Over the past decade, North America’s shale revolution unlocked vast reserves of low-cost natural gas. While these supply sources are spread out across the continent, roughly 75 percent of natural gas production growth in 2014–24 came from three basins: Appalachia (Pennsylvania, Ohio, and West Virginia), Haynesville (North Louisiana), and Permian (West Texas).
Sources of North America’s historical natural gas supply growth
Natural gas production in Canada and the United States grew from approximately 86 billion cubic feet per day (bcfd) in 2014 to about 121 bcfd in 2024, led primarily by Appalachian, Haynesville, and Permian shale production (exhibit). The Appalachian gas basins are now the largest contributors to North American supply, comprising approximately 30 percent of the total volume.
This growth was enabled by midstream players constructing pipelines to link these supply basins with demand centers, effectively stabilizing Henry Hub prices between $2.50 and $3.00 per million British thermal units (MMBTU)1 (see sidebar “Sources of North America’s historical natural gas supply growth”).
However, this era of rapid midstream infrastructure growth has come to an end, especially in the US Northeast, at a time when natural gas demand is projected to rise significantly. Our analysis suggests that US demand (including domestic consumption and net exports) could potentially reach 125 billion cubic feet per day (bcfd) by 2030, an increase of 14 percent compared to 109 bcfd in 2024, driven by increased power demand due to electrification, the rise of data centers, and a growing global liquefied natural gas (LNG) export industry. These same factors are expected to further increase demand throughout the 2030s.
With the gas distribution network already constrained, the US gas market could face supply bottlenecks, price volatility, and a growing dependence on higher-cost supply basins.2 US operators would need to expand the current natural gas infrastructure network to overcome these challenges.
In many regions of the United States, project execution is a considerable challenge. In particular, the Appalachian Basin contains an abundant, low-cost dry gas supply but faces severe pipeline bottlenecks that limit the flow of gas to high-demand markets. Expanding infrastructure in the basin could materially help maintain affordable prices and meet future demand, but would have a range of implications for different stakeholders, from producers to consumers.
In this article, we model two hypothetical infrastructure development plans for the Appalachian Basin—northward pipeline expansion and southward pipeline expansion—and compare them to a baseline scenario.3 We explore the implications of both scenarios on regional pricing and shifts in gas flows to understand how the value chain might be impacted under each scenario.
Pipeline projects adjacent to the Appalachian Basin could debottleneck parts of the system
Between 2010 and 2024, approximately 15,800 miles of incremental onshore gas pipelines were built across the United States. Of this build-out, only around 18 percent was in Appalachia (Ohio, Pennsylvania, and West Virginia)—in contrast to 36 percent in Louisiana and Texas.4 The majority of the build-out occurred before 2018, slowing as key gas corridors became more concentrated and saw increased density.
The Mountain Valley Pipeline
The Mountain Valley Pipeline (MVP) was announced in 2014 with the aim to be in service by 2018. It was completed in 2024 after the resolution of litigation and regulatory uncertainty on permitting.
It has a maximum capacity of two bcfd and is designed to move Appalachian gas from the supply basin’s central hubs to the Transcontinental Gas Pipe Line (Transco) at an interconnection in Virginia, then onward to growing demand markets in the US Gulf Coast and the Northeast (exhibit).
This slowdown in infrastructure build-out has constrained gas export capacity from the Appalachian Basin and the ability for operators to increase gas production volume. Over the past decade, a number of regional pipeline projects have been proposed with the goal of improving gas flow to local urban demand centers or to the US Gulf Coast (USGC). While most of these proposed projects were not successfully completed, the Mountain Valley Pipeline (MVP), which began construction in 2018, came online in June 2024 (see sidebar “The Mountain Valley Pipeline”).
Although MVP provided a new outlet for gas production and has been operating at more than 80 percent capacity since completion, its broader regional impact on flows and pricing has been mixed because of downstream constraints on the interconnecting Transcontinental Gas Pipe Line (Transco) (Exhibit 1). For example, at the closest demand market to MVP—Transco Zone 5 in Virginia—gas prices rose immediately prior to MVP being built, then fell straight after the pipeline’s start date, reflecting the anticipation and realized deliveries of new supply volumes.
Prices declined significantly in the months following the MVP’s in-service date at the nearest delivery market, Transco Zone 5 in Virginia, and at the next southern supply hub, Transco Zone 4 in Alabama. In contrast, prices in northeastern markets, specifically Transco Zone 6 (New York and non-New York), remained relatively unchanged following MVP’s in-service date.
Prices remained relatively unchanged following MVP’s in-service date in northeast demand markets further downstream from Transco, for example, Algon Gates in Boston.
After MVP became operational, prices showed little change in Appalachian supply hubs upstream from MVP, such as Dominion N in Pennsylvania.
However, other markets further downstream in the Northeast, such as Algon Gates (Boston) and Transco Zone 6 (New York), continued to follow historical pricing trends, implying that MVP had little to no effect on these markets. Additionally, total natural gas production and prices at supply hubs in the Appalachian Basin remained relatively unchanged in the year after MVP was completed.5 This indicates that although MVP helped alleviate a local supply constraint (Transco Zone 5), it has not significantly changed the broader regional infrastructure constraints that exist downstream of MVP that lead to higher natural gas prices in cities, such as Boston and New York.
By comparison, other pipeline projects that have successfully debottlenecked supply basins have shown more widespread and sustained impacts on pricing and gas flow. For example, in 2019, gas prices in Waha, the West Texas Permian gas supply basin hub, fell substantially relative to gas prices at Henry Hub, the main USGC demand market hub.
Factors influencing associated gas volumes
Associated gas is natural gas produced as a coproduct, predominantly from oil wells. The volume and market accessibility of this gas is influenced by several factors, including:
- the rate of oil production, which is driven by oil price and demand patterns
- the well age, as gas-to-oil ratio (GOR) typically increases with age
- regulations and operators’ emission reduction targets, which reduce the amounts of associated gas that is flared or vented in the field
- the development of infrastructure to transport gas to market
- basin maturity and geology, which affect gas volumes, since “high-gas” basins, such as Delaware, are often only developed after “low-gas” basins have been depleted
Since the economics of these wells is primarily determined by oil prices, associated gas has low or even negative break-even costs, which means that higher volumes of this gas can help lower US gas prices, even when low-cost gas basins, such as Appalachia, are constrained by bottlenecks (exhibit). However, this also means that if oil prices are high enough, gas production can change independent of gas market dynamics, explaining continued Permian gas production growth even with recent negative Waha prices.
These five months of widening differentials (the difference between demand and supply node prices) were caused by increasing production volumes of associated gas that were unable to leave the basin as existing pipelines were already fully utilized. Gas production continued to grow, even though absolute Waha prices became negative, with some producers having to pay to have their gas volumes taken away (see sidebar “Factors influencing associated gas volumes”).
To alleviate this issue, the Gulf Coast Express (GCX) Pipeline was built to connect Waha to Agua Dulce, a demand market in south Texas near Corpus Christi, adding two bcfd of egress capacity. Immediately after GCX started service in August 2019, Waha pricing increased and the Waha-to-Agua Dulce differential shrank by 55 percent ($1/MMBTU), reflecting the value of Permian producers being able to structurally bring stranded gas volumes to market (Exhibit 2). This pricing effect is typical evidence of a pipeline project’s ability to resolve structural regional imbalances, stabilize prices for end consumers, and improve the business case for producers.
The cycle of pipeline additions in the Permian Basin has repeated multiple times over the past decade. These expansions, including the Double E Pipeline and the Permian Highway Pipeline, have helped alleviate short-term bottlenecks, bringing additional low-cost gas to the USGC and reducing local oversupply at Waha.
MVP, by contrast, was locally helpful for Appalachia but did not achieve the same level of impact as GCX. This was largely a result of system bottlenecks remaining in place downstream of the MVP additions that prevented the gas from reaching additional demand centers. Further pipeline development could help unlock these bottlenecks and create value for Appalachian gas producers and US end consumers.
Potential scenarios for expansion: Northward or southward from Appalachia
We explored two hypothetical development scenarios for pipeline infrastructure build-out from the Appalachian Basin to assess the potential implications for gas flows and pricing across Canada and the United States.
One scenario explores pipeline expansion northward (toward the Boston and New York areas), and the other southward (toward the Atlantic corridor urban centers and the USGC). If realized, these expansion scenarios could create the infrastructure conditions required to bring additional low-cost supply to demand markets as they become more accessible.
While these scenarios are not mutually exclusive, we explore them separately to examine the impact on stakeholders of different development goals: a more domestic, demand-oriented path (northward) and a more export-oriented path (southward). If both pipelines were developed, they could add approximately 7.5 bcfd of egress for Appalachia volumes, which is significantly below the more than 15 bcfd of additional economic supply that we estimate represents Appalachia’s “infrastructure unconstrained” potential.
For comparison, we also highlighted a baseline scenario where capacity remains constrained to the current midstream infrastructure (Exhibit 3).
The Baseline scenario assumes that Appalachian pipeline egress capacity remains constrained through 2030, with only approximately one bcfd of capacity added from 2024 to 2030.
The Southward Expansion scenario assumes a cumulative addition of 4.6 bcfd on top of the baseline from resolving the southbound transmission bottlenecks (through MVP’s Southgate expansion and Transco’s southbound Southeast Supply Enhancement [SESE] project) and possible others such as Texas Gas Transmission’s (TGT) Borealis expansion.
The Northward Expansion scenario assumes expansions to the Algonquin Gas Transmission, the Millennium Pipeline, and the Transco northbound pipelines, cumulatively adding up to around three bcfd to existing capacity.
The modeled results for these two pipeline expansion scenarios suggest that stakeholders across the value chain—upstream producers, midstream operators, and downstream consumers (residential and commercial, LNG, storage providers, and traders)—and across geographies could see distinct and significant impacts, with value pools shifting as a lower-cost gas delivery configuration becomes available.
The Baseline scenario
Our baseline scenario assumes increasing LNG demand out of the USGC, limitations on Appalachian egress capacity, and the Permian-associated gas production plateauing in the long run. All these dynamics are expected in the current market. To meet rising demand under this scenario, gas producers would need to increase drilling activity from higher-cost dry gas basins, potentially resulting in Henry Hub prices increasing by $1/MMBTU (above $4 to $5/MMBTU) through the 2040s.
The Southward Expansion scenario
Expanding southward pipeline capacity by four to five bcfd would enable the same volume of additional, low-cost Appalachian gas to flow along the eastern seaboard for domestic use and USGC LNG export by increasing the utilization of Transco’s southbound, MVP, and TGT pipeline systems (Exhibit 4).
Despite the gas having to travel longer distances from Appalachia to the USGC, the total delivered gas cost is projected to decrease due to lower drilling and completion costs in this scenario. This net reduction in system costs could be passed along to consumers or partially recognized as additional margin by producers. However, should this scenario be realized, producers would need to tread carefully, as excessive price markups could drive consumers back to their local suppliers (in this case, North Louisiana gas production).
Upstream impact: The next highest cost supply along the Gulf Coast would be displaced, improving system capital efficiency, while other supply basins would be unaffected
Bringing Appalachian gas supply to the USGC could directly compete with and displace marginal, higher-cost gas production from local Gulf Coast basins, such as the Haynesville Shale Basin (Exhibit 5). In contrast, supply and price differentials (to Henry Hub) for other supply basins, such as Canada (AECO gas hub) and Permian (Waha gas hub), could remain relatively stable and consistent with the Baseline scenario.
The replacement of high-cost, low-productivity Gulf Coast gas wells with cheaper, more productive Appalachian gas wells could improve overall system capital efficiency.6 Between 2025 and 2030, this upstream supply shift is projected to reduce drilling and completion costs by between $7 billion to $9 billion, while maintaining the same volume of natural gas production. This represents a potential decrease of around $16 billion in capital deployed to drill wells in the USGC, and an increase of $7 billion to $9 billion in capital deployed by Appalachian producers.
Midstream impact: Overall value pool expands with higher full-year flows
The Southward Expansion scenario would also result in increased connectivity between Atlantic corridor midstream players and Gulf Coast LNG export facilities, shifting an estimated $0.7 billion to $0.9 billion in revenue from USGC-centric midstream players to their Appalachian counterparts. With LNG exports continually operating throughout the year (even amid seasonal pricing variability and occasional ramp-downs during extreme weather events or facility maintenance), these revenues would be realized year-round for pipelines.
End consumer impact: Southeast gas consumers and LNG exporters see notable price benefits
Southern and Mid-Atlantic domestic gas consumers and LNG exporters are projected to see lower gas prices in the Southward Expansion scenario compared to the Baseline scenario, potentially reducing consumer costs by $4 billion to $5 billion from 2025 to 2030.
For example, our modeling suggests hub price differentials to Henry Hub along the Transco and TGT system (for example, Transco Zone 5 South and Virginia) narrow by about $0.1 to $0.2/MMBTU (10 to 15 percent) across seasons as the system gains greater access to lower-cost gas for the end consumer.
If realized, this scenario could also support the United States’ position as a key LNG supplier to global markets by improving USGC cost-competitiveness (through lower feedgas costs) and limiting impacts from increased exports on domestic gas prices.
The Northward Expansion scenario
By contrast, expanding northward pipeline capacity by one to two bcfd would bring low-cost Appalachian gas to key demand centers in the Northeast region (Boston, New York, and Virginia), principally during peak winter demand seasons, by increasing utilization of Transco’s northbound, Millennium’s, and Algonquin’s systems (Exhibit 6).
Upstream impact: Multiple supply basins would see displaced production from Appalachia, improving system capital efficiency, with Canada seeing the largest impact
An influx of Appalachian gas to northeast markets could primarily offset regional imports from other distant supply basins, notably Canada, Mid-Continent (for example, SCOOP/STACK shale plays), and the Rockies (for example, Denver–Julesburg shale plays and Powder River), basins (Exhibit 7). This displacement, while not as high as that in the Southward Expansion scenario, is projected to shift $0.5 billion to $1.5 billion of drilling and completions spend by oil and gas operators away from these locations to Appalachia.
The impact of this shift would be greatest during the high-demand winter months. During the summer months, when demand is lower, surplus low-cost Appalachian gas supply could slightly edge out flows from these higher-cost basins along the USGC. Northeast imports from the Western Canadian Sedimentary Basin (WCSB)—a major natural gas-producing region in Alberta and British Columbia—are expected to be the most affected. In 2024, the WCSB supplied 8.78 bcfd of gas to US markets, accounting for virtually all of Canada’s natural gas exports. Northward expansion from Appalachia could displace about 1.0 to 1.5 bcfd of this Canadian gas.
Midstream impact: Increased seasonal flows on Appalachia pipelines with lower utilization of west-to-east cross-continental systems
Overall system transportation costs serving northeast gas demand could decrease due to increased use of shorter routes transporting gas from Ohio and Pennsylvania over other longer routes from Canada, Colorado, and Oklahoma.
Resulting midstream value pools are projected to expand, particularly for assets carrying these northward volumes, as local flows reorganize and overall regional system utilization increases. However, due to the high seasonal variability in northeast demand (30 to 45 percent higher in winter than in summer), incremental pipeline capacity may not be fully utilized throughout the year, potentially resulting in lower project margins compared to pipelines flowing southward.
End consumer impact: Reduced peak winter prices for end users
In this scenario, northeast consumers could collectively save $2 billion to $3 billion between 2025 and 2030 due to price reductions from lower-cost Appalachian gas. This would primarily benefit urban consumers across residential sectors, as well as commercial and industrial (C&I) users, including power generators and data centers.
A Northward Expansion scenario could also increase energy self-sufficiency for northern US cities and reduce overall energy costs for US consumers, with gas differentials to Henry Hub near key urban centers, such as Iroquois Zone 2 (Albany) and Transco Zone 6 (New York), projected to fall by around $0.2 to $0.3/MMBTU.
Consideration of full value chain impacts is critical for efficient infrastructure development
Under both Appalachian debottlenecking scenarios, the end consumers of natural gas stand to save billions of dollars in costs through the rest of the decade. However, very different consumers stand to benefit in each scenario.
Midstream infrastructure developers and oil and gas operators will need to clearly articulate the specific value of these integrated projects to create societal and governmental buy-in, whether the focus is on improved LNG exports and positioning US supply on the global market, or improved energy self-sufficiency and reducing pricing pressure on the American consumer.
Natural gas pipeline expansion is a critical tool for meeting the dual goals of supplying growing demand for gas and maintaining downward pressure on pricing. However, the significant differences in how capacity additions redistribute value through the system, combined with the challenges of completing regional midstream projects, likely require alignment across the entire value chain to solve.
Assessing the value of these projects will also need to occur while navigating other changes in the US energy system. Regulatory and energy policies are rapidly evolving, shifting the viability and incentive structure around infrastructure development. At the same time, the regional role of energy transition technologies and economic applications in a demand-growth environment is being tested, as projections view an increasing role for most energy sources in the near and medium term.7
Many questions remain:
- What level and direction of debottlenecking is most critical, given the changing profiles of domestic demand (for example, changes to the Inflation Reduction Act and expected power supply build-out) and LNG markets (such as potential changes to LNG market balances), given US policy shifts?
- How can project developers communicate and share value across different stakeholders to improve the likelihood of infrastructure development? How do these values align with policy and societal objectives across political and geographical regions?
- What levers are available for different operators to support the expansion of debottlenecking infrastructure and promote working toward a common goal?
- How can non-Appalachia producers build resiliency into their development plans when both demand and infrastructure build-out remain uncertain?
- Will gas pipeline infrastructure expansion bring a reliable supply to the emerging data center demand in the Northeast (for example, Virginia)?
A coordinated approach among all players could ensure infrastructure investments, not only by addressing immediate needs but also by aligning with long-term market dynamics, fostering resilience and shared growth across the industry.
