Russia's Oil Production and Oilfield Services Market

2.1 Oil and condensate production — year-by-year trend

Table 1 · Russia's oil and condensate production, 2018–2025, and consensus forecast through 2030

Sources: CDU TEK, Russian Ministry of Energy, EIA International Energy Outlook 2023, IEA World Energy Outlook 2025, Russia's Energy Strategy through 2050, Carnegie Endowment for International Peace (2026). Cross-check with EIA (bbl/day): 2023 — ~10.88 million; 2024 — ~10.51 million; crude oil excluding condensate for 2024 — ~9.2 million bbl/day.

2.2 Timeline of key events, 2018–2025

2018

• Production at what was then a historic high — 555.8 Mt.
• The OPEC+ deal (since 2017) is in effect, with periodic quota adjustments.
• A law on a phased "tax maneuver" is prepared — zeroing out the export duty on oil by 2024 with a compensating increase in the mineral extraction tax (MET), effective January 2019.

2019

• Absolute post-Soviet production record — 560.2 Mt.
• January 2019 — start of the tax maneuver: a phased reduction of the export duty from 30% to 0% by 2024.
• The expanded OPEC+ deal is in effect.

2020

• Production collapses by 8.6% (to 512.7 Mt) — the historic OPEC+ deal of April 2020 (a cut in global supply of 9.7 million bbl/day) amid a pandemic-driven demand collapse; the Urals price fell to ~$20/bbl in April 2020.

2021

• Production recovers (+2.2%, to 524 Mt) as OPEC+ quotas ease.

2022 — a turning-point year

• February 24 — the start of the war in Ukraine and the beginning of large-scale sanctions pressure.
• February 27 — BP announces its exit from a 19.75% stake in Rosneft (held since 2013), writing off the investment.
• March 2–15 — the U.S. and EU ban the export of oil refining technologies and new investment in Russia's energy sector.
• March 18–20 — the "big four" oilfield services companies suspend new investment and technology deliveries to Russia: SLB (Schlumberger) and Halliburton — March 18, Baker Hughes — March 19, Weatherford — March 20.
• September — Halliburton sells its Russian business to local management; the new entity is called "BurService."
• August–November — Baker Hughes agrees to sell its Russian business to local management (the deal was approved by Putin in November); the new entity is called "OFS Technologies."
• Exxon announces its exit from the Sakhalin-1 project; the operator becomes the Russian "Sakhalin Oil Company." Production immediately after Exxon's exit collapsed roughly 22-fold (to ~10,000 bbl/day), with a subsequent recovery.
• Shell exits Sakhalin-2; the new operator is the Russian entity "Sakhalin Energy."
• December 5 — the EU embargo on seaborne imports of Russian oil takes effect, along with a price cap set by the G7/EU/Australia coalition at $60/bbl.
• Production rises 2% for the year (to 535.1 Mt) — the effect of redirected flows and the first sanctions had not yet hit output.

2023

• February 5 — the EU embargo on Russian petroleum products takes effect, along with differentiated price caps: $100/bbl on light products (diesel, gasoline, kerosene, naphtha), $45/bbl on dark products (fuel oil).
• February — Russia announces a voluntary production cut of 500,000 bbl/day starting March 2023 in response to the price cap.
• April — a number of OPEC+ countries (including Russia and Saudi Arabia) announce an additional voluntary cut for May–December 2023.
• November — Russia increases its voluntary additional export cut to 500,000 bbl/day.
• November 2 — the U.S. imposes blocking sanctions on the operator of the Arctic LNG 2 project (Novatek) — the first blow to new LNG/gas condensate projects in the Yamalo-Nenets Autonomous Okrug (YaNAO).
• The Urals-to-Brent discount is at a record high early in the year (up to ~$30/bbl), narrowing by year-end to ~$12/bbl as the "shadow fleet" of tankers adapts.
• Oil refining rose ~1.1–1.2%, to 275 Mt.
• The combined share of India and China in Russian crude oil exports rose from 32% (2021) to 78% (2023): India — from 4.5 Mt to 82 Mt (an 18-fold increase), China — from 80 to 107 Mt (+33%).
• A windfall tax is introduced (10%/5% for early payment) — oil, oil refining, and coal companies, as well as LNG producers, are explicitly exempt from it.
• Production −0.8% (530.6 Mt).

2024

• January 1 — export duties on oil and petroleum products are fully zeroed out (completing the tax maneuver launched in 2019); the mineral extraction tax (MET) is raised at the same time.
• Federal Law No. 176-FZ of July 12, 2024 — starting 2025, MET rates are raised for high-profitability sectors, including oil and gas.
• April–October — two episodes of production shutdown at Arctic LNG 2 due to the inability to sell cargoes under sanctions and a shortage of ice-class LNG carriers (Arc7).
• Drone strikes on refineries in European Russia — a factor reducing refining volumes.
• December — a new methodology for calculating the "tax quotation" for the fuel-price damper mechanism is approved.
• Production −3.0% (516.1 Mt); refining −3.1% (to 266.5 Mt); petroleum product exports — 104.3 Mt.
• Gas: production rose 7–7.4% (685–708 billion m³ depending on the estimate), Gazprom +12.25% (420.1 billion m³) — a partial recovery after the collapse of 2022–2023.

2025

• January 1 — a complete halt to Russian gas transit through Ukraine (the contract expired and the parties did not renew it).
• January 10 — the outgoing Biden administration introduces an expanded package of OFAC sanctions: blocking sanctions are imposed on Gazprom Neft and Surgutneftegas — together with dozens of subsidiaries, 180+ tankers, traders, oilfield service contractors, and insurers.
• January — the operator of the Vostok Oil project ("RN-Vankor") is placed under U.S. sanctions; the project's cost rises by 25–30% due to logistics constraints and import substitution.
• February 27 — the U.S. ban on exporting oilfield services to Russia takes effect.
• April — the OPEC+ "eight" begin gradually returning previously cut volumes to the market.
• September — OPEC+ fully exits the voluntary cuts of 2.2 million bbl/day.
• October 22 — the U.S. imposes blocking (SDN) sanctions simultaneously on Rosneft and LUKOIL and 30+ subsidiaries of each — the largest sanctions strike in the history of the regime. A wind-down license is granted until November 21, 2025.
• October — Gunvor agrees to buy 100% of LUKOIL's international assets; in November the U.S. Treasury denies the license and the deal falls through.
• November 30 — OPEC+ fixes production for Q1 2026 and approves a transition to a quota methodology based on audited maximum sustainable capacity (MSC) starting in 2027.
• The Urals-to-Brent discount narrows to its lowest level since early 2022 (~$11.6/bbl in August 2025).
• Production −0.8% (estimate, ~512 Mt); gas −2.6…−4% (663 billion m³ total).

2026 (as of the report date)

• January 29 — LUKOIL signs a final agreement with Carlyle to sell its international assets (European refineries, 5,000+ filling stations in 19 countries, stakes in upstream projects in six countries). Kazakh assets are not part of the deal.
• July — some OPEC+ countries (including Russia) agree to an additional cut of 188,000 bbl/day starting August 2026.
• August 2026 (report date) — for the first time in a long while, Russia's actual oil production comes in roughly 1 million bbl/day below its own OPEC+ quota (8.887 million actual vs. 9.824 million targeted for July) — according to Bloomberg, this is linked to strikes on oil infrastructure rather than a voluntary cut: a key structural shift from "quota-limited" to "capacity- limited" production (more detail in Section 6.2).

2.3 Industry structure and macroeconomic role

Rosneft remains the largest producer — by its own account, it accounts for roughly 40% of Russian oil production; at the end of 2025 the company retained second place in the world by hydrocarbon production among public companies (statement by I. Sechin at the AGM, August 2026), while management itself described 2025 as "a year of decline in key operating and financial indicators."

A distinctive feature of the current period is that the degree of disclosure has become uneven across companies: LUKOIL and Tatneft continue to publish IFRS/RAS statements and pay dividends regularly; Rosneft publishes only aggregated IFRS figures without segment or regional detail; Gazprom Neft and Surgutneftegas have disclosed virtually no operating data since the OFAC sanctions of January 2025; Bashneft has not published production volumes since 2022 at all, limiting itself to reserve-replacement metrics. The legal basis for this selective disclosure is a presidential decree (signed retroactively from July 1, 2022) allowing sanctioned issuers to determine independently the amount of information they publish.

2.4 Industry taxation: completing the tax maneuver, the damper mechanism, MET

• The tax maneuver — launched in January 2019, fully completed by January 1, 2024: export duties on crude oil and petroleum products are zeroed out; the resulting shortfall in budget revenue is offset by a higher base MET rate.
• MET on oil — calculated using a formula with a base rate, a world-price dynamics coefficient (Kc, tied to the Urals quotation and the dollar exchange rate), a damper coefficient Dm, and a number of deductions for specific categories of fields (relief for depleted, new, and Arctic sites, including Eastern Siberia projects).
• The damper mechanism — introduced together with the maneuver in 2019 to compensate refineries for supplying fuel to the domestic market at prices below export parity (and to claw back excess profits in the reverse situation). Damper payments to oil companies in 2025 will shrink to RUB 2.6 trillion. At the end of 2024 the Ministry of Finance approved a new unified methodology for calculating the "tax quotation" for the damper (in effect since 2025) — previously several parallel methodologies were used because of sanctions-related difficulties with direct Urals quotations.
• Additional MET increase from 2025 — Federal Law No. 176-FZ of 12.07.2024 raises rates for sectors with high operating profitability, including oil and gas, on top of the base effect of the tax maneuver.
• Windfall tax — introduced as a one-off in 2023, rate 10% (5% for early payment by 30.11.2023), base — the difference between average profit for 2021–2022 and 2018–2019. Oil, oil refining, coal companies, and LNG producers are explicitly exempt from this tax.

2.5 Urals oil prices and the discount to Brent

The official average annual Urals price (published by Russia's Ministry of Finance, and since 2024–2025 by the Ministry of Economic Development; used as the basis for calculating MET, making it the most authoritative and legally significant price series):

Table 2 · Average annual Urals price, 2018–2025

2025 — confirmed by calculation from 11 of the 12 official monthly quotations; 2024 — tax quotation (a separate alternative estimate also exists).

Monthly Urals price trend in 2025 — a collapse in the second half of the year

Table 3 · Urals price by month, 2025

Urals-to-Brent discount by year

Table 4 · Urals-to-Brent discount, 2018–2025

No single official published series exists; below is a combination of direct press references and the editors' own calculated estimate.

Overall trend: a sharp widening of the discount immediately after the embargo/price cap (late 2022 – early 2023) → steady narrowing as the "shadow fleet's" logistics adapted (by 2024 — ~889 tankers, ~112 million dwt) → a new sharp jump in late 2025 amid blocking sanctions against Rosneft and LUKOIL — the discount remains structurally sensitive to each new round of targeted sanctions rather than narrowing monotonically.

2.6 Natural gas production

Table 5 · Russia's natural gas production, 2018–2025

Context of the decline and partial recovery: the collapse of Gazprom's exports to Europe after 2022 (the Nord Stream sabotage in September 2022, the halt of Yamal–Europe, the complete stop of Ukrainian transit from January 1, 2025 — before that Gazprom exported around 150–170 billion m³/year to the EU). Partial offset — growth in Power of Siberia deliveries to China (Section 4.8), though the absolute volumes are several times smaller than the lost European market.

2.7 Oil distribution balance: the pivot to the East

Table 6 · Production, refining, and export balance, 2023–2024

• In 2023, Russia redirected roughly 140 million tonnes of oil and petroleum products from West to East.
• The combined share of India and China in Russian crude exports rose from 32% (2021) to 78% (2023): India — from 4.5 to 82 Mt (an 18-fold increase), China — from 80 to 107 Mt (+33%). By 2025 roughly 80% of Russian oil shipments go to Asia. Turkey has established itself as the third-largest new sales market.
• Analysts generally consider the export reorientation to have been completed by 2023–2024.
• Russia's refining depth remains stable at around 84.1%.
• Refineries in European Russia came under drone strikes in 2024–2025, which became one of the factors behind reduced refining volumes and periodic domestic fuel shortages.

3.1 The exit and transformation of Western service majors

The real picture of the Western "big four" oilfield services companies' exit from Russia turned out to be considerably more nuanced than the common simplified version that "everyone left in 2022":

Table 7 · Western oilfield services majors — status as of 2025–2026

Bottom line: only 2 of the 4 majors (Halliburton, Baker Hughes) fully handed assets over to local management; SLB and Weatherford continued operating throughout the entire period — undermining the simplified narrative of a "clean Western exit." According to Yakov and Partners, "unfriendly" countries still accounted for 15% of the Russian drilling market in 2022–2023, concentrated in the most technically complex segments (MWD/LWD telemetry, rotary steerable systems, fracturing, offshore work).

Who took the place of those who left

• The share of independent Russian players in the market rose to 52% in 2024 (versus the share held by integrated oil companies' own service units — 41%, and foreign companies — 7%). Russia has the world's highest share of local oilfield service companies — 93% (the world average is roughly 20%).
• Gazprom Burenie — a consistent market leader, with contracts across all major integrated oil companies; rated AA-.ru (stable) by NKR (July 2025).
• RN-Burenie (Rosneft's own drilling asset) — Russia's largest drilling company, with revenue of roughly RUB 100 billion.
• Chinese players: COSL (a CNOOC subsidiary) has operated in Russia since 2015; Yantai Jereh (烟台杰瑞) has built a network of service units and a spare-parts warehouse in Russia, supplying drilling, cementing, enhanced-oil-recovery, and gas compression/liquefaction equipment — reportedly of good quality and noticeably cheaper than Western equivalents.

3.2 Import substitution: drilling fleets, fracturing, equipment

Table 8 · Drilling and equipment import-substitution indicators

Hydraulic fracturing (fracking) — the most vulnerable segment

• Estimates of the number of active fracturing fleets vary — Carnegie Endowment cites "159 (2022) → 188 (2024)," while a KhMAO official said in April 2024 there were "around 150, all foreign-made." The most recent and methodologically transparent reconstruction is D. Kasatkin's expert estimate (Kasatkin Consulting) in the industry publication InfoTEK (October 2025): ~170 active fracturing fleets. The same source forecasts demand growing to ~220 fleets by 2030 and ~250 fleets by 2035.
• Fleet-renewal needs run at roughly 20 new fleets per year (about half of which replace equipment that has reached the end of its service life).
• The first domestically built fracturing fleet was developed by MIT (a Roscosmos entity) together with Gazprom Neft (12 units of equipment); the first commercial operation took place on April 6, 2024, at the Vatinskoye field (KhMAO).
• July 2026 — Gazprom Neft reports the launch of the first series-produced domestic fracturing complex at the Yuzhno-Priobskoye field.
• The technology gap persists: the average number of stages per fracturing operation in Russia is 8–10, versus ~16 stages in the U.S.

3.3 Sanctions restrictions on technology and equipment

• 2014 (baseline): the U.S. and EU banned the export of critical technologies and equipment for deepwater, Arctic offshore, and shale projects in Russia.
• 2022 (expansion): a ban on exporting oil refining technologies (March 2); a ban on new U.S./EU investment in Russia's energy sector (March 8/15); the UK separately banned "energy services," including well drilling and testing.
• January–February 2025: an expanded U.S. sanctions package introduces a comprehensive ban on providing oilfield services to persons in Russia (effective February 27, 2025).

Import dependence for offshore/Arctic projects (Yakov and Partners estimate): floating drilling rigs — 90% import, production equipment — 80%, marine seismic surveying — 70%, supply vessels — 80%; delivering the offshore plans through 2030 will require more than 30 new platforms. The full-cycle cost of developing hard-to-recover reserves (the Bazhenov formation and analogues) is estimated at $40–60/bbl — comparable to U.S. shale production.

3.4 Size and structure of the oilfield services market

Table 9 · Oilfield services market size estimates by source

Despite the spread in methodologies and currencies, sources broadly agree: the market grows nominally at a mid-single-digit annual rate through 2030, provided Urals stays above $60/bbl. More than 300 oilfield services companies were operating in Russia at the end of 2024 across four segments: integrated oil companies' own units, large independent Russian players (revenue >RUB 10 billion), surviving foreign companies, and other independents. Kasatkin Consulting points to a likely consolidation of the market — within a five-year horizon a "national champion" with a 15–20% market share may emerge.

3.5 The 2009 REnergyCO report: what came true and what didn't

This report methodologically continues a separate REnergyCO industry report titled "Oil Production and the Oilfield Services Market, Volume II: Russia's Oilfield Services Market" (May 2009, data for 2002–2008, forecast through 2015). Below is a reconciliation of its baseline figures and forecasts against what actually happened, including the fate of the companies that the 2009 report identified as key market players.

Market size: forecast vs. actual

Table 10 · Russia's oilfield services market: REnergyCO's 2009 forecast vs. actual

The 2009 forecast did not pan out: by 2019 the dollar-denominated market had reached only ~58% of the value forecast for 2015. The reason was not an error in the 2009 analysis itself, but two structural shocks the model of that time could not have foreseen: the sanctions-driven ruble devaluation of 2014–2016 (the rate rose from ~32 to ~65–70 rubles/$, halving the dollar-equivalent size of the market) and the breakdown of technology supply chains after 2022. The 2022 and 2024 estimates are the editors' own calculation using the Bank of Russia's average annual exchange rate, not a primary source figure; Kasatkin Consulting's market scope may not fully match the narrower scope used by the 2009 REnergyCO report (excluding offshore, equipment, and infrastructure construction).

The fate of the companies named in the 2009 report

The 2009 report named four companies as leaders of Russia's independent oilfield services sector, with combined 2008 revenue of $5 billion (26% of the market excluding casing pipe): BKE (43% of that group), Integra (30%), SSC (18%), GEOTEK Holding (9%).

Table 11 · The fate of the 2009 independent oilfield services leaders

None of them disappeared from the market entirely, but none retained the previous ownership structure or the reporting transparency that characterized the 2009 report.

Table 12 · Number of active fracturing fleets, 2022–2035

Sources disagree (Carnegie: 159→188; KhMAO: ~150 in April 2024); the 2025 figure is the editors' reconstruction at the intersection of the trajectories.

Regional production map

A schematic map (not a geographic projection) — regions are arranged by their relative position to one another. Fill intensity on a blue scale encodes production volume; regions without a single published data set are marked separately — this too is a research finding, not a layout gap.

gapHatching marks regions for which no single up-to-date published production tally could be found (only data at the level of individual companies/fields is available).

4.1 Khanty-Mansi Autonomous Okrug (KhMAO)

The country's largest and, at the same time, most mature oil-producing region continues to decline steadily:

Table 13 · Oil production in KhMAO, 2018–2024

KhMAO's share of total Russian production fell from 41% to 40% between 2023 and 2024. The cumulative decline over 2018–2024 amounted to roughly 31 Mt, or about 13%. By one estimate, Western Siberia as a whole (KhMAO + YaNAO + southern Tyumen Oblast) accounts for roughly 80% of "low-sulfur" oil production in the country as of 2024 (a caveat is warranted: this figure may relate to a narrow crude-grade classification rather than to the region's total production). By a long-term forecast, the share of Western Siberia's largest fields in total Russian production may fall from 21% to 19% by 2035, with production from this cohort of fields dropping to 103.2 Mt (2030) and 98.1 Mt (2035).

4.2 Yamalo-Nenets Autonomous Okrug (YaNAO)

Traditionally a gas region with a growing role for oil and condensate — driven above all by Gazprom Neft's Arctic projects. The key asset is the Novoportovskoye field: target hydrocarbon production for 2024 was roughly 5.08 Mt, with proved and probable reserves (C1+C2) exceeding 250 Mt of oil/condensate and 320+ bcm of gas. The Messoyakhaneftegaz joint venture (50/50 with Rosneft, operated by Gazprom Neft) had reached cumulative production of over 40 Mt by early 2025. By one estimate, KhMAO and YaNAO each account for roughly 23% of Russia's "low-sulfur" oil production.

Table 14 · Oil production in YaNAO, 2019–2025

The series is assembled from scattered official sources — the regional government, the district natural resources department; no single consolidated table covering all years is publicly available.

4.3 Volga-Urals region

The country's oldest oil-producing region (Tatarstan, Bashkortostan, Udmurtia, Orenburg and Samara Oblasts) continues a steady natural production decline.

Table 15 · Change in production by Volga-Urals region subject, 2024

The key constraint for the region is the depletion of traditional reserves; a partial offset may come from technologies for producing hard-to-recover high-viscosity oil (see Section 5.5, Tatneft).

4.4 Timan-Pechora

The Komi Republic and the Nenets Autonomous Okrug — a region with a mature resource base, described by industry sources as "having no prospects for launching new fields," with declining recovery rates at existing assets (LUKOIL's Yuzhno-Khylchuyuskoye field, a number of Rosneft assets).

Table 16 · Oil production in the Komi Republic (a proxy for Timan-Pechora)

A separate tally for "Timan-Pechora as a whole," including the Nenets Autonomous Okrug, does not exist in open sources.

For reference: "LUKOIL-Komi" (the region's main operator) produced 14.9 Mt of oil in 2021 — comparable to the regional figure, confirming LUKOIL's dominant role in the province. The company is also preparing to merge the "LUKOIL-Komi" entity with "LUKOIL-Perm."

4.5 Eastern Siberia and the Vostok Oil project

The only region with a confidently rising production trend, and at the same time — a key bet on the industry's future as a whole:

• The Verkhnechonskoye field (Irkutsk Oblast, Rosneft) — production has nearly tripled, exceeding 8 Mt/year.
• The Talakanskoye field (Yakutia, Surgutneftegas) — roughly 8 Mt/year.
• The Vankor cluster (Krasnoyarsk Krai, Rosneft) — 14.8 Mt of oil and condensate in 2023.
• By one forecast, Eastern Siberia's share of Russian oil production could exceed 10% by 2030.

Vostok Oil — the industry's flagship project

Table 17 · Vostok Oil project parameters

Actual progress as of 2025: pilot production has begun at the Payakhskoye field; over the first 9 months of 2025 — 101,000 m of development drilling, with 19 producing wells brought online. Delays: the launch of the Taymyrskoye and Zapadno-Irkinskoye fields has been pushed to "no earlier than 2028"; the first stage of the Bukhta Sever port — launch planned for September 2026. Sanctions pressure: in January 2025 the project operator ("RN-Vankor") was placed under U.S. sanctions; the resulting cost increase is estimated at 25–30%.

Vostok Oil ownership structure

Table 18 · Vostok Oil project ownership structure

Bottom line on the Western traders: Trafigura and Vitol, which originally bought minority stakes in 2020–2021 (20% of the project combined; the whole project was then valued at ~€70 billion), exited the capital entirely in July 2022, transferring their stakes to opaque entities in Hong Kong and the UAE — the ultimate beneficiaries are not disclosed in any of the sources reviewed. An Indian consortium (ONGC Videsh, Indian Oil Corp, Oil India, Bharat PetroResources) signed a non-binding agreement back in 2019, but the actual stake purchase never took place; CNPC held talks but, according to the Jamestown Foundation, judged the risks too high. Carnegie Endowment describes Vostok Oil as the "only exception" in an otherwise frozen pipeline of new Russian oil-production projects.

4.6 Far East: Sakhalin-1, Sakhalin-2

Sakhalin-1

Operator since 2022 — the Russian "Sakhalin Oil Company" (replacing Exxon Neftegas). In 2025 a new offshore facility was launched — the southern dome of the Odoptu field, with individual wells flowing up to 2,600 t/day; production has exceeded the former operator's (Exxon's) planned figures by 20%. The project's field reserves (Chayvo, Odoptu, Arkutun-Dagi) total roughly 307 Mt of oil and 485 bcm of gas. The question of Exxon's stake (30% before its exit) remains open: the deadline for the stake sale has been repeatedly extended (most recently to January 2027).

Sakhalin-2

Operator since 2022 — the Russian entity "Sakhalin Energy" (replacing the Shell structure). Average daily production at the "Molikpaq" platform in 2024 was 2,700 t/day; total LNG output in 2024 was 10.2 Mt; the operator's revenue rose 9% in 2024.

4.7 North Caucasus

The least significant region by volume, with an industry profile of a long-running, steady decline in fragmented, mostly low-flow-rate wells in Chechnya and Stavropol Krai. No consolidated annual production figure for the region was found in open sources; by historical proportions it is estimated at around 1 Mt/year.

4.8 Infrastructure: ESPO, Power of Siberia, Power of Siberia 2

• ESPO (Eastern Siberia — Pacific Ocean pipeline) — reached design capacity (80 Mt/year for the first stage + 50 Mt/year for the second) back in November 2019. Kozmino port throughput was 46 Mt in 2024 → 50 Mt in 2025.
• Power of Siberia (pipeline to China): 2020 — 4.1 bcm; 2021 — 10.4; 2022 — 15.4; 2023 — 22.7 (+50%); 2024 — 30 (design capacity 38 bcm/year); 2025 — 39 bcm (+25%). Volumes remain only a fraction (less than a third) of Gazprom's lost European exports (~150+ bcm/year before 2022).
• Power of Siberia 2: in September 2025 Gazprom CEO A. Miller announced the signing of a legally binding memorandum with CNPC for a pipeline with a capacity of 50 bcm/year. As of mid-2026 the final agreement has not been signed.

Comparison by latest available production figures

Table 19 · Companies: latest available production figures

* Gazprom Neft — the figure includes gas (Mt o.e., 2024) and is not directly comparable to other companies' liquid hydrocarbon figures. † Bashneft — an unofficial estimate (T-Bank/Tinkoff Investments); the company has not published production volumes since 2022.

5.1 Rosneft

Table 20 · Liquid hydrocarbon production, Rosneft

• The company retains the #2 spot worldwide among public companies by hydrocarbon production; management openly described 2025 as a year of decline in key operating and financial indicators.
• Disclosure: a presidential decree (in effect since July 1, 2022) allows Rosneft to independently decide how much information to disclose. The company continues to publish aggregated IFRS figures, but segment, regional, and reserve detail is largely withheld.
• Sanctions: October 22, 2025 — blocking OFAC (SDN) sanctions simultaneously with LUKOIL, with over 30 subsidiaries of each company blocked.
• BP: on February 27, 2022, announced its exit from a 19.75% stake in Rosneft (held since 2013).
• Sakhalin-1: after Exxon's exit in 2022, production collapsed roughly 22-fold before recovering; by 2025–2026 it had exceeded the Exxon-era planned figures by 20%.
• Vostok Oil: pilot production launched in Q1 2025; the Bukhta Sever port launch is planned for September 2026.
• Capex: 2024 — RUB 1.442 trillion (+11.2%); 2025 — RUB 1.360 trillion. Development drilling in 2025 exceeded 11.8 million m, with ~3,000 new wells brought online, 74% of them horizontal.

5.2 LUKOIL

Table 21 · Production, LUKOIL

• The best disclosure among the majors, alongside Tatneft — it publishes RAS/IFRS statements and pays dividends regularly. RAS net profit for 2025 was RUB 403.735 billion; interim dividends — RUB 275.068 billion. Dividend per share: 2024 — RUB 1,055, 2025 — RUB 675.
• Sanctions: October 22, 2025 — blocking OFAC sanctions simultaneously with Rosneft, with 34 subsidiaries blocked, forcing an urgent sale of an international portfolio worth over $19 billion.
• The saga of selling foreign assets: October 2025 — Gunvor Group agrees to buy 100% of Lukoil International GmbH; November 2025 — the U.S. Treasury denies the license and the deal falls through; January 29, 2026 — LUKOIL signs a final agreement with Carlyle. Kazakh assets (Karachaganak 13.5%, Tengiz 5%, Kumkol 50%) are not part of the deal.

5.3 Gazprom Neft

Table 22 · Hydrocarbon production, Gazprom Neft

• Arctic oil exceeds 30% of the company's entire production portfolio.
• Key assets: the Novoportovskoye field (YaNAO) — target 2024 hydrocarbon production ~5.08 Mt; Messoyakhaneftegaz (a 50/50 JV with Rosneft) — cumulative production exceeded 40 Mt by early 2025.
• Sanctions: January 10, 2025 — blocking OFAC sanctions simultaneously with Surgutneftegas, plus dozens of subsidiaries, more than 180 tankers, traders, oilfield service contractors, and insurers. A wind-down license runs through February 27, 2025, the same date on which the ban on exporting oil production/ transport services to Russia took effect.
• Operating-data disclosure is essentially closed, similarly to Rosneft.

5.4 Surgutneftegas

Table 23 · Oil production, Surgutneftegas

The company plans to keep 2025 production flat because of OPEC+ commitments, with upside potential.

The "cash pile" — Russia's largest corporate cash reserve

At the end of 2024 it stood at over RUB 6 trillion (some estimates put it at up to RUB 7 trillion) in bank deposits, mostly in foreign currency (USD/CNY), accumulated over more than 10 years as a hedge against ruble devaluation. By June 30, 2025 the reserve had shrunk to RUB 5.6 trillion — the decline is linked to the ruble's strengthening in 2025. The company remains one of the least transparent entities in the Russian corporate sector — the composition of the deposits and the counterparty banks are not disclosed.

Sanctions: the same OFAC wave of January 10, 2025 blocked Surgutneftegasbank, Kaliningradnefteprodukt, Kirishinefteorgsintez, Pskovnefteprodukt, and other group entities.

5.5 Tatneft

Table 24 · Production, Tatneft

• Alongside LUKOIL — the company with the most consistent reporting disclosure (IFRS/RAS). RAS net profit for 2025 was RUB 152.0 billion (−50.8% y/y).
• High-viscosity oil (HVO) — a competency unique in the industry: annual production exceeds 3.5 Mt, with 883 producing wells involved; the company's own research institute (TatNIPIneft, Bugulma) is piloting the country's first steam-injection technology with variable injection points in horizontal wellbores. Since 2024 a separate tax-support group has been designated for HVO.

5.6 Bashneft

Table 25 · Bashneft — unofficial production estimates (not company-confirmed)

Both estimates should only be used with an explicit "unofficial estimate" label, not as fact. The company's official position is limited to reserve-replacement figures — this is a confirmed, structural disclosure gap rather than a shortcoming of this research.

5.7 Gazprom

Table 26 · Gas production, Gazprom

• In H1 2025 production rose only "symbolically" year-on-year — a signal more of hitting bottom than of a full recovery.
• Financial crisis: RAS figures for 2024 show a net loss of RUB 1.08 trillion (~$12.89 billion). RAS shows a profit of RUB 696 billion for 2023; sources contain some confusion between IFRS and RAS regarding the claim of "Gazprom's first loss in 25 years" — this needs verification. H1 2025 saw a loss of RUB 10.77 billion, sharply smaller than the RUB 480.64 billion loss a year earlier.
• Capex: 2023 — ~RUB 2 trillion; 2024 — cut to RUB 1.574 trillion, then revised up to RUB 1.642 trillion; 2025 — planned at RUB 1.524 trillion (−7%).
• Gas transit through Ukraine has been fully halted since January 1, 2025.

5.8 NOVATEK

• 2024: production ~84 bcm, sales ~78 bcm. "Yamal LNG" (not under sanctions) — output of over 21 Mt of LNG in 2024 (+6%).
• Arctic LNG 2 — under sanctions since November 2, 2023. Design capacity — 3 trains, 19.8 Mt/year of LNG + 1.6 Mt/year of condensate. Partners (TotalEnergies, CNOOC, CNPC, JOGMEC, Mitsui) declared force majeure on offtake. The first train started up on December 27, 2023; in 2024 the project twice suspended production because of sales sanctions and a shortage of ice-class LNG carriers (Arc7). Sanctions have also effectively frozen the associated gas condensate stream — a direct parallel to the constraints on Vostok Oil.
• Starting 2026, the elevated profit-tax rate for "Yamal LNG" drops from 34% to 25%.

6.1 Forecast scenarios: from Carnegie Endowment to Energy Strategy-2050

Unlike the forecast sections of pre-crisis industry reports (a single trend extrapolation), the current situation is marked by a fundamental divergence of scenarios between independent and official sources — this divergence is itself a key finding of the section.

Scenario A — "managed decline" (Carnegie Endowment for International Peace, March 2026)

• 2030: ~8 million bbl/day (continuing the ~3%/year decline rate observed in 2024–2025)
• 2035: below 7 million bbl/day
• Long-term horizon (18–20 years): a possible decline to ~5 million bbl/day under a "managed" scenario
• Crisis scenario (full wartime economic mobilization, a protracted conflict): a decline of 10–12%/year

Carnegie's key structural finding: OPEC+ quotas, fixed on a 2017 baseline with no mechanism for dynamic revision, led companies to conclude that quotas were a "permanent feature" of the market, which effectively destroyed the investment pipeline for new projects. Combined with the loss of access to Asian debt markets after 2022 (the real cost of capital rose to ~20%), companies now fund investment almost exclusively from operating cash flow — meaning cash-flow shocks translate into cuts in drilling budgets within months rather than years.

Scenario B — Energy Strategy-2035 (original version, ~2020)

The target level is stable production around 525 Mt/year, with a share of hard-to-recover reserves rising to 17% and target refining depth raised from 72% to 90%. An earlier version of the same strategy assumed a peak of 560 Mt in 2024, declining to a range of 490–550 Mt by 2035 — meaning the strategy itself was repeatedly revised downward between editions.

Scenario C — Energy Strategy-2050 (November 2024, detailed in April 2025)

• Target scenario: production essentially flat at ~540 Mt/year throughout the entire forecast period.
• Base scenario: a moderate decline through 2030, followed by a sharper decline of 4–5%/year.

Scenario D — Yakov and Partners (a forecast tied to the oilfield services market)

• Base case: the 500+ Mt production threshold in 2030 is achievable provided that localization roadmaps for oilfield services technologies (fracturing fleets, rotary steerable systems, MWD/LWD telemetry, offshore equipment) are successfully implemented.
• Negative case: if the oilfield services market stagnates around $18 billion for 5–7 years, up to 20% of oil production would be "at risk" from technology shortfalls by 2030 — a substantially harsher risk framing than Carnegie's smoothed model, since it directly ties production risk to the state of the oilfield services supply chain.

Scenario E — Ministry of Economic Development (near-term horizon, through 2029)

• Base scenario: 511 (2025) → 525 Mt by 2029.
• Conservative scenario: 497.2 (2025) → 512.2 Mt by 2029.

Scenario F — Vostok Oil as a standalone upside lever

30 Mt/year from 2026, rising to ~50 Mt/year by 2027, "up to 100 Mt/year" by the 2030s. As noted in Section 4.5, even Carnegie treats this project as the "only exception" in an otherwise frozen pipeline of new projects — the industry's entire potential upside is concentrated in a single mega-project.

Scenario G — official international forecasts (EIA, IEA) and the section's key finding

We were able to obtain precise official country figures directly from primary EIA and IEA sources. This data materially changes the section's overall picture: mainstream international forecasters turn out to be much closer to Russia's official target scenario than to Carnegie Endowment's pessimistic model, which in this light looks more like an analytical outlier than a consensus.

Table 27 · Official international forecasts for Russian production, 2030–2035

Key finding: the official EIA (10.3 million bbl/day) and IEA current-policy scenario (~10.7 million bbl/day) forecasts practically match the Russian government's target figure (~10.84 million bbl/day, 540 Mt) — a gap within 5%. In this context, the Carnegie Endowment scenario (~8 million bbl/day by 2030) is not "one point among a wide range of views" but a distinct, notably more pessimistic position held by a single think tank.

Summary table of scenarios for 2030

Table 28 · Summary table of all production scenarios for 2030

6.2 OPEC+: from quota-limited to capacity-limited production

• November 30, 2025 — OPEC+ (8 participating countries, including Russia) fixes aggregate production for Q1 2026 and approves a shift to a new quota methodology based on audited maximum sustainable capacity (MSC) starting in 2027.
• July 5, 2026 — seven major OPEC+ producers (including Russia) agree to cut aggregate production by 188,000 bbl/day starting August 2026.
• Key observation (August 2026, report date): Russia's actual oil production is roughly 1 million bbl/day below its own OPEC+ quota (8.887 million actual vs. a 9.824 million target for July) — according to Bloomberg, this results from strikes on oil infrastructure rather than a voluntary cut.

Implications for the industry and the oilfield services market: until 2025, OPEC+ quotas were the binding constraint, holding back growth in Russian production even where spare capacity existed. The 2026 situation is the reverse — Russia is physically unable to fill even its own quota. Carnegie's analysis notes that the years-long period of "quota lock-in" has already done long-term structural damage to the pipeline of investment in new projects — so even if OPEC+ quotas are eased later on (the new MSC methodology from 2027), Russia may not have enough drilled, ready-to-bring-online wells to respond quickly.

6.3 Regional growth points and risk points through 2030

Table 29 · Regional growth points and risk points through 2030

6.4 Oilfield services market forecast

• Consensus forecast for nominal market growth: +8–10% per year through 2027 (to ~RUB 3.4 trillion), then a mid-single-digit growth rate through 2030 — provided Urals stays above $60/bbl.
• In dollar terms (Yakov and Partners): growth from $20 billion (2022) to $24 billion (2030, base scenario), with the drilling segment alone reaching $8.2 billion by 2030 (+25% vs. 2022).
• Further consolidation around 3–4 large players is likely (integrated oil companies' own units plus 1–2 independent leaders), with a chance of a "national champion" emerging with a 15–20% market share within 5 years.
• The critical open question is the pace and scale of localizing fracturing fleets and offshore/Arctic equipment (70–90% import dependence on key items). According to the Yakov and Partners model, the answer to this question determines whether the "base" (500+ Mt by 2030) or "negative" (up to 20% of production at risk) production scenario materializes.

This report's key finding is that the fate of Russian oil production through 2030 depends, to a far greater degree than in the pre-crisis 2010s, on the state of the oilfield services market itself, not just on geology, oil prices, or OPEC+ quotas. The 2022–2025 sanctions regime simultaneously:

• forced the industry into record-level localization of services (93% — the highest rate in the world),
• while exposing a critical dependence on imported technology precisely in the most capital-intensive and high-margin segments — multi-stage fracturing, rotary steerable systems, offshore and Arctic equipment, ice-class LNG/tanker fleets.

For players in the oilfield services market, this means that the greatest potential demand over the horizon through 2030 is concentrated in three areas:

1. Series production of domestic fracturing fleets — the shift from one-off pilot units (Vatinskoye, 2024) to series production (Yuzhno-Priobskoye, 2026) — the largest still-unfilled niche in import substitution, with a direct impact on production volumes in traditional regions.
2. Servicing and developing Eastern Siberia's infrastructure — Vostok Oil remains the industry's only major source of new demand for drilling, infrastructure, and logistics services; at the same time, the project itself is under direct sanctions pressure (sanctions on RN-Vankor since January 2025), creating a dual risk/opportunity for contractors.
3. Technologies for hard-to-recover and high-viscosity reserves — competencies in high-viscosity oil (Tatneft's model) and, potentially, the Bazhenov formation are becoming strategically significant as traditional Western Siberian and Volga-Urals deposits deplete, although the cost of such projects ($40–60/bbl) makes their profitability highly sensitive to oil prices and the exchange rate.

Official international forecasts (EIA IEO2023 — 10.3 million bbl/day; IEA WEO2025 CPS — ~10.7 million bbl/day) and Russia's Energy Strategy-2050 (~540 Mt/year) converge in a tight consensus range close to the current production level — itself an important signal: the mainstream view of the industry is considerably more resilient than one might assume from the single pessimistic Carnegie Endowment scenario (~8 million bbl/day), which in this context should be read as a "lower-bound" risk estimate rather than a central trajectory. Nonetheless, the very existence of such a gap is an indicator of a level of uncertainty unprecedented for the industry over the past two decades. The NOEC Analytical Center recommends that investors and contractors in the oilfield services market, when planning through 2030, build in a scenario-based rather than a point forecast, paying particular attention to the pace of localizing fracturing and offshore equipment technologies as a key leading indicator of the industry's actual trajectory.