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Commentary Outlook & Notes Market-Relevant Events Infrastructure Supply Chart Pack
Northeast basis locations, such as TETCO M2, have moved lower as winter concludes. The prompt month TETCO M2 contract briefly traded above Henry Hub during winter storm Fern, but has since traded lower. Prices for the next few seasons have been mostly unchanged over this period. Interestingly, prices for the next few seasons have slightly strengthened over this period. With egress capacity not expected to meaningfully increase until 2028, we could see downward pressure on Northeast basis pricing.
Commentary
May 8, 2026: While prompt Appalachia basis prices remain stable, seasonal strips have weakened over the past week and a half. Summer ’26 is down 8c and Winter ‘26/’27 is lower by $0.01, while Summer ’27 is down $0.04. Notably, Summer ’26 and Winter ‘26/’27 TETCO M2 – Transco Z4 basis spreads have widened by $0.18 and $0.12, respectively.
April 24, 2026: Prompt Appalachia basis prices remained stable throughout the week. However, seasonal strips have strengthened throughout April, with Summer ’26 and Winter ’26 strengthening $0.08 and $0.06 respectively. This is in stark contrast to other regions of the country, where basis differentials have weakened substantially.
April 17, 2026: Over the past week, TETCO M2 prompt basis has only strengthened by ~$0.05 to $0.79 despite a cold snap forecasted for the weekend, which could cause average temperatures in the region to plummet by ~20 degrees. Seasonal strips have remained relatively unchanged as well. EIA East region storage is currently at a 33 Bcf deficit to the five-year average, but with injection season on the horizon, this deficit should shrink. With no planned maintenance in the near term, Northeast regional basis prices should remain stable, excluding any unforeseen outages/weather events.
April 10, 2026: Prompt M2 and seasonal strip prices have remained relatively stable given the recent volatility in natural gas. There have been no major changes to storage or production, although production is ~.5 Bcf/day lower than this time last year. This stability has translated to Dom South pricing as well, where we have seen seasonal strips strengthen by a few pennies over the past two weeks.
March 27, 2026: While prompt M2 basis prices have continued lower, falling to -$0.87/MMBtu following seasonal trends, the later parts of the curve have remained stable or moved higher, especially the next two winter seasons. Winter '27/'28 TETCO M2 basis recently reached -$0.58/MMBtu, near a one-year high. EIA East region storage remains below the five-year average, with the storage injection season beginning very soon.
March 20, 2026: After reaching an all-time high of $0.05 on January 26th, TETCO M2 basis prices have weakened substantially, correcting to levels we saw this time last year. Most of this price action has been seen in the prompt month, as seasonal strips have remained relatively unchanged. Dry gas production increased off the back of Winter Storm Fern and held steady throughout February when blizzards from Winter Storm Hernando ravaged the Northeast. Production currently sits at 35.87 Bcf/d, in line with levels from last year. Heading into summer, demand has reverted to historical averages, which, in conjunction with normalized production, has historically lead to weaker pricing.
March 11, 2026: Following winter storm Fern and the conclusion of peak winter, fundamentals in the northeast have normalized. Gas production has returned to levels of about 35-36 Bcf/d, and demand has fallen in-line with seasonal averages. However, gas storage for the EIA East region remains near a seasonally adjusted five-year low. Despite lower storage, TETCO M2 and Dom South prices for the next few seasons have been mostly unchanged in recent weeks, but they remain near one-year highs.
January 27, 2026: Prompt TETCO M2 prices trended higher throughout December and the first half of January, but remained within historical norms. Prices surged to the highest level in years on January 26, with Northeast basis markets trading at a premium to Henry Hub, a rarely seen event. Spot markets have jumped to near record levels, with TETCO M2 spot trading at more than $50/MMbtu on the 26th, according to data from Bloomberg. This was due to incredibly strong demand and reduced supply during Winter Storm Fern. Total consumption in the Northeast climbed to a high of 43 Bcf/d, while production fell to 34 Bcf/d. The Northeast is more insulated to the impacts of freeze-offs due to winterization, but dry gas production has fallen about 2.5 Bcf/d to 34 Bcf/d. While the remainder of the Winter '25/'26 strip has rallied significantly, this is primarily a real time event and the back of the curve has not changed much. However, this will draw down storage in the East region, lending some support to gas prices going forward.
TETCO M2 Basis Outlook and Notes
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Summer '26
Egress capacity is not anticipated to increase by a material amount until 2028
Historically, shoulder months can be weaker due to the combination of lower demand and increased maintenance
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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 pipline egress, possibly weakening basis differentials, similar to Winter ‘25/’26
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Summer '27
Expect similar dynamics to Summer ’26. There are limited pipeline projects coming into service until late 2027 with Transco’s Northeast Supply Expansion project
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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
12.1.2025
Tioga Pathway gets final permitsd
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7.24.2025
EQT advancing over 1 Bcf/d in MVP expansion
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7.16.2025
EQT secures deal to supply 4.4 GW in Pennsylvania
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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. Expansions on Transco will work to increase pipeline takeaway capacity and are currently underway, with the Northeast Supply Enhancement (NESE) project receving approval and permits in late 2025. 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
Borealis Pipeline Project
In-service date: TBA
Capacity: 2 Bcf/d
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Source: S&P, AEGIS
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| TGT Borealis Project—On April 1, 2025, Boardwalk Pipelines announced a new Texas Gas Transmission pipeline expansion. The project involves a 2 Bcf/d greenfield line running from existing infrastructure in Lebanon, Ohio, to Clarington in eastern Ohio. No timeline has been given yet, but it's estimated that the line should enter service by the end of the decade. The project should result in higher productive capacity in the Marcellus and Utica. |
Mountain Valley Pipeline
In-service date: 2Q 2024
Capacity: 2.0 Bcf/d
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Source: Equitrans
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Mountain Valley Pipeline - MVP began flowing gas in June 2024, with a capacity of up to 2 Bcf/d. The pipeline ships gas from Equitrans' transmission and storage system in Wetzel County, West Virginia to Transco Station 165 in Pittsylvania County, Virginia.
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Regional Energy Access
In-service date: 4Q 2024
Capacity: 0.83 Bcf/d
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Source: Williams
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Regional Energy Access - Williams developed the Regional Energy Access project to enhance gas supply in the Northeast region. The project involves increasing compression, which should allow for an additional 829 MMcf/d to be shipped to New Jersey from Pennsylvania on the existing Transco pipeline. Opposition to the project is continuing in court despite the expansion already being placed into service.
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Mountain Valley Pipeline Southgate
In-service date: mid-2028
Capacity: 0.55 Bcf/d
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Source: Equitrans
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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 75 miles from the MVP terminus in Virginia to delivery points in Rockingham and Alamance Counties, North Carolina.
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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 realtively 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 (Q1 2026 EC)
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04/22/2026
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2026 Gudiance:
Production: ~6.2–6.5 Bcfe/d
Maintenance CapEx: ~$2.07–$2.21B
Strategic & Infrastructure Highlights:
Vertical integration (Equitrans) driving lower costs + higher reliability
2x peer uptime during Winter Storm Fern
Accelerating demand tie-ins (data centers, power projects) in Appalachia
Integrated model enables price optimization + flexible production response
Drilling & Basin Activity
Production above high-end of guidance driven by strong well productivity
Efficiency gains lowering capex and operating costs
Q2 curtailments: ~10–15 Bcf to optimize seasonal pricing
Continued investment in compression, water systems, and pipeline connectivity
Hedging Activity
Captured ~100% of Q1 gas price upside (low hedge exposure)
2026 hedge book ~$180MM in-the-money
Strategy: opportunistic hedging while maintaining upside exposure
Analyst Q&A Takeaways
LNG is Critical for Value Realization:
U.S. gas remains disconnected from global pricing
Long-term LNG exposure (post-2030) is key to closing gap
Basis Improvement Strategy:
Focus on demand pull into Appalachia (data centers, power)
Expected to structurally tighten differentials over time
Supply Discipline:
Curtailments used as “in-ground storage” to maximize pricing
Production flexed based on seasonal demand signals
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Expand Energy (Q1 2026 EC)
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04/29/2026
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2026 Guidance:
Production: ~7.4-7.6 Bce/d
Appalachia: ~4.3 Bcfe/d total
Northeast Appalachia: ~2.65-2.68 Bcfe/d
Southwest Appalachia: ~1.62-1.63 Bcfe/d
CapEx: ~$2.75-$2.95B
~45-50% allocated to Appalachia
Strategic & Infrastructure Highlights
Appalachia positioned as core AI/data center demand basin (4-6 Bcf/d growth)
In-basin demand growth expected to unlock pipeline-constrained supply
~0.5 Bcf/d new term sales + transport added to premium markets
Integrated marketing strategy targeting ~$0.20/Mcfe margin uplift (~$500MM FCF)
98% uptime in Appalachia during Winter Storm Fern
Drilling & Basin Activity
Appalachia Production (Q1):
Northeast: ~2.78 Bcfe/d
Southwest: ~1.50 Bcfe/d
Rig Activity:
Northeast Appalachia: 3 rigs / 2 crews
Southwest Appalachia: 2 rigs / 1-2 crews
Operational Highlights:
Record drilling speeds in Utica (SW Appalachia)
Continued efficiency gains lowering well costs
Seasonal curtailments expected in Q2 to align with demand
Hedging Activity
~66% of 2026 gas production hedged
"Hedge-to-wedge" strategy:
Protect downside cash flows
Maintain upside exposure to volatility
Actively optimizing hedge book based on market conditions
Analyst Q&A Takeaways
Appalachia Demand Inflection:
AI + power demand expected to drive 4-6 Bcf/d incremental demand in Northeast
In-basin demand + new infrastructure = key to unlocking constrained supply
Gulf Coast Pull Impacts Appalachia:
Long-term, Appalachia gas will need to flow to Gulf Coast LNG markets
Pipeline expansion from Northeast seen as necessary
Supply Advantage vs Peers:
Expand has deeper inventory vs smaller Gulf Coast producers
Better positioned to sustain long-term supply into LNG growth
Marketing & Margin Focus:
Strategy shifting to premium market access + integrated value chain
Stacking smaller deals (transport, LNG, power) vs single large transactions
Hedging & Capital Allocation:
Hedging ensures stable cash flow despite volatility
Buybacks remain opportunistic, balanced with debt reduction
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CNX Resources (Q1 2026 EC)
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04/30/2026
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2026 Guidance
Production: ~1.65-1.70 Bcfe/d
~92-93% natural gas (Appalachia-focused)
CapEx: ~$556-$586MM
Strategic & Infrastructure Highlights
Pure-play Appalachian gas producer (Marcellus + Utica)
Positioned for in-basin demand growth (power + data centers)
Actively participating in RFPs for new power demand
Pipeline connectivity allows flexible delivery across PA/OH/WV markets
Long-term view: demand growth timing uncertain (3-7 year window)
Drilling & Basin Activity
Q1 Production: ~1.69 Bcfe/d
Activity (Q1):
14 wells drilled (SWPA Marcellus)
12 wells turned-in-line total
2026 Activity Plan:
~34 TILs Total
SWPA Marcellus: 24 wells (~13,750 ft laterals)
CPA Marcellus: 3 wells
Utica: 7 wells (~13,400 ft laterals)
Operational Focus:
SWPA Marcellus = core cash flow / "harvest mode" asset
Utica = longer-term growth inventory (early-stage development)
Hedging Activity
~459.6 Bcf hedged for 2026 (~81% of production)
NYMEX: ~3.55/Mcf
Physical/index: ~2.64/Mcf
Strategy:
Heavy hedging vs peers (prioritizes cash flow stability)
Increasing exposure to long-dated hedges (2027-2028)
Benefiting from tightening basis differentials in outer years
Analyst Q&A Takeaways
Appalachia Demand Growth:
Strong agreement on significant in-bain demand growth (power/data centers)
Magnitude large, but timing uncertain (3-7 years)
Marcellus vs Utica Strategy:
SWPA Marcellus remains highest-return asset (existing infrastrcture)
Utica development increasing over time but still secondary
In-Basin vs Gulf Coast Pull:
CNX focused more on local demand capture vs LNG export exposure
Pipeline network allows flexibility across regional markets
Hedging Philosophy:
More conservative vs peers (prioritizing downside protection)
Actively adding longer-dated hedges as forward curve improves
Supply Positioning:
Depth of inventory + credit quality positions CNX to secure long-term contracts with new power/date center demand
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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. Demand in Appalachia specifically reached about 13.5 Bcf/d in February 2025, while the Northeast region as a whole saw consumption hit 29.8 Bcf/d. 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 Northeast US still utilizes a significant amount of coal in its power sector. 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 40 GW of coal generation capacity, about 7.5 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 16 GW of renewables over the next three years. 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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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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Don’t stop here.
See how other regions are performing right now:
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