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Commentary Outlook & Notes Market-Relevant Events Infrastructure Supply Chart Pack
TETCO M2 is the benchmark for Appalachian gas and trades at a discount to Henry Hub across the entire forward curve due to the structure of the region. The basin currently produces about 35.5 Bcf/d while consuming 9 Bcf/d, leaving ~25 Bcf/d that has to leave every day, meaning pipeline capacity sets the price. That discount is also seasonal, narrowest in peak winter when local demand competes for the gas and widest in the shoulder months, with Winter '26/'27 at -$0.526 against -$0.825 for Summer '27.
Basis firmed through the first half of the year and peaked in late July, giving back about $0.10 since, though the Winter ‘26/’27 strip still sits in the 92nd percentile of its history. Egress remains the binding constraint, with the Northeast-to-South corridor running at 89% of capacity over the past 30 days. Transco's Southeast Supply Enhancement is the project to watch, since it relieves the Station 165 bottleneck that keeps Mountain Valley Pipeline from flowing full, with partial service as early as 1Q27 and full service targeted for late 2027.
Commentary
October 9: November TETCO M2 basis fell 12.7 cents to -$1.000 over the past week. Texas Eastern cut capacity at Tompkinsville from 1,933 to 1,528 MMcf/d on October 6th following its force majeure declaration, taking roughly 405 MMcf/d off the basin’s main southbound path. December gave up 4.3 cents to -$0.530 while January and February held, so the damage stayed at the front of the curve. November fixed price rose 7.3 cents to $2.168 and December 14.8 cents to $2.965, meaning a firmer Henry Hub masked the widening regional discount.
Appalachian output came off again, averaging 33.80 Bcf/d. The injection pace slipped with it, as a 22 Bcf build for the week ended October 2 took East region storage to 862 Bcf, narrowing the five-year surplus to 18 Bcf, creating a fourth consecutive week of erosion.
October 2: Over the past week, November basis strengthened 8.7 cents to -$0.873 and Dom South 9.5 cents to -$0.895. Mountaineer XPress came back into service on the 29th and MXPSEG is scheduling 1.9 Bcf/d again, returning takeaway that was stranded last week. That said, DT Midstream's force majeure on Stonewall Gas Gathering is still ongoing, capping deliveries into TCO's West Braxton meter near 0.5 Bcf/d since the 23rd, against roughly 1.0 Bcf/d before, keeping that supply out of the market. December added 2.8 cents to -$0.487 while the rest of winter sat still, meaning these disruptions didn’t affect the forward curve. November fixed price fell 31.6 cents to $2.095 and December 35.6 cents to $2.817, with a steep Henry Hub decline swamping the regional gain.
Production eased for a second week, averaging 34.04 Bcf/d, but inventories still increased. A 25 Bcf injection for the week ended September 25 took East region storage to 840 Bcf, though the five-year surplus narrowed again to 23 Bcf, marking a third straight week of erosion.
September 25: Over the past week, October basis fell 26.8 cents to -$1.562 and November 15.7 cents to -$0.960, while the curve beyond held. TCO declared force majeure on Mountaineer XPress Thursday after a leak at the Saunders Creek Regulator Station, cutting the MXPSEG constraint to zero from the September 25 Timely Cycle and stranding 1.8 Bcf/d of takeaway with no restoration date. Fixed price rose against it. October added 11.7 cents to $1.734, with Henry Hub bid on supply the basin can no longer deliver.
Production averaged 34.29 Bcf/d, 1.62 Bcf/d below the prior week, and fell to 32.49 Bcf/d on Friday as West Virginia volumes behind the constraint shut in. Inventories gained less ground. A 20 Bcf build for the week ended September 18 took East region storage to 815 Bcf and trimmed the five-year surplus to 25 Bcf from 30, narrowing for a second week running.
September 18: The curve split this week. Cove Point's annual maintenance this year runs from September 20th to October 10th, removing roughly 850 MMcf/d of regional demand almost entirely inside the October contract. This caused October basis to shed 6.7 cents to -$1.252. Seasonal strips firmed, with Winter '26/'27 gaining 2.2 cents to -$0.468 and Summer '27 2.5 cents to -$0.823.
Production held at 35.82 Bcf/d, essentially flat on the week though 0.77 Bcf/d above the same week last year, while demand climbed 0.93 Bcf/d. Storage turned. The 22 Bcf build for the week ended September 11 fell short of the five-year norm and trimmed the surplus from 32 Bcf to 30, its first step back in five weeks.
September 11: After moving lower for three consecutive weeks, October TETCO M2 basis has remained relatively flat since the last update, shedding only 3.0 cents. The seasonal strips gave up between 1.5 and 2.8 cents. Fixed price fell far harder, with October down 11.0 cents to $1.654 and Winter '26/'27 down 11.8 cents to $2.851, resulting from a steep decline in Henry Hub pricing.
Production slipped to 35.52 Bcf/d, 0.43 Bcf/d below the week ending August 27, though still 0.50 Bcf/d ahead of the same window a year ago. Rigs came off with it, down one each to 23 in the Marcellus and 10 in the Utica. Inventories kept filling. Builds of 26 and 20 Bcf took East region storage to 773 Bcf for the week ended September 4, widening the five-year surplus to 32 Bcf from 26.
August 28: Heading into expiration, September TETCO M2 basis weakened at the front for a third straight week. September settled 11.3 cents lower at -$1.250. Fixed price pushed higher at the same time, with prompt M2 adding 2.2 cents to $1.657, leading to the discount to Henry Hub widening for the second week in a row. Summer '27 was the only seasonal strip to give ground, easing 3.2 cents to -$0.820. The pressure came from the demand side, with Appalachian demand down 1.24 Bcf/d week over week and Northeast power burn off 7.6%.
Production pulled back to 35.91 Bcf/d, 0.28 Bcf/d below the prior week but still 0.47 Bcf/d ahead of the same week last year. Storage moved against that. The EIA reported East region inventories of 727 Bcf for the week ended August 21, a 19 Bcf build that pushed the surplus to the five-year average to 26 Bcf.
August 21: Prompt TETCO M2 basis sold off hard this week. September settled 16.3 cents lower at -$1.113, while October gave up 10.8 cents to -$1.120. Fixed price fell by nearly the same amount at the front, with prompt M2 off 16.2 cents to $1.621, meaning the whole of the front-month decline came out of basis. This was driven by a combination of flat production and ~1Bcf/d lower demand in New England.
Basin production came in at 36.10 Bcf/d, just 0.06 Bcf/d week over week, though volumes still run 0.66 Bcf/d above the same week a year ago. The storage side was just as quiet. Thursday's EIA print landed at 708 Bcf for the East region for the week ended August 14, a 15 Bcf build that holds the surplus to the five-year average at 25 Bcf for a second straight week.
August 14: The front of the TETCO M2 curve gave ground this week while the seasonal strips barely moved. Prompt September basis settled at -$0.955 on August 13, 7.8 cents softer than the -$0.877 mark on August 7. October traveled with it, sliding 7.0 cents to -$1.028 and pulling the balance of summer to -$0.991. Fixed price tells a different story. Prompt M2 shed only 1.2 cents to $1.772 and the Winter '26/'27 strip 2.5 cents to $2.971, pointing to a widening regional discount against Henry Hub.
Appalachian production climbed back to 35.96 Bcf/d on a weekly average, up 0.22 Bcf/d from the week ending August 7 and undoing the prior week's dip, with volumes now sitting 0.70 Bcf/d above the same week a year ago. Storage leans the same way. Thursday's EIA report showed East region inventories at 693 Bcf for the week ended August 7, a 15 Bcf build that keeps the region 25 Bcf above its five-year average and holds the surplus right where it stood a week ago.
August 7: TETCO M2 basis strengthened in the front of the curve this week, while the upcoming seasonal strips remained relatively unchanged. Prompt September basis settled at -$0.900 on August 6, up 5.3 cents from -$0.9525 on July 31. October followed suit, gaining 5.3 cents to -$0.9625, putting the balance of summer at -$0.931. Past October the curve went quiet, with Winter ‘26/’27, Summer ‘27 and Winter ‘27/’28 strengthening by a penny. Fixed price went the other way, and by more than basis gained. Prompt M2 fell 5.5 cents to $1.740 and the Winter 26/27 strip dropped 12.6 cents to $2.942 due to Henry Hub weakening.
Appalachian production averaged 35.66 Bcf/d over the past week, down 0.32 Bcf/d from the week ending July 31 and the softest stretch since mid-June. Conversely, Thursday's EIA report put East region storage at 678 Bcf for the week ended July 31, a 24 Bcf build that leaves the region 25 Bcf above its five-year average. This surplus showed up in late June after storage entered injection season at a five-year low under 300 Bcf.
August 3, 2026: The Sep26 TETCO M2 basis contract has slightly weakened over the past two weeks after trading at an all-time high of -$0.90 (currently printing -$0.95). Seasonal strips have followed suit, with Summer ’27 being the outlier, which has remained unchanged. Dry gas production sits at 35.5 Bcf/d (in line with this time last year), while storage sits at 654 Bcf (15 Bcf above the five-year average).
July 20, 2026: TETCO M2 Basis Winter ‘26/’27 and Winter ‘27/’28 prices are trading around 15c higher than they were in May. Summer ’27 came off slightly but is still elevated nearly 10c since May. Basis prices have held up relative to Henry Hub over the past month. Northeast storage started the injection season at a 5-year low, sitting below 300 Bcf. However, due to strong Appalachian production and mostly mild weather, Northeast storage has now surpassed the 5-year average.
July 10, 2026: Over the past month, each of the Winter ‘26/’27, Summer ’27, and Winter ‘27/’28 seasonal strips have strengthened to all-time highs. This strength in basis pricing is not isolated to Appalachia, as basis pricing around the country has been on the run. These seasonal strips are trading at all-time highs in many locations around the country, with the weakening in Henry Hub prices being a driving factor. Northeast storage is in line with 5-year average, with dry gas production is within .5 Bcf/d of this time last year.
TETCO M2 Basis Outlook and Notes
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Winter '26/'27
We hold a bullish view on NYMEX prices for this period due to LNG demand growth. Typically, there is an inverse correlation between Henry Hub prices and Northeast basis, which could lead to potential weakening of M2 and Dom South pricing
Specific to Appalachia; any additional production growth during this period could push limits of pipeline egress, possibly weakening basis differentials, similar to Winter ‘25/’26
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Summer '27
With Transco’s Southeast Supply Enhancement project scheduled to be in-service early, we should see some alleviation to the constraints of Appalachia gas flowing south, which could lead to stronger basis prices during peak demand months - assuming production doesn't quickly grow into the new capacity
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Winter '27/'28
Winter '27/'28 should be the first season with both of Transco's expansions in service. Southeast Supply Enhancement relieves southbound flow into the Southeast and Northeast Supply Enhancement adds deliverability into New York and New Jersey, both targeted for the fourth quarter of 2027
That said, the forward market prices this winter at a wider discount than Winter '26/'27, implying producers are expected to fill the new capacity about as fast as it arrives
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For more discussion on basis price moves and the current forward curves:
For more discussion and charts, jump to our outlook and chart pack. Remember, the local market is influenced by the broader gas market. Consult our Gas Macro Outlook for more.
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Recent Market-Relevant Events
6.26.2026
MVP Southgate Receives FERC Approval
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6.12.2026
Transco Southeast Supply Project Poised to Come Online Early
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5.20.2026
Enbridge Launches Open Season for Project Beacon Expansion on Algonquin
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The Appalachian Basin has suffered from a lack of pipeline egress capacity in the past several years as pipeline projects were delayed by permitting issues and court proceedings. After multiple years of delays, the Mountain Valley Pipeline finally entered service in 2024 after a Congressional deal. Downstream constraints on the Transcontinental pipeline materialized during MVPs construction, preventing the 2 Bcf/d pipe from flowing at full capacity, but help is on the way. Expansions on Transco will work to increase pipeline takeaway capacity and are currently underway. The Transco Southeast Supply Enhancement (SESE), which adds 1.6 Bcf/d in egress capacity from the Northeast, is poised to be in-service early (Late ’26 – Early ’27). Additionally, their Northeast Supply Enhancement (NESE) project broke ground in April 2026. This expansion is projected to add 0.4 Bcf/day in capacity, designed to better supply New York City and Long Island during peak winter demand.
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For a discussion of production outlook:
Below are the most market-relevant infrastructure projects that appear to be funded and going forward. The projects that offer intra-region capacity (egress) are also shown in the chart above.
Note: Deeper discussion included below the map.
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Major Pipeline Exits From Appalachian Basin
Gas Pipeline Flows
Gas Pipeline Projects
Transco Southeast Supply Enhancement (FID)
In-service date: Early 2027
Capacity: 1.6 Bcf/d
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Source: Williams
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| Transco Southeast Supply Enhancement (SESE) - Transco’s SESE project began construction on March 2, 2026. The additional capacity created by this expansion, which includes 55 miles of 42-inch diameter pipeline, will help ease constraints on the mainline from Station 165, increasing takeaway capacity from Appalachia to the south. While compression projects are still scheduled to be completed by 3Q27, there is belief that additional capacity could come online in early 2027. |
Transco Northeast Supply Enhancement (FID)
In-service date: November 2027
Capacity: 0.4 Bcf/d
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Source: Williams
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| Transco Northeast Supply Enhancement - Transco's NESE project began construction on April 14, 2026. The enhancement, which includes 37 miles of pipeline across Pennsylvania, New Jersey, and New York, aims to quell natural gas price spikes during peak demand months. It is expected to be in-service by November 2027. |
Mountain Valley Pipeline Southgate
In-service date: mid-2028
Capacity: 0.50 Bcf/d
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Source: MVP
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| Mountain Valley Pipeline Southgate - The MVP Southgate extension initially proposed in 2018, abandoned, and now resurrected is a proposed project to connect MVP to demand centers in the Mid-Atlantic region. The line would extend 31 miles from the MVP terminus in Virginia to delivery points in Rockingham and Alamance Counties, North Carolina. Construction began in March24, 2026 and is expected to be completed in 2028. |
Constitution Pipeline
In-service date: 4Q 2028
Capacity: 0.65 Bcf/d
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Source: Williams
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| Constitution Pipeline - Proposed 124-mile pipeline connecting New York and Pennsylvania. In conjunction with the Wright Interconnect Project, the pipeline could transport 650+ MMcf/d from Susquehanna County, PA to markets in New York and New England. |
Other Projects
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Transco Expansions - Numerous smaller expansions to the Transcontinental pipeline are planned for the next few years through 2028. While many of these projects are in the Southeast US, they will help alleviate downstream constraints, allowing for additional Appalachian production to flow, especially on the recently started Mountain Valley Pipeline. Specifically, the Southeast Supply Enhancement was granted permission to begin construction in late February. The project will add 1.59 Bcf/d in additional capacity, and is expected to begin construction this year, with anticipated completion in late 2027.
MVP Expansion - EQT is advancing two major expansions of the Mountain Valley Pipeline, totaling 1.05 Bcf/d of new takeaway for Appalachian natural gas. The MVP Boost expansion is expected to increase capacity on the pipeline to 2.5 Bcf/d with an in-service date of 2028. EQT is also advancing the MVP Southgate Project, which would add another 550 MMcf/d to the system by 2028.
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Local Supply
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Production growth should remain limited in the next few years. The Appalachian basin has long been constrained by a lack of pipeline egress, with this likely continuing into the future. As expansions on Transco are completed, Mountain Valley Pipeline can flow at full capacity, with this new capacity likely being filled by production relatively quickly. Output in the region has remained relatively stable year over year, with total supply ranging from 34.7 - 36.2 Bcf/d. This output can flex during times of higher demand, such as peak winter months when increased consumption allows for higher pipeline egress, while the yearly Cove Point LNG maintenance often coincides with a drop in production.
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Operator Guidance
EQT (Q2 2026 EC)
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07/22/2026
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2026 Gudiance:
Full-year 2026 sales volume guidance raised by roughly 90 Bcfe to 2,375–2,450 Bcfe on stronger well performance and system pressure optimization
Q2 2026 sales volume of 634 Bcfe beat the high end of guidance, helped by lower-than-expected price-related curtailments
Q3 2026 sales volume guided to 570–620 Bcfe
Full-year 2026 realized price differential guidance of $(0.55)–$(0.35) per Mcf
Strategic & Infrastructure Highlights:
MVP Southgate has secured all key regulatory approvals, with capital accelerated to complete construction by year-end 2026
New 10-year agreement to supply 325,000 Dth/d to a Competitive Power Ventures gas-fired power project in West Virginia
New five-year, 0.5 MTPA LNG offtake agreement with an Asian integrated energy company beginning in 2028
Compression and system-pressure investment cited as the driver of shallower base declines across the Appalachian system
Presentation's M2 basis forward chart shows the 2027–2030 average Appalachian differential tightening materially from current levels
Drilling & Basin Activity
Full-year 2026 plan of 100–120 net wells spud on 2–3 horizontal rigs, 2–3 top-hole rigs, and 2–3 frac crews
Q3 2026 guidance of 34–50 net wells turned in line
Q2 realized differential of $(0.67) per Mcf came in favorable to guidance despite wider basis, credited to marketing and curtailment timing
Hedging Activity
Hedged volumes of 125 MMDth for Q3 2026, 108 MMDth for Q4 2026, and 62 MMDth for Q1 2027, not a significant portion of their production
EQT discloses absolute hedged volumes only — no percent-of-production hedged figure was published this quarter
Analyst Q&A Takeaways
45+ Appalachian demand and takeaway projects under construction or evaluation totalling nearly 20 Bcf/d of potential incremental demand; roughly 30 further compression opportunities identified beyond the six underway.
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Expand Energy (Q2 2026 EC)
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07/29/2026
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2026 Guidance:
Full-year 2026 Northeast Appalachia guided to roughly 2,680 MMcfe/d, a modest step up from the Q2 rate
Full-year 2026 Southwest Appalachia guided to roughly 1,660 MMcfe/d, essentially flat to Q2
Full-year 2026 Southwest Appalachia guided to roughly 1,660 MMcfe/d, essentially flat to Q2
Q2 2026 Southwest Appalachia gas production of 1,084 MMcf/d at $2.47 per Mcf, plus 14 MBbl/d of oil and 83 MBbl/d of NGLs
Strategic & Infrastructure Highlights
Q2 basis deduct to NYMEX was $(0.75) per Mcf in Northeast Appalachia and $(0.43) in Southwest Appalachia — the widest of Expand's three areas
Twin Eagle acquisition adds 44 Bcf of storage, 49 Bcf pro forma, plus firm-transport-linked marketing reach into premium hubs
Structural demand outlook of 4–6 Bcf/d of incremental power-sector demand by 2030 across Appalachia and the Gulf Coast, rising to 7–10 Bcf/d by 2040
Southwest Appalachia's liquids mix differentiates its price exposure from dry-gas Northeast Appalachia
Drilling & Basin Activity
The Q4 2026 company production ramp above 7.6 Bcfe/d is concentrated in the Appalachia business units
Management expects winter demand to tighten Appalachian basis into that ramp
Operational techniques carried over from the Haynesville-anchored integration credited for Southwest Appalachia's improvement
Hedging Activity
66% of 2026 gas production hedged and 41% of 2027 hedged, company-wide
No basin-level hedge split is disclosed, so Appalachian coverage tracks the company book
Analyst Q&A Takeaways
Management said it has "more appetite" to grow Appalachian volumes into contracted demand now that Twin Eagle's origination platform is in-house
Expand has not historically tied its volume growth to signed utility or data-center contracts, unlike some Northeast peers
Asked about a peer's utility and data-center supply deals, management said it will "absolutely look for deals there as well"
Broader gas market seen modestly oversupplied through at least the first half of 2027 given roughly 3.5 Bcf/d of incoming Permian egress
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CNX Resources (Q2 2026 EC)
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07/30/2026
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2026 Guidance
Full-year 2026 production guidance maintained at 605–620 Bcfe
Full-year 2026 natural gas differential guidance of $(0.59) to $(0.64) per MMBtu on open volumes
Q2 2026 total volumes of 151.5 Bcfe, including 126.5 Bcf of shale gas and 9.7 Bcf of CBM
Strategic & Infrastructure Highlights
Pennsylvania environmental-attribute pricing assumed flat and marked to ICE trades, with management acknowledging the market can be volatile
No LNG, in-basin power, or data-center demand commitment was disclosed this quarter — a notable contrast with EQT
Utica wells characterized as performing to guidance and top tier in the basin, supporting the play as longer-term inventory
Drilling & Basin Activity
Q2 activity: 2 CPA Utica wells drilled, 6 SWPA Marcellus wells fracked, and 5 SWPA Marcellus wells turned in line
Full-year 2026 plan of 34 TILs — 24 SWPA Marcellus, 3 CPA Marcellus, and 7 deep Utica wells
Maintenance-level activity of roughly 1.5 rigs and a partial-year frac crew for the full year
Management expects quarterly volumes to be highest in Q4 2026
Hedging Activity
81% of 2026 natural gas production hedged — 460.5 Bcf at an average $2.73 per Mcf including basis
400.4 Bcf hedged for 2027 at an average $3.31 per Mcf; no 2027 percentage disclosed
Heavy hedge coverage relative to peers means CNX volumes are largely insensitive to near-term price weakness
Analyst Q&A Takeaways
A 12–13 well Marcellus pad online in Q3 2026 and a Utica pad in Q4; management describing 2026 into 2027 as "a little bit soft" against a "tremendous" longer-term Appalachian outlook
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Local Demand
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The Appalachian basin is located in close proximity to Northeast US demand centers, with the Northeast being one of the largest gas-consuming regions in the country during the winter months. Due to this dynamic, demand in Appalachia can fluctuate heavily between the winter and summer seasons. Specifically, demand averaged 12.27 Bcf/day throughout Winter ‘25/’26, while only averaging 7.87 Bcf/day throughout Summer ’25.
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Coal-to-Gas Switching: The Appalachia region still utilizes a significant amount of coal in its power sector, specifically in Pennsylvania and West Virginia. Among all the US balancing authorities, PJM has the second-largest operating coal fleet, after its neighbor MISO. When gas prices rise, more coal generation can be called up, helping to balance the market.
Coal Retirements: Out of PJM's nearly 39 GW of coal generation capacity, about 5.1 GW is scheduled to retire over the next three years. This should reduce coal-to-gas switching capability and support gas demand.
Renewables: According to the EIA, PJM plans to install about 17.6 GW of renewables by the end of 2029. While the actual generating capacity is likely to be about one-third of the nameplate capacity, the continued expansion of renewables threatens to erode natural gas's market share.
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Data Centers and Electrification: The rise of data centers and electrification of oilfield operations (e.g., electric drilling rigs) also adds to power demand. The Northern Virginia region is currently the largest market for data centers, and power demand will likely increase over the next several years. This could support regional power demand and, thus, natural gas prices.
LNG: The Cove Point LNG export plant in Maryland is the only LNG export facility in the Northeast. The relatively small 0.9 Bcf/d facility typically shuts down for maintenance for about a month every Fall, coinciding with a weakening of Northeast cash prices and a decline in production as pipeline egress capacity tightens due to the drop in demand.
Environmental Concerns: There is often opposition to pipeline projects and energy infrastructure in the region from Environmental groups. This opposition contributed to the multi-year delay in Mountain Valley Pipeline.
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In this area, there are multiple basis locations affected by similar market conditions. Many AEGIS customers hedge Eastern Gas South Basis, formerly known as Dominion South.
The reader will notice that Eastern Gas South and Tetco M2 have very similar forward curves. AEGIS notes that historically the Tetco pipeline has had many more instances of emergency outages that have caused cash-price discrepancies between M2 and other nearby prices.
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Recent Market-Relevant events
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MVP Southgate Receives FERC Approval
(June 26, 2026)
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Market Impact: This expansion aims to relieve Appalachian basis pressure by opening access to higher-priced Southeast markets
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Expansion adds 500 MMcf/d of takeaway capacity from Appalachia to the Southeast via 31 miles of 30-inch diameter pipe
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Targeted in-service date of 2028
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MVP is also advancing their MVP Boost project, which would add an additional 500 MMcf/d to it’s mainline system via added compression by 2028
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Transco Southeast Supply Project Poised to Come Online Early
(June 12, 2026)
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Market Impact: The updated in-service date could help ease constraints from Appalachia to the Southeast earlier than anticipated. This is bullish for basis pricing in the peak demand months of Summer ’27, and could be completed in time to alleviate late Winter ‘26/’27 prices
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Project could come in-service as early as late 2026 or early 2027
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Compression projects still targeted for 3Q27
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The Southeast Supply Enhancement (SSE) will add 1.6 Bcf/d in capacity via 55 miles of 42-inch diameter pipeline
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Enbridge Launches Open Season for Project Beacon Expansion on Algonquin
(May 20, 2026)
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Market Impact: This expansion, which includes an optional pipeline-and-storage offering, will alleviate west-end constraints. These constraints, combined with sustained New England basis prices, have strengthened the case for additional pipeline capacity
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Expansion could add 300 MMcf/d of capacity to AGT, representing a 10% increase
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Would provide firm transportation from Ramapo receipt point at the Millenium Pipeline interconnect
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Project aims to replace Enbridge’s Project Maple, which never reached FID
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Federal Regulators Reopen Review of Constitution Pipeline
(April 16, 2026)
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Market Impact: The potential restart of the Constitution Pipeline would meaningfully ease continual natural gas supply constraints across the Northeast and New England, regions that have historically faced price spikes and fuel switching during peak demand periods. This would help to strengthen Appalachia basis pricing during these periods
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Williams is targeting FERC certificate reinstatement by Q3 2026, with an in-service date of Q4 2027, contingent on finalizing commercial agreements with Northeastern states
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The 30-inch diameter pipeline is ~125 miles long, running from Susquehanna County, PA to Schoharie County, NY and is expected to add 650 MMcf/d of new capacity
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The project connects to both the Iroquois Gas Transmission and Tennessee Gas Pipeline systems, expanding Marcellus Shale gas access into constrained Northeast markets
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Williams Breaks Ground on NESE, Aims to Ease New York Natural Gas Spikes
(April 15, 2026)
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Market Impact: This expansion will help alleviate constraints along the Transco pipeline from Pennsylvania to New York. The end goal is to reduce natural gas prices in New York, which can surge during periods of high demand
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The project will add 400 MMcf/d of new capacity
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Williams CEO, Chad Zamarin, said New York prices can be triple the national average, reaching as high as 10 times the national average during peak winter demand
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The project is scheduled to enter service in late 2027
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Transco Gets FERC Green Light to Build 1.6 Bcf/d Southeast Natural Gas Supply Expansion
(February 26, 2026)
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Market Impact: The additional capacity created by this expansion will help ease constraints on the mainline from Station 165. This will increase takeaway capacity from Appalachia to the south. Limited spare takeaway capacity from Appalachia to the south has been an issue for some time, as highlighted by the startup of the Mountain Valley Pipeline
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Federal regulators gave the go-ahead for Transco to begin construction
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The Southeast Supply Enhancement (SSE) will add 1.6 Bcf/d in capacity via 55 miles of 42-inch diameter pipeline
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Enhancement will help alleviate bottlenecks south of St. 165 in Virginia
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The project is scheduled to be in service in 3Q27
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Tioga Pathway Gets Final Permits
(December 1, 2025)
National Fuel Gas has received the final permits needed for the Tioga Pathway project
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The project will add 190 MMcf/d of new capacity in Pennsylvania
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All new capacity has been leased by National Fuel's E&P unit, Seneca Resources
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The project should enter service in November 2026
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EQT Advances Over 1 Bcf/d in MVP Expansions for Appalachian Natural Gas
(July 24, 2025)
EQT is advancing two major expansions of the Mountain Valley Pipeline (MVP), totaling 1.05 Bcf/d of new takeaway for Appalachian natural gas
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MVP Boost: +500 MMcf/d by 2028 via 180,000 hp compression addition
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MVP Southgate: +550 MMcf/d by 2029, serving Carolinas utilities
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The expansions aim to relieve Appalachian basis pressure by opening access to higher-priced Southeast markets
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New regional gas demand (e.g., AI campuses, data centers) allows EQT to sell more gas at local premium prices without competing for Gulf Coast pipe space
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EQT Secures Major Gas Deals to Supply 4.4 GW AI Campus and 1 GW Data Center in Pennsylvania
(July 16, 2025)
EQT Corp. signed two major gas supply agreements, including one with Homer City Redevelopment (HCR) to fuel a 4.4 GW gas-fired AI computing campus in Homer City, PA, slated to begin operations in 2027
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EQT will supply up to 665,000 MMBtu/d (~.6 Bcf/d) to HCR, potentially making it one of the 40 largest U.S. gas purchasers and one of the largest single-site gas supply agreements in North American history
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EQT also struck a separate agreement with Frontier Group of Companies to supply the planned 1+ GW Shipping port Power Station at the former Bruce Mansfield site in Beaver County, PA, which includes a co-located data center and up to 800 MMcf/d of demand
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