Enterprise Products (EPD) is nearing a make-or-break moment for ATEX (Appalachia-to-Texas), a 1,230-mile ethane pipeline connecting Marcellus and Utica supply to EPD’s ethane distribution system in Mont Belvieu. The pipeline has 190 Mb/d of capacity and typically moves around 160 Mb/d, although flows periodically exceed nameplate capacity, including spikes above 200 Mb/d in 3Q25.
Despite strong utilization, ATEX is approaching a significant commercial test.
On its 2Q26 earnings call, EPD highlighted recontracting risk on ATEX, noting that the tariffs currently in place can exceed the value of the ethane being transported. ATEX transportation rates range from roughly $0.20/gal on the low end to as high as $0.25/gal (see chart).
Mont Belvieu ethane is currently priced near $0.24/gal, meaning the highest ATEX tariffs already exceed the value of the commodity. When ethane prices fell to roughly $0.20/gal in May, essentially the entire tariff range was at or above the value of the ethane being transported. Factoring in the transport costs, that means shippers were effectively receiving no value for their ethane.
EPD management said it is working with customers to determine the “highest use of the pipeline,” suggesting that options beyond the existing ethane service are being evaluated.
The issue is less about current utilization, and more about several legacy transportation contracts signed around the time ATEX entered service in 2014.
East Daley Analytics is aware of four major commercial commitments on the system. The largest is a 75 Mb/d contract originally signed by Chesapeake Energy, now Expand Energy (EXE), that expires in 2028. Antero Resources (AR) holds another 20 Mb/d contract that also expires in 2028. Range Resources (RRC) entered into a 20 Mb/d agreement in 2014. Assuming an original 10-year term, that contract may have already been renewed or could currently be under renegotiation.
Shell (SEL) also holds ~30 Mb/d of ATEX capacity, which provides optionality if operations are disrupted at its Monaca ethane cracker in southwestern Pennsylvania. Assuming that contract began when Monaca entered service in 2022 and carries a 10-year term, it could extend through 2032.
Based on the contracts East Daley can identify, at least 95 Mb/d of firm ethane capacity faces direct recontracting risk in 2028, equivalent to roughly 50% of ATEX nameplate capacity.
A complete conversion away from ethane service, however, appears unlikely.
Energy Transfer (ET) had previously contemplated adding more than 70 Mb/d of incremental ethane export capacity at Marcus Hook around 2027, close to the timing of the ATEX contract expirations. That expansion was later reduced to 20 Mb/d. East Daley believes difficulty securing sufficient firm ethane supply may have contributed to the smaller project. At the same time, a 20 Mb/d expansion could still provide an incremental Northeast outlet potentially supported by producers such as RRC or AR.
Shell’s position provides another reason for ATEX to retain ethane service beyond 2028. The pipeline remains an important source of operational flexibility for Monaca, giving Shell an alternative outlet for ethane supply during cracker disruptions.
EPD’s reference to the “highest use” of ATEX nevertheless raises the question of what else the system could become.
A conversion to natural gas service appears technically possible but economically difficult. ATEX is ~1,230 miles long, meaning pump stations across the system would need to be converted to compressor stations. With a 16-inch pipe, East Daley estimates gas capacity would likely be limited to roughly 300 MMcf/d. Given the significant conversion capital required relative to the resulting capacity, we view a full gas conversion as unlikely.
A broader liquids service could be more plausible. ATEX could potentially provide incremental Gulf Coast egress for other Northeast purity products, such as propane and butane, while retaining some role in ethane transportation. That option would likely require substantially less capital than converting the entire system to natural gas service, although limited purity product storage in the Northeast would make batching and operational flexibility more difficult.
The more likely outcome is therefore not the disappearance of ATEX ethane service, but a commercial reset. With nearly half of the pipeline’s capacity potentially exposed to recontracting in 2028, EPD may need to lower transportation rates, restructure contracts, or find additional liquids services that improve the economics of the system. – Julian Renton, Tickers: AR, EPD, ET, EXE, RRC, SHEL.
Demand is Coming. Where Will the Supply Come from — and Who’s Going to Deliver?
The largest growth cycle in US energy demand is on deck, and the infrastructure required to meet it could reshape US energy markets over the next decade.
LNG infrastructure in the Lower 48 and Mexico could grow by 45 Bcf/d by 2035, while gas-fired power generation serving data centers could add another 7.6 Bcf/d of natural gas demand. More than 32 Bcf/d of major pipeline expansions and newbuild projects have already been proposed to connect growing supply with LNG, power, residential and commercial demand.
And natural gas is only part of the story.
- Midstream consolidation is accelerating as operators position themselves from wellhead to water, including Williams’ move to acquire Momentum.
- Nearly 1,200 Mb/d of Y-grade and purity product expansions are proposed out of the Permian alone, while Mont Belvieu could face more than 1,000 Mb/d of fractionation constraints by 2032.
- A possible ATEX conversion project from liquids to gas could unleash more Northeast supply and reshape NGL flows in the region.
- Permian crude oil takeaway is already running tight, with routes to Corpus Christi at 99% utilization and Cushing/Houston routes at 92%. With only about 75 Mb/d of expansions on the books, takeaway capacity could become a constraint on future Permian growth.
- Roughly $32B per year of infrastructure has been sanctioned and underwritten by long-term contracts through 2031 — representing more than $191B of committed capital over the next five years.
Where are the biggest infrastructure gaps? Which projects get built? And which companies are positioned to capture the opportunity?
Join East Daley Analytics on August 26 at 10:00 AM MT as we connect the dots across natural gas, NGLs, crude oil and capital investment to map the infrastructure buildout ahead. Click here to register now and reserve your spot.
One Market, One Model: Gain a Holistic View of North America Supply & Demand
East Daley Analytics is pleased to announce the Canada Supply & Demand report. The Canada S&D completes our North American model, providing a fully integrated supply and demand forecast for crude oil and natural gas. East Daley follows molecules from Canadian production through US infrastructure to end-markets. Clients now have a continental view to anticipate trends, from how Canadian gas is reshaping Midwest markets, to how crude imports flow to Gulf Coast refiners. The Canada S&D report and dataset is available exclusively in Energy Data Studio. Reach out to learn more about East Daley’s North American energy model.
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