Executive Summary

Valued at 4.1 USD Trillion in 2025, the Oil and Gas Upstream Market is forecast to reach 6.8 USD Trillion by 2035, expanding at a CAGR of 5.21%.

Saudi Arabia and the UAE are easing production restrictions and directing national oil company capital toward deepwater exploration. Brazil’s ANP expanded its Permanent Production Sharing Offer from 8 to 23 exploratory blocks in March 2026.

Asia-Pacific led upstream activity in 2025 on China and India volumes, while the Middle East and Africa ranks as the fastest-growing region through 2035. Onshore fields remain the largest production base, and national oil companies hold the largest reserve share.

Strait of Hormuz transit risk and mature-field decline, seen in ONGC’s KG-DWN-98/2 output slipping toward 20,000 bbl/d, continue to temper investment pacing. Operators range from NOCs and international majors to independents and oilfield service contractors, with NOCs controlling the largest reserve base.

Key Takeaways

• The market stood at USD 4.12 Trillion in 2025 and is forecast to reach USD 6.85 Trillion by 2035, a CAGR of 5.21%.
• Onshore is the largest location category.
• On operator type, the leading category is National Oil Companies (NOCs).
• Middle East & Africa is the fastest-growing region through 2035.
• 10 suppliers are profiled.

Market Definition and Scope

The Oil and Gas Upstream Market covers exploration, drilling and production activities, from seismic surveys and exploratory wells to primary, secondary and enhanced oil recovery. It spans conventional crude oil, natural gas and natural gas liquids alongside unconventional shale, tight, coalbed methane and oil sands resources, produced onshore and across shallow-water, deepwater and ultra-deepwater offshore fields by national oil companies, international oil companies, independents and oilfield service operators.

The market excludes downstream refining, fuel retailing and midstream pipeline transport and storage, which fall outside wellhead production and field-level processing.

Market Trends

Gulf and Brazilian Offshore Tenders Are Redirecting Exploration Capital

Saudi Arabia and the UAE eased upstream production restrictions through 2026, freeing national oil company balance sheets for final investment decisions (FID) on new field development, while Brazil’s ANP moved in March 2026 to expand its Permanent Production Sharing Offer from 8 to 23 exploratory blocks. The shift favors deepwater and ultra-deepwater operators and the oilfield service contractors that support subsea and floating production systems, lifting offshore drilling activity through 2035 relative to mature onshore basins.

EU Methane Rules Are Pushing Compliance Costs Back to the Wellhead

The EU Methane Regulation, in force since 4 August 2024 as part of the EU Green Deal and REPowerEU push to cut fossil-fuel import dependency, requires leak detection surveys with repairs within 5 to 15 working days and bans routine flaring; importer methane-intensity reporting starts in 2028, with binding limits from 2030 that anchor the bloc’s Paris Agreement NDC commitments. Because the obligations trace back to the originating production facility rather than the export terminal, upstream operators supplying the EU, including US exporters shipping from FERC-authorized LNG terminals and Middle Eastern producers, face rising monitoring and abatement capital spending well before cargoes reach a European port. Tankers calling at those ports already carry a carbon cost under the EU Emissions Trading System’s maritime extension, and exporters are watching whether the EU’s Carbon Border Adjustment Mechanism, currently limited to steel, cement and fertilizers, eventually widens to hydrocarbon cargoes.

Shale Volumes Are Swinging With Price Rather Than Trending Steadily

US EIA guidance moved from a December 2025 forecast of 13.5 million b/d in 2026, a decline built on WTI averaging USD 51 a barrel, to an August 2026 outlook of 13.8 million b/d in 2026 and 14.2 million b/d in 2027 as Brent assumptions rose to USD 85 a barrel. The reversal shows unconventional operators adjusting activity within a single price cycle. US Inflation Reduction Act tax credits for carbon capture keep methane-abatement capex flowing even as rig counts track price rather than policy, giving independents more flexibility than offshore projects locked into a single FID.

Growth Drivers and Restraints

Brazil and Gulf Licensing Rounds Are Expanding the Investable Resource Base

Brazil’s ANP moved in March 2026 to add 15 exploratory blocks to its Permanent Production Sharing Offer, lifting the tender portfolio from 8 to 23 blocks, though each award still requires separate IBAMA environmental licensing. Saudi Arabia and the UAE simultaneously eased upstream production restrictions, freeing national oil company capital for reservoir development. Part of the pull behind both rounds is European: EU Green Deal and REPowerEU diversification away from Russian gas has pushed buyers toward term contracts with Gulf and Atlantic Basin suppliers, sharpening the incentive for operators to reach FID on Brazilian and Gulf offshore acreage. Together the moves widen the pool of financeable projects for international oil companies, independents and oilfield service operators, concentrating near-term capital in Latin American and Gulf offshore drilling.

Rising US Shale Output Is Sustaining Drilling and Completion Spending

The US EIA’s August 2026 outlook raised its US crude production forecast to 13.8 million b/d for 2026 and 14.2 million b/d for 2027, up from the December 2025 forecast of 13.5 million b/d built on WTI averaging USD 51 a barrel. The revision follows a Brent assumption of USD 85 a barrel for the third quarter of 2026. Underneath the price signal, US Inflation Reduction Act tax credits for carbon capture and enhanced oil recovery continue to improve project economics in several unconventional plays. Rising associated gas volumes are also pushing more output toward LNG export terminals, whose expansion still needs Natural Gas Act certificates from FERC, an approval step that can trail drilling by months. Higher realized prices sustain drilling economics in US unconventional plays, pulling incremental rig activity toward independents and integrated oilfield service operators rather than longer-cycle offshore programs.

EU Methane Rules Are Creating a Compliance Services Market Upstream

Regulation (EU) 2024/1787, in force since 4 August 2024, requires leak detection and repair surveys completed within 5 to 15 working days and bans routine flaring, with binding methane-intensity limits on importers from 2030. Producers exporting to the EU, including US and Gulf NOCs and IOCs, must demonstrate MRV equivalent to OGMP 2.0 Level 5 or contract new monitoring and flare-reduction services. The regulation sits alongside the EU Emissions Trading System, whose carbon price adds a second cost to unabated flaring, and the CBAM, which is set to extend carbon-cost exposure to embedded emissions in imported hydrocarbon derivatives. Both instruments trace to the bloc’s Paris Agreement NDCs, giving Brussels a legal basis for reaching upstream standards outside its own borders. The rule is building a distinct abatement services line within the integrated oilfield service segment ahead of the 2030 deadline.

Strait of Hormuz Transit Risk Keeps Middle East Supply and Price Forecasts Volatile

The US EIA’s August 2026 outlook raised its estimate of shut-in Middle East crude production because of continued constraints on transit through the Strait of Hormuz, projecting Brent to average USD 85 a barrel in the third quarter of 2026 before falling to USD 69 a barrel in 2027 as inventories rebuild. That swing complicates FID timing on capital-intensive deepwater projects, and Middle Eastern producers and international oil companies weighing offshore sanctioning absorb the largest share of the resulting uncertainty.

Mature-Field Decline and Project Delays Are Slowing Asia-Pacific Output Growth

India’s ONGC has seen output from its KG-DWN-98/2 deepwater field fall to about 20,000 bbl/d against a 35,000 bbl/d target, even as it set capital expenditure of ₹30,000 crore for fiscal 2026-27, down from ₹35,878 crore the prior year, and plans 87 deep and ultra-deepwater wells over five years. The gap between committed capital and realized output shows how execution delays and natural decline in complex reservoirs slow new Asia-Pacific capacity and push back deepwater payback periods.

Regional Analysis

North America’s upstream base rests on United States output; the EIA forecasts crude production of 13.8 million b/d in 2026, rising to 14.2 million b/d in 2027. Congress’s 2025 revocation of the EPA methane Waste Emissions Charge, deferred to 2034 under the One Big Beautiful Bill Act, cut shale operators’ per-barrel cost exposure.

Europe’s upstream output leans on the Norwegian Continental Shelf, where Equinor plans NOK 60-70 billion in annual investment and around 75 subsea tiebacks through 2035 to hold production near 1.2 million boe/d. Norway expects close to USD 23 billion in oil and gas investment this year, favouring subsea tiebacks over new hubs.

Asia-Pacific ranks as the largest upstream region, led by China and India. India’s Directorate General of Hydrocarbons opened OALP Round XI on 30 March 2026, offering 21 exploration blocks across roughly 80,228 sq km, taking combined acreage on offer with Round X to 262,817 sq km ahead of the 29 May 2026 bid close.

Middle East & Africa is the fastest-growing upstream region through 2035, led by Saudi Arabia and the United Arab Emirates as production restrictions ease and national oil companies lift spending. ADNOC Gas took final investment decisions on Phases 2 and 3 of its Rich Gas Development programme in August 2026, awarding USD 8.2 billion of EPC contracts within a planned USD 28 billion 2026-2030 investment.

Latin America’s upstream growth centres on Brazil’s pre-salt Santos Basin. Petrobras brought the P-79 platform onstream on 1 May 2026, three months early, lifting Búzios field capacity to about 1.33 million bbl/d. The Sergipe Águas Profundas framework, sanctioned across December 2025 and April 2026, commits more than R$60 billion to two FPSOs holding over 1 billion boe of combined resource.

Segment Analysis

Activity

• Exploration – The phase of locating hydrocarbon reservoirs through seismic surveys, geological surveys, and test wells before extraction begins

• Seismic Surveys
• Exploratory Drilling
• Geological & Geophysical (G&G) Studies
• Drilling – The process of boring wellbores into identified reservoirs to establish physical access for hydrocarbon extraction or evaluation

• Onshore Drilling
• Offshore Drilling

• Shallow Water
• Deepwater
• Ultra-Deepwater
• Production – The phase of extracting, separating, and processing crude oil and natural gas from completed wells for transport to market

• Primary Recovery
• Secondary Recovery
• Enhanced Oil Recovery (EOR)

• Thermal Recovery
• Chemical Recovery
• Gas Injection (Miscible/Immiscible)

Exploration, drilling and production form the three sequential stages of the upstream chain, with production the phase that converts completed wells into marketable volumes. Exploration and drilling absorb the bulk of near-term capital, evidenced by 2026 final investment decisions (FID) at Umm Shaif, Cronos and the Rich Gas Development programme, each requiring extensive drilling before first output. Operators are pairing those FIDs with flaring and venting reductions tied to national Paris Agreement NDCs, since gas burned off during well testing counts directly against methane pledges. Crude bound for the European Union also carries a growing compliance layer: the EU Emissions Trading System prices upstream and refinery-gate carbon, and the Carbon Border Adjustment Mechanism (CBAM) will extend that charge to imported barrels and derivative products on a phased basis. That offshore and deepwater sanctioning wave is concentrating near-term activity in well construction over production maintenance.

Resource

• Conventional – Oil and gas trapped in porous, permeable rock reservoirs where hydrocarbons flow to the wellbore under natural pressure without specialized extraction techniques

• Crude Oil
• Natural Gas
• Natural Gas Liquids (NGL)
• Unconventional – Oil and gas held in low-permeability formations such as shale, tight sand, or coalbed methane that require hydraulic fracturing or horizontal drilling to produce
• Shale Oil & Gas

• Shale Oil
• Shale Gas
• Tight Oil & Gas

• Tight Oil
• Tight Gas

• Coalbed Methane (CBM)
• Oil Sands / Heavy Oil
• Gas Hydrates

Conventional crude oil and natural gas remain the industry’s baseline output, produced from porous reservoirs under natural pressure with pipeline and processing infrastructure already in place. Unconventional resources need hydraulic fracturing and horizontal drilling to flow economically, tying output closely to prices: EIA guidance links 2026 US production near 13.5-13.8 million b/d to modest Permian, Alaska and Federal Gulf of America gains offsetting declines elsewhere. Within Enhanced Oil Recovery, the US Inflation Reduction Act’s Section 45Q tax credit is improving the economics of CO2-based EOR by underwriting capture and injection costs, pulling incremental barrels from mature basins that would otherwise be left to decline.

By Location

• Onshore (largest) – Oil and gas reservoirs located beneath land surfaces, developed using land-based drilling rigs, pipelines, and surface production equipment

• Conventional
• Unconventional

• Shale Oil & Gas
• Tight Oil & Gas
• Coalbed Methane (CBM)
• Shallow Water Offshore – Reservoirs situated under seabeds in coastal waters shallow enough for fixed platforms resting directly on the ocean floor

• Fixed Platforms
• Compliant Towers
• Jack-up Platforms
• Deepwater Offshore – Reservoirs found beneath seabeds where water depths exceed the reach of fixed platforms, requiring floating production systems anchored to the seafloor

• Semi-Submersible Platforms
• Tension Leg Platforms (TLP)
• Spar Platforms
• FPSO
• Ultra-Deepwater Offshore – Reservoirs located beneath extremely deep seabeds, accessed through specialized floating vessels and subsea equipment engineered for extreme pressure and remoteness

• FPSO
• Spar Platforms
• Subsea Production Systems

Onshore fields account for the majority of global crude oil and natural gas volumes, consistent with IEA and EIA reporting on production by location, since land-based rigs and pipeline networks cost markedly less to build and operate than floating systems. A growing share of associated gas from those onshore fields is routed to behind-the-meter power generation for drilling rigs and, in the Permian Basin, adjacent data-centre load, sidestepping grid interconnection queues that FERC’s Order 2023 reforms were designed to unclog. Deepwater and ultra-deepwater offshore are expanding fastest, pulled by 2026 sanctioning at Cronos, Búzios and Umm Shaif, where subsea production systems and FPSOs unlock reserves beyond fixed-platform reach.

By Operator Type

• National Oil Companies (NOCs) (largest) – State-owned entities that hold exclusive or majority rights to develop and produce a country’s domestic hydrocarbon reserves

• Fully State-Owned NOCs
• Listed/Partially Privatized NOCs
• NOC-IOC Joint Ventures
• International Oil Companies (IOCs) – Publicly traded, investor-owned firms that explore for and produce oil and gas across multiple countries outside state control

• Supermajors
• Majors
• Independent E&P Companies – Non-integrated firms focused solely on exploration and production activities without downstream refining or marketing operations

• Onshore Independents
• Offshore Independents
• Unconventional/Shale Independents
• Integrated Oilfield Service Operators – Companies that provide the equipment, technology, and specialized services operators contract to drill, complete, and maintain wells

• Drilling Contractors
• Integrated Project Management (IPM) Providers
• Multi-service Integrated Contractors

National oil companies hold the largest share of upstream activity, since state entities such as Saudi Aramco and ADNOC control the bulk of the world’s proved reserves and set regional production ceilings. International oil companies and independents are growing fastest in project sanctioning terms, pulled by farm-in deals such as Shell’s September 2026 entry into BP’s Tupinambá and Conifer exploration blocks, which spread deepwater exploration risk across balance sheets. European supermajors are also redirecting gas-weighted portfolios toward security-of-supply targets under the EU Green Deal and REPowerEU programme, which pushed LNG and pipeline diversification after 2022. BNEF cost benchmarks show that breakeven levels for both NOC and IOC deepwater projects have fallen enough to sustain sanctioning even as service-cost inflation persists.

Country Growth Comparison

United States crude output is set to reach 14.2 million barrels a day in 2027, the largest single-country volume among the countries profiled here. India’s twin OALP rounds put more than 262,817 sq km of exploration acreage to bid in 2026, the broadest licensing push of any covered country, while Saudi Arabia and the UAE pair reserve scale with ADNOC’s USD 28 billion, 2026-2030 gas investment programme. Norway and Brazil are extending mature basins instead of opening new ones: Equinor’s NOK 60-70 billion annual Norwegian Continental Shelf spend and Petrobras’s Búzios expansion both add capacity through subsea tiebacks and new FPSOs rather than fresh discoveries.

Competitive Landscape

Saudi Aramco and a handful of other national oil companies control the majority of the world’s proved upstream reserves, with a group of established international majors and independents completing the market’s competitive core, competing on project execution, reserve replacement and cost of capital. Leading companies include Saudi Aramco, Exxon Mobil Corporation, Chevron Corporation, BP plc, Shell plc, TotalEnergies SE, Eni S.p.A., Equinor ASA, ConocoPhillips and Occidental Petroleum Corporation.

TotalEnergies, ADNOC, CNPC and Eni took a final investment decision in July 2026 for the Umm Shaif Gas Cap development offshore the UAE, targeting more than 600 million cubic feet a day of gas by 2030 and making Gulf NOC-IOC joint ventures a growth channel. Eni and TotalEnergies sanctioned the Cronos gas field off Cyprus in July 2026, the country’s first hydrocarbon development, routing output to Egypt’s Zohr facilities and Damietta LNG for European export. ADNOC Gas awarded USD 8.2 billion of EPC contracts in August 2026 for its Rich Gas Development programme, lifting cumulative programme investment to USD 13.2 billion. Shell agreed in September 2026 to take 50% of BP’s Tupinambá block in Brazil’s Santos Basin and 30% of BP’s Conifer prospect in the US Gulf of America, spreading exploration risk across both companies’ deepwater portfolios.

Strategic Outlook

Deepwater gas in frontier and underexplored basins, Cyprus’s Cronos and the UAE’s Umm Shaif Gas Cap among them, represents the clearest whitespace through 2035. NOC-IOC joint ventures and host governments capture most of the upside, provided financing terms hold and LNG offtake infrastructure such as Damietta keeps pace with new supply.

By 2035, upstream capital is likely to concentrate further around NOC-led gas and deepwater programmes rather than new onshore conventional plays, with subsea tiebacks, digital field automation and farm-in partnerships spreading exploration risk across a smaller number of larger, jointly financed projects.

Oil and Gas Upstream Market Report Scope