After a modest pullback in 2025, global E&P spending is expected to stabilize in 2026, remaining broadly flat year-over-year. Softer short-cycle spending in major onshore markets is being offset by stronger investments in offshore and LNG-linked developments.
STEPHEN RICHARDSON, Evercore ISI
North American (NAM) spending is set to decline around 3% in 2026, extending the downtrend from the 2023 peak, Table 1. U.S. spending is again the primary drag as the lingering effects of consolidation, capital efficiency gains and maturing shale productivity lower activity. Canada E&P spending will remain flat year-over-year in 2026, supported by improved pipeline egress and anticipated growth in LNG-related gas production. While overall budgets remain steady, operators are prioritizing drilling and completion activity over infrastructure and land expenditures.
Based on analysis, private operators’ capex increased around 10% in 2025. We expect this spending to decline 8% in 2026 as activity levels ease and cost discipline continues to weigh on activity. Independents reduced rigs more materially in 2025 in response to consolidation, capital discipline and capital return priorities. We expect U.S. oil majors’ spending to increase 3% in 2026 as deepwater developments, LNG expansions and large brownfield projects advance.
International E&P spending is expected to increase slightly in 2026, offsetting much of the decline in North America and supporting overall global stability. Growth is forecast at roughly 1% year-over-year, or about 2% excluding Russia, Table 2 and Fig. 1.
The Middle East, Africa and Latin America are projected to lead this growth, driven by continued investment in long-cycle offshore developments, LNG expansion and large-scale field redevelopment. NOCs remain the dominant source of international spending, accounting for the majority of global upstream investment.
Cash flow and oil prices remain the top determinants of 2026 spending plans. Cash flow and oil prices tied as the #1 drivers (each cited by 69% of respondents). Natural gas prices rose sharply to #3 (50%), reflecting growing importance of LNG feedgas demand and a tighter long-term gas balance. Service availability and drilling success rank as secondary factors amid eased supply-chain constraints.
Surveyed E&Ps expect limited change in exploration activity in 2026. 13% plan to increase exploration budgets, while 27% anticipate reductions and 60% expect budgets to remain flat. This contrasts with the prior survey, where fewer than 10% expected cuts and one-third signaled an increase. However, we still anticipate a pick-up in exploration activity in the near-term as oil majors plan to deploy capital to replenish reserves from offshore and international basins.
OFS pricing. Survey results indicate oilfield service pricing will remain broadly stable in 2026. About 58% of respondents expect flat pricing, down from 80% in last year’s survey, while 25% anticipate increases and 17% foresee declines, reflecting a more balanced outlook amid softer North American activity. Tubulars show the strongest upward momentum, with 56% expecting price increases—up from 42% previously—supported by supply-chain tightness and steady demand tied to longer laterals. Some upward pressure is also expected for completion equipment (33%) and seismic services (25%). At the same time, expectations for price declines remain concentrated in core service lines, including drilling (33%), completion equipment (22%) and fracturing and stimulation (22%), consistent with moderating U.S. activity and improved equipment availability. Continued operator consolidation, disciplined capital programs and efficiency gains are fostering a more competitive service environment and limiting broad-based cost inflation heading into 2026.
Digital transformation. U.S. E&Ps continue to report modest progress in digital adoption, with 40% indicating limited advancement to date. Among those expanding digital workflows, in-house development leads (27%), followed by third-party vendors (20%), while only 13% rely on digital offerings from oilfield service providers. Drilling and completions and geoscience and subsurface workflows deliver the greatest value, each cited by one-third of respondents. Other applications—such as production management, land and lease, and ESG reporting—remain in earlier stages of adoption. Evercore notes the survey skews toward smaller and private operators with tighter budgets, suggesting digital uptake could be higher among majors and larger independents.
Commodity prices. Oil price expectations softened through 2025 as fundamentals weakened and operators adopted more cautious planning assumptions. Most E&Ps are budgeting near $58/bbl WTI for 2026, reflecting expectations for continued market softness and potential surplus conditions. Meaningful spending increases would likely require prices near $70–$75/bbl, while downside risk emerges if WTI falls into the low-$50s. Broader industry forecasts similarly point to a subdued environment, with many outlooks placing 2026 WTI in the $50–$60/bbl range amid ample supply and macro uncertainty.
Natural gas fundamentals strengthened in 2025, supported by LNG feedgas demand, power-sector growth and rising industrial consumption. For 2026, operators are using planning assumptions near $3.50/MMBtu Henry Hub, consistent with market forecasts calling for a mid-$3 pricing environment. While near-term prices may ease slightly as supply keeps pace with demand, expanding LNG exports and power demand are expected to tighten balances longer term, supporting a constructive outlook beyond 2026.
REGIONAL BREAKDOWN
North America. North American upstream activity is expected to remain subdued in 2026, with spending declining for a third consecutive year after peaking in 2023. U.S. capex is projected to fall about 3%, reflecting ongoing consolidation, capital discipline and improved efficiency across larger portfolios. These trends have reduced the share of spending by independent operators while lifting majors’ share, as recently acquired shale assets shift into larger portfolios. Private operators—still responsible for roughly half of U.S. rig activity—are also expected to trim spending in 2026 after increasing budgets last year. Overall, about 80% of survey respondents anticipate further declines in Lower 48 rig counts, pointing to continued moderation in drilling activity.
Canada presents a steadier outlook, with spending expected to remain broadly flat as improved pipeline egress and rising LNG-related gas demand support activity. Across the region, U.S. crude production growth is slowing as fewer wells are brought online and efficiency gains mature. New offshore Gulf of America/Mexico projects are helping stabilize volumes, but total U.S. crude output is expected to remain essentially flat in 2026, underscoring a more measured phase of North American upstream investment.
Middle East capex is expected to return to growth in 2026 after declining about 1.5% in 2025, reflecting project timing and budget resets across key producers. Regional spending is forecast to increase roughly 6% year over year, supported by resumed activity in Saudi Arabia and continued strength across the UAE, Qatar and Kuwait. Saudi Aramco reduced spending in 2025 amid project deferrals and a continued pivot toward gas, though activity is expected to strengthen in 2026 as deferred oil projects resume and development at Jafurah advances.
The UAE, Qatar and Kuwait remain the primary anchors of regional growth. The UAE is expected to post mid-single-digit gains driven by oil-capacity expansion and gas development, while Qatar continues LNG-levered upstream investment tied to the North Field expansion. Kuwait is also positioned for another year of solid growth as capacity programs advance. Elsewhere, Oman remains broadly stable and Iraq reflects project-timing variability. Near-term FID activity remains limited, but a larger pipeline of approvals across the Gulf is expected to support regional spending into the latter part of the decade.
Latin America. Regional E&P capex declined roughly 8% in 2025, driven largely by PEMEX budget compression. Excluding Mexico, spending across Latin America increased about 4% year over year and is expected to return to growth in 2026, rising approximately 3% as PEMEX activity stabilizes and most national and independent operators maintain or modestly increase investment. Government support and recapitalization efforts in Mexico are expected to help normalize activity from 2025 lows.
Brazil remains the region’s largest spender, with Petrobras sustaining a strong deepwater-focused investment program supported by multiple FPSO developments and revitalization projects. Argentina, Guyana and Suriname continue to drive structural growth, led by Vaca Muerta development and ongoing deepwater expansion across the Guyana-Suriname basin. A steady pipeline of offshore FIDs across Brazil, Guyana and select regional markets supports a durable long-cycle outlook for Latin American upstream spending into the latter part of the decade.
Africa capex stabilized in 2025, with spending up about 1%, and is expected to re-accelerate in 2026 with growth near 6% as gas and deepwater developments advance. Algeria remains a key driver of regional upside, supported by implementation of the 2019 Hydrocarbon Law, new licensing rounds and continued focus on long-term gas export capacity. Nigeria, Angola, Mozambique, Namibia, Côte d’Ivoire and Egypt are expected to support the next leg of growth, underpinned by a steady pipeline of offshore and LNG-linked projects.
Gas and LNG remain central to the region’s investment outlook, with projects in Mozambique and Nigeria and future phases of Rovuma LNG reinforcing a structurally gas-weighted capex mix. North and East Africa continue to gain momentum amid renewed IOC interest and expanded exploration activity, while frontier basins in Namibia and Côte d’Ivoire add longer-term upside through deepwater developments and FPSO-linked projects expected to support spending into the latter part of the decade.
Asia-Pacific. Upstream capex across Asia-Pacific remained soft in 2025, declining about 3%, largely due to lower spending in China as national oil companies recalibrate budgets amid weaker macro conditions and slower industrial activity. PetroChina and Sinopec reduced upstream spending, while CNOOC maintained relatively stable investment levels. Early indications point to a return to growth in 2026, with Chinese operators expected to increase spending focused on shale gas, tight oil and domestic gas security.
India and Southeast Asia are providing modest support and are expected to move to firmer growth in 2026 as NOCs prioritize gas development to meet rising power and industrial demand. A strengthening FID pipeline across Indonesia, Malaysia, Brunei and Australia is expected to support activity into 2026 and 2027. LNG-linked and domestic gas projects remain central to the regional outlook, underpinned by energy security priorities and growing electricity demand across the region.
Europe. European E&P spending was projected to rise about 7% in 2025 before declining roughly 4% in 2026 as major North Sea developments roll off and operators tighten capital plans. The regional outlook reflects a growing divergence between Norway and the UK. Norway continues to anchor activity, with Equinor, Aker BP and Vår Energi advancing major projects such as Johan Castberg, Irpa, Halten East and Balder X, supporting peak investment levels through 2025 before moderating from 2026. Continued prioritization of oil and gas developments and a steady pipeline of subsea tiebacks and phased expansions on the Norwegian Continental Shelf (NCS) are sustaining comparatively strong spending visibility.
In contrast, UK North Sea investment remains constrained by fiscal and policy uncertainty. The Energy Profits Levy and broader regulatory headwinds are dampening new project sanctioning and long-cycle oil developments, prompting operators to remain selective. While decommissioning, intervention and select development work are sustaining some activity, the near-term FID pipeline is increasingly skewed toward Norway and select continental and Eastern Mediterranean projects. This widening policy and investment gap between Norway and the UK is expected to shape European capex trends and moderate overall regional spending into 2026.
Russia/FSU. Upstream spending across Russia and the FSU was expected to decline about 3% in 2025 and will fall a further 5% in 2026 as sanctions, constrained export routes and fiscal tightening continue to weigh on investment. Visibility into spending trends remains limited due to sparse disclosures, the withdrawal of Western partners and restricted financial reporting. Sanctions on technology, financing and shipping have curtailed major project development and reduced investment flexibility, while discounted crude sales and logistical constraints are compressing netbacks. Although Asian markets provide an outlet for exports, lower realized prices and tighter contract terms are likely to sustain capital discipline and drive further project deferrals across the Russian upstream sector into 2026. WO