellurian Driftwood) said that it expects to make FID in early 2025. The facility signed an engineering, procurement and construction (EPC) contract with Bechtel in Dec ‘24 but still lacks the offtake agreements to realistically make FID. Cheniere’s Sabine Pass Expansion (~2.7 Bcf/d export capacity) has potentially 40% of its offtake volumes already contracted via Cheniere’s Marketing arm, although the facility still needs its DOE non-FTA export license.
Infrastructure – Waha gas prices are likely to face pressure in the last week of February when Kinder Morgan’s (KMI) El Paso Natural Gas Pipeline (EPNG) conducts maintenance work. EPNG plans to take over 600 MMcf/d of capacity offline at the North Mainline compressor station February 24-26 and over 700 MMcf/d at the Cornudas station February 25-28, according to a schedule posted on the pipeline’s bulletin board.
Major pipeline maintenance events historically have contributed to brief but sharp price declines at the Waha hub, driven by limited egress capacity from the Permian Basin. However, Matterhorn Express is now in service and has expanded Permian takeaway, so maintenance events like these should have less impact on prices going forward.
Storage – Traders and analysts expect the Energy Information Administration (EIA) to report a 181 Bcf storage withdrawal for the week ending February 14. A 181 Bcf withdrawal would be 37 Bcf greater than the 5-year average and would increase the deficit to 148 Bcf. The storage deficit to last year would balloon to 329 Bcf from the current 208 Bcf deficit.
February weather continues to be frigid across much of the Lower 48, a clear deviation from last year’s mild temperatures. The stronger seasonal demand will be reflected in storage withdrawals for the balance of the month. A total of 681 Bcf could be withdrawn in February, leaving storage levels at 1,716 Bcf and in line with our forecast in the Macro Supply & Demand Report. A 681 Bcf withdrawal would be the fourth-largest ever for the month, behind only Feb ‘21, Feb ‘15 and Feb ‘14.
Rigs – The US rig count decreased by 3 for the February 8 week, standing at 542. The Anadarko, ArkLaTex, Permian and Powder River basins all lost 1 rig on the week while the Bakken added 1 rig.
On the midstream side, Targa Resources (TRGP) is down 3 rigs net with losses on its Permian and Eagle Ford systems. ONEOK (OKE) gained 3 rigs total on its Bakken and Anadarko systems.
East Daley’s weekly Rig Activity Tracker monitors rig activity by basin and by gathering and processing (G&P) system to better understand midstream impacts. We allocate rigs and monitor flows through 150+ public and privately owned G&P systems in every North American basin. Reach out for more information on the Rig Activity Tracker.
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