LNG potential to provide upside in otherwise flat onshore market in 2026

 

By Stephen Whitfield, Senior Editor

The answer to the question of where the global onshore drilling market sits heading into 2026 is simple, if unsatisfying: It depends on how you look at it.

For the most part, the market looks flat. Brent pricing appears to have settled from the uncertainty that was introduced into the market by increases in US steel tariffs and OPEC+ production hikes. Since plummeting from the low $80s into the low $60s this spring following the tariff announcements, prices had rebounded into the mid-$70s before falling again in October into the low $60s.

Even with these fluctuations, the outlook among US E&Ps appears to have improved slightly in the months following the tariff announcements, as fears of a global trade war subside. However, 2026 Brent futures were still trading at just $61.95/bbl as of 16 October.

On the oil side, additional supply from OPEC+ will likely push down prices and depress drilling activity marginally in several oil basins. But on the gas side, Rystad Energy said it expects the Henry Hub price to jump next year as more LNG trains come online in the US Gulf Coast and gas demand picks up. While that means the market should be on an upward trajectory soon, that is not going to be evident in terms of 2026 rig and well metrics.

“We’re in a depressed market, but it doesn’t quite feel like it’s a depressed market in the sense of other previous downturns,” said Ryan Hassler, Vice President at Rystad Energy, noting that there’s been a slow progression of a declining rig count throughout this year. “Drilling efficiencies are still high. If you look at the revenues of the largest three drilling contractors – H&P, Nabors and Patterson-UTI – they’re still doing pretty well from a standpoint of revenue per rig operating day.”

Rystad Energy is forecasting a $62/bbl average Brent price for Q4 2025, which is slightly lower than its forecast average of $69 for the year overall. However, after Q4, there should not be much more of a dip next year – the firm expects the Brent price to still average $62 for 2026. Henry Hub prices are expected to hold fairly steady, if low, at $3.32/MMBtu in 2025 before jumping to $4.35/MMBtu in 2026, according to Rystad.

Lower 48 horizontal rig count will likely continue to see a slow decline, however. It has already dropped by 41 rigs since 2024 to 494, and that number is forecast to fall to 448 in 2026. Rystad also forecasts the number of wells completed to drop in several key basins, including the Permian.

Outside of the US Lower 48, Rystad expects the market to be fairly flat, if not slightly bearish, as various countries navigate the uncertainty spawned from geopolitical events. The global rig count – but excluding the Lower 48, Russia and China – is forecast to stay in a similar range, going from 1,210 in 2025 to 1,180 in 2026. Wells drilled will rise slightly from 43,107 in 2025 to 43,506 in 2026.

For companies seeking pockets of opportunity in this market, Rystad pointed to countries that are either working on their LNG export capacities or building up existing midstream infrastructure as the ones with the highest-potential growth drivers. This includes countries in both the Middle East and South America.

“That is the gas story. When there’s enough gas, there’s an LNG project,” said Matt Hale, Senior VP of Drilling & Wells Research at Rystad Energy. “I think the activity is supporting a lot of cases of building out LNG infrastructure. You have an LNG export facility, or you have good investment-grade LNG projects that have offtake agreements, and you have the midstream infrastructure, that could support drilling activity. Also, I think we should note that there are large economies still dependent on imports.”

US Lower 48

Mr Hassler described the US Lower 48 as being “pretty close to the bottom” of a downcycle heading into 2026. But even with fewer rigs drilling, the current market is advantageous for the larger drilling contractors that have more high-spec rigs, which are drilling longer laterals in shorter amounts of time and incorporating more advanced automated systems. As E&Ps continue to maintain their focus on capital discipline, it’s these high-spec rigs have mostly been able to stay contracted.

“It’s sort of similar to the capital discipline story on the E&P side. The bigger drillers are driving a lot of this environment. They’ve essentially stacked equipment as they see necessary in order to keep the best equipment and the best crews working and drive utilization quite high,” Mr Hassler said. “The highest spec crews and rigs have maintained high utilization even in light of that declining rig count, and that’s because of this systematic approach from the top drilling contractors. There’s definitely a delta in pricing between the smaller drillers and the larger ones.”

The impact of increased drilling efficiency can be seen in the Permian. M&A activity has driven continued declines in the number of horizontal wells completed, expected to fall from 5,528 in 2025 to 5,118 in 2026, and in rig count, which is expected to drop 7% year-on-year from 2025 to 2026. Production, on the other hand, has been able to stay at roughly the same level year-on-year from 2024 to 2025 because of the efficiency gains seen by high-spec rigs. “In the current pricing environment, the Permian is the only basin really driving material production growth in all of US shale,” Mr Hassler said. “You still have to maintain some level of production, and then look for a small amount of production growth. That’s why we probably will not see too much more movement downwards in the rig count in the Permian beyond what we’ve already seen.”

The gas-heavy Haynesville Shale should also fare relatively well next year, especially with Henry Hub prices expected to increase. It is the one basin in the Lower 48 where horizontal wells completed (506 in 2025, 520 in 2026) and rig count (2026 levels to go up 3% from 2025 levels) are expected to increase, if only slightly. By 2027, the Haynesville could begin to see rig activity pick up even more as additional LNG terminals come onstream. Rystad’s forecast rise in gas pricing next year, along with continued higher pricing in 2027 (forecast at $4.46/MMBtu), could also further support rig activity.

“There’s been a lot of consolidation in the Haynesville over the last couple of years. There are fewer operators controlling more of that economic acreage, and they’ve been sitting on that acreage… Everybody’s kind of playing this waiting game to get to that higher pricing market,” Mr Hassler said.

In other more mature basins like the Bakken and the Denver-Julesburg, Rystad expects slight activity decreases next year. The same trend is forecast for the Marcellus-Utica Basin, with the rig count and horizontal well count both expected to stay roughly the same (762 wells in 2025 vs 755 wells in 2026, and a 1% drop in rig count from 2025 to 2026). However, Mr Hassler notes that there is an X factor that could affect activity in this market in the future: gas demand for data centers.

According to Rystad, more than 100 GW of data center land acquisition and construction announcements have been made in the US as of early 2025. These centers are poised to require between 395 and 660 terawatt-hours (TWh) of power by 2035, representing at least 10% of current total demand in the US. Although few of these announced data centers are located in the Marcellus-Utica footprint, Mr Hassler said he sees potential interest in building data centers in the Appalachia, with Pennsylvania emerging as a potential data center hub. For instance, in June, Pennsylvania Governor Josh Shapiro announced that Amazon had planned a $20 billion investment to build data center campuses across the state.

The following month, during the Pennsylvania Energy and Innovation Summit in Pittsburgh, Google, Blackstone and FirstEnergy announced an aggregate $92 billion in energy and AI investments in the state. In particular, Blackstone said it would build and operate natural gas-based power generation stations in a joint venture with PPL Electric Utilities to power data centers. Also in July, EQT Corp signed a deal to supply nearly 1 billion cu ft/day of Marcellus gas to a restarted power plant alongside a planned data center in Pittsburgh.

These actions will not have an impact on next year’s rig and well counts in the Marcellus, but they are signaling a potential shift that could lead to an increase in gas demand down the road.

Moreover, there are pipeline projects under way that should alleviate the takeaway capacity bottleneck that has plagued this region – the Mountain Valley Pipeline Southgate Project and the Tioga Pathway Project are both in the permitting process. Combined, these actions could create an environment for drilling activity growth in the near-term future.

The challenge in unlocking this potential with data centers will be overcoming the regulatory environment.

“We all know that the Northeast US is a more challenging regulatory environment for oil and gas infrastructure, and we will have to wait and see if this is also true for other major infrastructure projects like data centers. But I view it as something that could support economic growth outside of purely oil and gas. Maybe the governments view that differently, but if the potential for data centers is out there, and the regional producers can supply some of the gas needed for that from a power standpoint, then there is a possibility to unlock demand,” Mr Hassler said.

Canada

“Things are a little bit tough” for the onshore Canadian market right now, Mr Hassler said, though he remains optimistic for the future. He’s forecasting the rig count to stay in the same range year-on-year, with 194 rigs in 2025 and 180 in 2026. Unconventional wells drilled should reach 2,369 in 2026, a 4% increase over the 2,277 expected in 2025.

The story in Canada is an LNG story, he noted. The LNG Canada terminal exported its first cargo on 30 June from its facility in Kitimat, British Columbia, marking the beginning of Canadian LNG exports. So far, this milestone has not boosted gas prices, however. Strong 2025 production guidance from major Canadian operators, combined with robust activity levels from small private producers, have contributed to an oversupplied market. This is keeping prices down and will likely limit the possibility of an immediate ramp-up in drilling.

The AECO spot price (the benchmark for natural gas trading in Western Canada) averaged US $0.55/MMBtu in the three months following LNG Canada’s startup. Even though gas prices are usually lower in the summer months than during winter, Mr Hassler said the market remains oversupplied as increasing feedgas demand for LNG Canada has not yet caught up to supply.

Rystad’s view of AECO prices in the short term remains bearish, as many players in the Montney Shale can easily ramp up production, with decades of low-breakeven inventory. Additionally, production ramp-up at the LNG Canada facility has been slow so far. The pace of shipments in August and early September averaged just one cargo every nine days, well short of the four-day pace expected at full capacity. Once the first facility hits full capacity –  in late October for the first train and by May 2026 for the second train – LNG Canada will require approximately 1.8 billion cu ft/day of feedgas.

Additional projects under way could also help to alleviate the gas oversupply, Mr Hassler said. Woodfibre LNG and Cedar FLNG are expected to begin ramping up in 2027 and 2029, respectively, adding an extra 0.7 billion cu ft/day of feedgas demand.

Other pre-FID LNG projects have also made regulatory progress recently, under the recently installed government of Prime Minister Mark Carney, who took over from Justin Trudeau following the country’s parliamentary elections in April.

Under Prime Minister Carney, the Liberal Party has signaled a much friendlier attitude toward oil and gas development. For example, the government in September established the Major Projects Office (MPO), aiming to fast-track regulatory assessment and approvals of projects deemed to be in the national interest. LNG Canada Phase 2 was selected by the Prime Minister’s office for the first series of infrastructure projects referred to the MPO for expedited approval. The Prime Minister has also scrapped the consumer carbon tax.

Other positive actions include the government’s greenlight, assisted by the Impact Assessment Act, for the construction of the Ksi Lisims LNG in British Columbia. Work on the Prince Rupert Gas Transmission pipeline has also started in the province.

While it remains to be seen how the Liberal Party’s attitude toward oil and gas development will evolve and how new government policies will impact LNG development and drilling activity, Mr Hassler said the initial signs are positive.

“You have LNG Phase 1 now taking some cargoes, which is going to support natural gas growth out of the Montney. Then, you have some signs that LNG Phase 2 is going to make FID and potentially unlock an additional wave of natural gas demand from the Montney. So the longer-term forecast is pretty optimistic,” he said.

“The services sector is already in a position to take advantage of that growth, and that might even balance the pressure-pumping market as we start to see activity ramp up in the Montney and the Duvernay. It’s a little bit more bullish than what we see in the US.”

He added: “It’s still the Liberal Party in power, but Mark Carney has a very different view on energy than Justin Trudeau did. We’ve seen that there is some support for major infrastructure projects that would provide the associate midstream capacity needed to supply the feedgas for LNG exports. It looks like – maybe – we’re in a world where the Canadian government is more supportive of that infrastructure build-out.”

South America

Rystad is forecasting the rig count in South America to stay flat year-on-year – 111 rigs in 2025, 112 rigs in 2026 – while wells will go down slightly, from 2,438 in 2025 to 2,372 in 2026.

One of the biggest potential growth areas for land rig activity on the continent is in Argentina, where unconventional production from the Vaca Muerta is already helping the country shift away from its historical dependence on gas imports. With the help of investment incentives for additional infrastructure and storage projects, Argentina is now looking toward the potential export and monetization of its gas reserves.

While Rystad did not provide specific rig count totals for Argentina, Mr Hale said he expects an increase in rig activity over 2025, with the number of unconventional wells drilled to increase from 675 to 712.

“There’s just so much potential in Argentina to add rigs,” Mr Hale said. “What gives us that confidence is that there’s a lot of midstream infrastructure supporting production growth there, and that gives them ways to build on that potential like what we’ve seen in the US.”

That midstream infrastructure comes from a few major projects that have either started or are set to start soon. One project, the Southern Energy LNG project, will harness two FLNG vessels, the Hilli Episeyo and MK II. These units will be positioned off the coast of the Rio Negro province, collectively offering an export capacity of 6 million tonnes/year for the country. Southern Energy issued an FID for the MK II on 7 August, with first production from Hilli Episeyo slated for late 2027 and MK II set to come online by the end of 2028.

In a parallel national effort, YPF is spearheading additional large-scale developments in Rio Negro, conceptualized as a broader, phased project alongside the Southern Energy project.

Another project being planned is YPF’s ARGFLNG 2, a partnership with Shell, that is expected to achieve a capacity of 10 million tonnes/year. FID is targeted for 2026, with potential start-up in 2028. ARGFLNG 3 could potentially follow that project, perhaps with Eni as a strategic partner, which would contribute an additional 12 million tonnes/year.

If these projects all move ahead, Rystad said it expects full capacity to be reached by the late 2030s.

Another pivotal enabler for long-term export growth is the Vaca Muerta Oil Sur (VMOS) pipeline project. Slated to commence operations in 2027, VMOS will establish a direct link between the Neuquén Basin and the Atlantic Coast via the Punta Colorada port. This new corridor is set to alleviate inland bottlenecks and enhance export logistics, which Mr Hale said should reinforce the Vaca Muerta’s long-term viability as a global energy hub.

The Vaca Muerta already accounted for 43% of total Latin American upstream deal value in Q1 2025, according to Rystad analysis. In a notable move this year, Equinor reversed its earlier decision to exit the shale play and decided to remain in the region. The operator attributed the decision to the country lifting most of its currency controls, which means that businesses are now permitted to freely access foreign currency to pay for goods and services. Previously, importers were subject to a 30-day waiting period from the shipment’s registered arrival date before making payments. Other motivating factors cited by Equinor included Argentina’s improving infrastructure and export viability.

This shift in Equinor’s stance has marked something of a turning point, reaffirming international confidence in Argentina’s shales. However, federal elections, which were set to be held on 26 October, just after this publication went to press, could be the main risk to the bullish outlook in the country. Incumbent President Javier Milei’s Libertarian Party has been largely supportive of oil and gas production, but recent corruption allegations have dampened his popularity.

“The current administration has done a lot for the fiscal regime that has helped to realize the growth that’s already happened there,” Mr Hale said. “That can continue if he stays in place. They’ve already had a lot of FIDs and awards that really support the drilling activity onshore.”

Middle East

The Middle East will be an interesting market to look for in 2026. After announcing production cuts in 2023 and 2024, OPEC+ has been steadily raising output in 2025 – its most recent increase of 137,000 bpd was announced on 5 October.

Onshore drilling activity is not going to see a boost next year from this production hike – Rystad expects rig demand in the region to move from 587 in 2025 to 583 in 2026, and unconventional wells completed to move from 524 in 2025 to 551 in 2026. However, there been positive contract announcements in the region. In July 2025, Arabian Drilling secured contracts for four land rigs with Saudi Aramco. The following month, Arabian Drilling extended contracts on 11 onshore rigs for gas projects with SLB. “It doesn’t appear like this production hike will be a short-term thing. If these countries want to grow that into next year, they will have to pick up rigs,” Mr Hale said.

Gas will be the key driver of growth in the region. In fact, the Middle East is on track to surpass Asia and become the world’s second-largest gas producer in 2025, just behind North America as the largest gas-producing region. The Middle East currently produces 70 billion cu ft/day of gas, a number that Rystad said should increase by 30% by 2030 thanks to developments in Saudi Arabia, Iran, Qatar, Oman and the UAE.

However, Rystad said this outlook hinges on Brent prices holding at $70/bbl and Brent-indexed gas prices hovering between $7 and $9/MMBtu up to 2030. At lower prices, new projects could be delayed and volume growth could decrease depending on the severity and duration of the price decline. OPEC+ will likely hold significant influence over where those prices fall, depending on how they approach production quotas in the near term.

“It’s a situation where, if OPEC+ continues on this course they’re on now, they’re going to drive down prices once those inventories hit the market. In that case, OPEC+ may have to change course again because they don’t want the oil price dropping below $60,” Mr Hale said.

To capitalize on the potential growth in gas production, the region is preparing for a significant increase in gas exports. By 2030, Rystad believes the Middle East will have an additional 10 billion cu ft/day of gas available for export, positioning itself as a major supplier to both Europe, which is working to reduce its reliance on Russian energy, and fast-growing markets in Asia.

This expansion is supported by a forecast annual production increase of around 6%, with Qatar, the UAE and Saudi Arabia leading OPEC+ to reach a total output of 90 billion cu ft/day by the end of the decade. DC