Africa Oil & Gas Law and Regulatory Watch Atlas

Growing producer: 2024 crude output about 44,000 b/d (up ~50% on 2023) and gas about 250,000 MMBtu/d (mostly for power); Eni's Baleine field (Phases 1–2 on stream; Phase 3 FID May 25, 2026 (Eni, PETROCI, Vitol), reported ~USD 4bn, to raise field output from about 60,000 to 150,000 b/d and from 80 to 200 MMcf/d). Official target 300,000 b/d by 2030. Other discoveries: Calao, Calao South (2026), Cachalot. Basin: Ivorian (Tano) offshore basin; onshore sedimentary basin.

Key laws: Petroleum Code (1996-08-29); Ordinance amending the Petroleum Code (2012-04-18); Implementing decree of the Petroleum Code (1996-09-19); Law on local content in oil and gas activities (2022-06-13); Implementing decree of the local content law (2023-05-24); Finance Law 2026 (2025-12-19); UEMOA Regulation on external financial relations (2024-12-20)

• Negotiated PSC regime with competitive cost recovery and production/price-sliding profit oil; terms are contract-specific.
• Strong recent exploration momentum (Baleine, Calao) and direct-negotiation awards to majors.
• Modest PETROCI participation (generally 10–15%) and a good record on contract stability.
• New local content law (2022) and UEMOA FX rules (2024) add compliance work; Code Art. 81 FX guarantees apply subject to BCEAO rules, so check derogations in each PSC.
• A Petroleum Code revision is planned; monitor for changes.

Pre-production frontier. There is no commercial oil or gas output yet. Since 2022 there have been major light-oil discoveries in the offshore Orange Basin, including Venus (PEL56, TotalEnergies operator) and Mopane (PEL83, TotalEnergies operator since 2026, with Galp). Venus (about 150,000 bbl/d FPSO) was reported technically ready for sanction but pre-FID as of September 2026, with first oil targeted around 2030. Mopane FID is targeted for 2028. The offshore Kudu gas field remains undeveloped.

Key laws: Petroleum (Exploration and Production) Act, 1991 (1991); Petroleum (Taxation) Act, 1991 (1991); Export Levy Act, 2016 (2016); Petroleum (Exploration and Production) Amendment Bill, 2025 (2025); National Upstream Petroleum Local Content Policy (2026-08-04); Environmental Management Act, 2007 (2007)

• One of the most competitive fiscal regimes in Africa on paper: 5% royalty, 35% petroleum income tax and an Additional Profits Tax that bites only at higher returns.
• State participation is modest and not statutory (about 10% NAMCOR in practice).
• Governance is in transition. The Amendment Bill moves regulation to an Upstream Petroleum Unit under the Presidency, and investors should follow the final text and its transitional provisions.
• There is no fiscal stabilization in practice, and Namibia is outside the ICSID and New York Conventions, so project-level protections (offshore arbitration seat, treaty structuring) matter.
• Local content is moving from principle to policy, and a statutory regime is likely after first production nears.

Former small oil producer (Chinguetti, 2006–2017); became an LNG exporter in April 2025 with GTA Phase 1 (bp/Kosmos, ~2.3–2.5 mtpa FLNG shared 50/50 with Senegal). Large undeveloped gas at BirAllah (Block C8; government estimates up to ~60–80 Tcf): bp's operating contract expired in April 2024, TotalEnergies withdrew in H2 2025, and SMH has assumed operatorship targeting first gas by 2030 while seeking partners. Basins: Coastal (MSGBC) offshore basin; onshore Taoudeni basin (frontier).

Key laws: Crude Hydrocarbons Code (2010-07-20); Law amending and supplementing the Crude Hydrocarbons Code (2021) (2021-12); Law on local content in the extractive industries and energy sectors (2024)

• Contract-based PSC regime with strong stabilisation and ICC arbitration in Paris.
• Cost-oil caps (55% oil/62% gas) and State profit share of 31–42% give a moderate take.
• SMH carry and optional back-ins can raise State participation to roughly 25–39% at development.
• New local content law (2024) adds compliance obligations.
• Large undeveloped gas (BirAllah) is open for new partners, with SMH as interim operator.

Pre-production. Commercial discoveries in the Albertine Graben (Lake Albert basin); Government reports recoverable reserves of about 1.65 billion barrels (Nov 2025). Two upstream developments: Tilenga (TotalEnergies-operated, ~190,000 b/d plateau) and Kingfisher (CNOOC-operated, ~40,000 b/d), for ~230,000 b/d combined plateau. Kingfisher central processing facility reported at 99% complete with 22 of 31 wells drilled (Sept 2026). Crude to be exported via the East African Crude Oil Pipeline (EACOP) to Tanga, Tanzania, reported ~92% complete (Oct 2026). First commercial oil, repeatedly rescheduled (2018, 2020, 2025, July 2026), is now targeted by June 2027.

Key laws: Petroleum (Exploration, Development and Production) Act, 2013 (2013-04-05); Petroleum (Refining, Conversion, Transmission and Midstream Storage) Act, 2013 (2013-07-26); East African Crude Oil Pipeline (Special Provisions) Act, 2021 (2021); Petroleum (Exploration, Development and Production) (National Content) Regulations, 2016 and Petroleum (Refining, Conversion, Transmission and Midstream Storage) (National Content) Regulations, 2016 (2016); Income Tax Act (petroleum provisions, Part IXA) and Public Finance Management Act, 2015 (Petroleum Fund) (1997 / 2015); Foreign Exchange Act, 2004 (2004)

• Framework is modern and coherent (2013 upstream and midstream Acts, independent PAU), but first oil has slipped repeatedly and is now targeted by mid-2027.
• Fiscal take is significant: sliding royalty up to 12.5% (older PSAs) or 18% (2015 model), R-factor profit split up to 75% to Government, 30% CIT, and a carried UNOC stake.
• PSAs offer London-seated UNCITRAL arbitration and economic-equilibrium stabilization; Uganda is in both ICSID and the New York Convention.
• No foreign exchange controls; profits and dividends repatriate freely.
• National content rules (reserved services, supplier database) are a material compliance item for contractors and service companies.

Mature oil producer and large gas producer. Gas output was about 3.9 bcf/d in March 2026, with government targets of +1 bcf/d by end-2026 and 6.6 bcf/d by 2027; it is currently below domestic demand. Key areas: Gulf of Suez, Western Desert, Nile Delta, East Mediterranean (Zohr) and Sinai.

Key laws: Mines and Quarries Law (Fuels Material Law) (1953); Law concerning the Egyptian General Petroleum Corporation (EGPC) (1976); Prime Ministerial Decree establishing EGAS (2001); Prime Ministerial Decree establishing GANOPE (2002); Law regulating gas market activities (2017); Income Tax Law (2005); Public Contracting Law (tenders) (2018)

• Each concession is ratified by its own law, providing a high degree of legal certainty for contract terms.
• Royalty and income tax are paid by the state entity out of its share, simplifying the contractor's fiscal exposure.
• Payment arrears and FX availability have been the key commercial risk; arrears were cleared in mid-2026 but EGPC remains highly leveraged per the IMF.
• Active licensing (2026 bid round) and renegotiated gas pricing aim to raise gas output.
• Contractor–NOC disputes go to CRCICA arbitration in Cairo and Government–contractor disputes go to Egyptian courts. Egypt is party to ICSID and the New York Convention.

Offshore producer since 2010 (Jubilee, TEN, Sankofa-Gye Nyame/OCTP). Crude output has declined from a 2019 peak of 71.44 million barrels to 37.3 million barrels in 2025 (about 102,000 b/d); no new petroleum agreement has been signed since 2018; a 2025–2026 Jubilee drilling campaign aims to reverse the decline. Gas from Jubilee/TEN and OCTP supplies domestic power. Basins: Tano (Western), Saltpond, Accra-Keta (Keta Basin, frontier), Voltaian (onshore frontier).

Key laws: Petroleum (Exploration and Production) Act, 2016 (2016-08-19); Petroleum (Local Content and Local Participation) Regulations, 2013 (2013-11); Petroleum Revenue Management Act, 2011 (as amended 2015) (2011); Petroleum Commission Act, 2011 (2011); Income Tax Act, 2015 (petroleum operations provisions) (2015); Ghana National Petroleum Corporation Act, 1983 (1983); Growth and Sustainability Levy Act, 2023 (as amended) (2023-04-03)

• Stable, transparent royalty/tax system with Parliamentary ratification and strong revenue transparency (PIAC).
• Mandatory minimum 15% GNPC carry (exploration and development) plus 5% indigenous equity under L.I. 2204 must be priced into any bid; a reduction to 10% is proposed but requires Parliament.
• Declining production has prompted the government to propose more investor-friendly terms in 2026.
• Royalty, AOE and stabilisation terms are agreement-specific; review the ratified agreement for each block.

Small, declining oil and gas producer and net energy importer (relies on Algerian gas). Oil output fell ~13% and gas ~25% between Nov 2023 and Nov 2024 per parliamentary figures. Key areas: Ghadames/Berkine extension (south), Gulf of Gabès offshore, Nawara gas field.

Key laws: Hydrocarbons Code (1999-08-17); Law amending the Hydrocarbons Code (2002-02-14); Law amending the Hydrocarbons Code (service companies) (2004-07-27); Law amending the Hydrocarbons Code (2008-02-18); Law amending the Hydrocarbons Code (approval of conventions) (2017-05-30); Draft law revising the Hydrocarbons Code (2025)

• Mature 1999 code with R-factor-based royalties and taxes that adjust to project profitability.
• Non-resident holders enjoy a favourable FX regime, keeping sale proceeds abroad beyond local needs.
• ETAP participation option and parliamentary approval steps add timing considerations.
• A Code revision has been under discussion since 2025; investors should monitor its content and transitional rules.
• Arbitration is available under the Code, and Tunisia is party to ICSID and the New York Convention.

Major OPEC oil producer and Africa's largest gas producer/exporter (pipeline to Italy and Spain plus LNG). Crude output roughly 0.9-1.0 million b/d under OPEC+ arrangements (approximate, not verified for this file). Key basins: Berkine, Illizi, Hassi Messaoud, Hassi R'Mel, Ahnet, Reggane, Timimoun.

Key laws: Law governing hydrocarbon activities (2019-12-11); Executive Decree 21-97 (base prices of gaseous hydrocarbons) (2021-03-11); Executive Decree 21-98 (transfer of hydrocarbon contracts) (2021-03-11); Executive Decrees 21-99 and 21-100 (provisional tax payments) (2021-03-11); Executive Decree 21-176 (reduced royalty and tax rates) (2021-05-03); Other implementing decrees (mining titles, conservation, midstream access and tariffs, abandonment, transfer fee, operating authorisations, refining) (2021)

• Law 19-13 offers three contract models; PSCs and RSCs relieve Sonatrach of funding obligations and are the main vehicles in recent rounds.
• Headline fiscal take is moderate (10% royalty, profit-based revenue tax 10-50%), with reduced rates available for difficult projects.
• Sonatrach's 51% minimum and 49% contractor cap remain structural features; pre-emption applies to transfers.
• Regular ALNAFT bid rounds resumed (2024, 2026) with majors and Asian NOCs participating.
• International arbitration is available by contract, and Algeria is party to ICSID and the New York Convention.

Mature oil producer and OPEC member, producing about 220,000 b/d of crude in May 2024 (Platts OPEC survey). Output comes mainly from the onshore and shallow-offshore coastal (Port-Gentil/Ogooué) basin; deepwater and ultra-deepwater are largely unexplored. Gas is mostly associated, and there is a Perenco-led Cap Lopez LNG project.

Key laws: Law No. 002/2019 regulating the hydrocarbons sector in the Gabonese Republic (Hydrocarbons Code) (2019-07-16); Draft separate Petroleum Code and Gas Code (to replace Law 002/2019) (2026); CEMAC Regulation on exchange regulation (2018-12-21); BEAC Instruction raising the repatriation rate for extractive companies (2026-04-23)

• The 2019 code is one of the more competitive CEMAC regimes (no separate corporate tax, higher cost recovery, a State PSC interest of up to 10% plus an optional GOC stake of up to 15%), but it is about to be replaced; new PSCs should be timed and negotiated with the forthcoming oil and gas codes in mind.
• GOC's pre-emption right is real and has been exercised on a major M&A deal; factor it into exit and acquisition planning.
• The commission created in October 2026 to audit and, if needed, renegotiate State agreements means existing contracts may be reviewed.
• CEMAC FX rules will require 50% and then 70% onshore repatriation of export proceeds from 2027-2028.
• Deepwater acreage and gas commercialisation are the government's priority growth areas.

Mature, declining oil producer: 19.3 million barrels in 2025 (about 54,000 b/d), projected about 52,000 b/d in 2026. Main basins: Rio del Rey (offshore, main producing area) and Douala/Kribi-Campo. Gas producer with LNG via the Hilli Episeyo FLNG at Kribi (expected to depart, reducing LNG output from 2027); Yoyo-Yolanda cross-border gas agreement with Equatorial Guinea signed February 2026.

Key laws: Law No. 2019/008 of April 25, 2019 on the Petroleum Code (2019-04-25); Decree No. 2023/232 of May 4, 2023 implementing the Petroleum Code (2023-05-04); Law No. 2012/006 of April 19, 2012 on the Gas Code (2012-04-19); CEMAC Regulation on exchange regulation (2018-12-21); BEAC Instruction raising the repatriation rate for extractive companies (2026-04-23); CEMAC Regulation on implementing FX rules for extractive companies (2021-12-23)

• Codified regime (2019 code plus 2023 decree) with mandatory stabilization terms and three contract models, including risk service contracts.
• Most fiscal terms (royalty, cost stop, profit split) are negotiated per contract and not published; due diligence must rely on the specific contract.
• Production is declining; the government is courting investment in near-field and gas opportunities through SNH-led rounds.
• New York Convention, ICSID and OHADA coverage plus contractual offshore arbitration provide good dispute options.
• CEMAC FX rules will require 50% and then 70% onshore repatriation of export proceeds from 2027-2028.

Second-largest oil producer in Sub-Saharan Africa after Nigeria, averaging about 1.1 million bbl/d (ANPG, June 2026), mostly deepwater offshore in the Lower Congo and Kwanza basins, with frontier acreage in the Benguela and Namibe basins. Gas is mainly associated gas feeding Angola LNG (Soyo). The first non-associated gas project (New Gas Consortium) started production in March 2026. ANPG reports more than 90 blocks awarded as of 2026, up from 20 in 2019.

Key laws: Petroleum Activities Law (2004-11-12); Amendment to the Petroleum Activities Law (2019-04-18); Petroleum Activities Taxation Law (2004-12-24); Customs Regime for the Petroleum Sector (2004-11-12); Foreign Exchange Law for the Oil Sector (2012-01-13); Marginal Fields Decree (2018-05-18); Natural Gas Framework Law (gas legal and fiscal regime) (2018-05-18); Local Content Regime for the Oil Sector (2020-10-20); Incremental Production Decree (2024-11-20); Natural Gas Master Plan (2025-03-21); Decree extending ANPG's remit to the natural gas midstream (2026-04-22)

• A mature, well-tested PSC framework run by a dedicated regulator (ANPG), with regular licensing rounds and a Permanent Offer system.
• The headline fiscal take on standard crude PSCs is high, but targeted regimes for gas, marginal fields and incremental production substantially reduce it.
• Local content rules are strict: only 100% Angolan-owned companies qualify for the exclusivity and preference regimes, which affects service-company structuring.
• Statutory arbitration must be seated in Angola under Angolan law, though awards now benefit from New York Convention and ICSID membership.
• The oil-sector FX regime requires payments through Angolan banks and FX sales to local banks, so treasury planning is needed.

Africa's largest oil producer alongside Libya/Angola: roughly 1.5–1.8 million b/d of crude and condensate in 2025–2026 (approximate; figures vary by source), plus large gas reserves (c. 200+ Tcf) feeding Nigeria LNG (Bonny). Key basins: Niger Delta (onshore, swamp, shallow water, deep offshore); frontier basins: Anambra, Benue Trough, Chad (Bornu), Benin, Sokoto.

Key laws: Petroleum Industry Act 2021 (2021-08-16); Nigerian Oil and Gas Industry Content Development Act 2010 (2010-04-22); Deep Offshore and Inland Basin Production Sharing Contracts (Amendment) Act 2019 (2019-11-04); Nigeria Tax Act 2025 (2025-06-26); Oil and Gas Companies (Tax Incentives, Exemption, Remission, etc.) Order 2024 (2024-02-28); Presidential Directive on Local Content Compliance Requirements 2024 (2024-02-28); Presidential Directive on Reduction of Government Petroleum Sector Contracting Costs and Timelines 2024 (2024-02-28); Upstream Petroleum Operations (Cost Efficiency Incentives) Order 2025 (2025-05-29); Executive Order No. 9 of 2026 on direct remittance of oil and gas revenues to the Federation Account (2026-02-13); Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order 2026 (2026-08-06); Arbitration and Mediation Act 2023 (2023-05-26)

• Modern PIA framework with clear licensing and separate regulators, but tax and revenue rules have been reorganised several times since 2021 (including the Nigeria Tax Act 2025 and EO No. 9 of 2026); asset-level fiscal modelling is essential.
• Strong incentives currently target deepwater and non-associated gas projects through end-2029.
• Local content obligations under the NCDMB Act are among the most detailed in Africa and need early planning.
• FX conditions for IOCs improved in 2026 with removal of the 90-day retention rule.
• The 2025 bid round (provisional awards July 2026) offered onshore, shallow water and frontier acreage.

New producer: Sangomar oil field (Woodside-operated) on stream since June 2024 at about 100,000 b/d; Greater Tortue Ahmeyim (GTA) LNG Phase 1 (bp/Kosmos, shared with Mauritania) exporting since 2025 and ramping up in 2026. Large undeveloped gas: Yakaar-Teranga (~25 Tcf, domestic-market focus). Basin: MSGBC (Mauritania-Senegal-Gambia-Guinea-Bissau-Conakry) basin; PETROSEN onshore exploration programme (~US$100m, 2026).

Key laws: Petroleum Code (2019-02-01); Law on local content in the hydrocarbons sector (2019-02-01); Gas Code (2020-02-07); Decree on the participation of Senegalese investors in upstream oil and gas activities (2020-10-28); Decree on the National Local Content Monitoring Committee (2020-10-21); UEMOA Regulation on external financial relations (2024-12-20)

• Modern 2019 Code with transparent royalties, cost-oil caps and R-factor sharing, but a revision is pending.
• Government is seeking to renegotiate legacy contracts (Sangomar, GTA); expect negotiations and possible disputes.
• State participation (10% carried, plus an optional paid increase of up to 20%) and local content obligations are significant.
• FX rules under UEMOA/BCEAO are being enforced more strictly; confirm contractual derogations.
• Large gas resources (Yakaar-Teranga) with a domestic gas-to-power priority.

Major oil producer and OPEC member: about 260,000 b/d in 2023 (about 270,000 b/d cited in early 2025), government target 500,000 b/d by 2029. Mostly offshore Lower Congo basin (shallow and deep water) plus onshore Coastal basin. Growing gas exporter: Eni's Congo LNG (Tango FLNG from 2024; Nguya FLNG Phase 2 adding 2.4 mtpa for total capacity of about 3 mtpa, with Phase 2 exports expected from early 2026). Proven gas reserves estimated at about 10 tcf (not re-verified).

Key laws: Law No. 28-2016 of October 12, 2016 on the Hydrocarbons Code (2016-10-12); Implementing decrees of 2019 (subcontracting, services, employment and training, penalties) (2019); Gas Code (draft) (2025); CEMAC Regulation on exchange regulation (2018-12-21); BEAC Instruction raising the repatriation rate for extractive companies (2026-04-23)

• Comprehensive 2016 code with clear statutory floors: 15% mandatory carried SNPC interest, 50% cost stop and a minimum 35% State profit oil.
• Local content is among the heavier in CEMAC: a 15% mandatory stake for Congolese private companies and a 25% local-cost floor.
• Every contract needs parliamentary approval, which lengthens timelines but gives negotiated terms (including stabilization) statutory force.
• Gas is the growth story (LNG, Gas Master Plan), but the dedicated Gas Code is still pending.
• CEMAC FX rules will require 50% and then 70% onshore repatriation of export proceeds from 2027-2028.

Gas producer with negligible crude oil output. Onshore gas comes from Pande/Temane (Inhambane), largely exported by pipeline to South Africa. Offshore LNG in the Rovuma Basin comes from Coral Sul FLNG (Area 4), producing since 2022. Two major onshore LNG projects are progressing. TotalEnergies-led Mozambique LNG (Area 1) lifted force majeure and relaunched in late 2025. ExxonMobil-led Rovuma LNG (Area 4, about 18 mtpa) lifted force majeure in November 2025, and its FID was targeted before end-2026 with start-up around 2031. FID had not been confirmed as of the research date.

Key laws: Petroleum Law (revised) (2026-06-03); Local Content Law (petroleum sector) (2026-06-03); Specific Tax and Tax Benefits Regime for Petroleum Operations (2017-12-28); Special Legal and Contractual Regime for the Rovuma Basin LNG Projects (Areas 1 and 4) (2014)

• Since June 2026 the framework has shifted markedly toward State and national participation: a 15% non-dilutable free-carried ENH stake, carry up to 40% through first production, ENH pre-emption on direct and indirect transfers, and a 25% domestic market obligation now covering LNG.
• Law 9/2026 is among the most prescriptive local content regimes in Africa, with sector percentage quotas, a 20% Mozambican shareholding for partnerships and penal sanctions. Supply chain and JV structuring must be reviewed.
• Existing contracts keep vested rights, but any amendment or extension triggers the new regime, and the Rovuma special regime's status needs clarity. This is key for Area 1 and Area 4 financing.
• Strong international arbitration access (ICSID since 1995, New York Convention) and an optional 10-year fiscal stability package remain important protections.
• FX rules require partial conversion of export proceeds, so treasury planning and project-specific FX regimes matter.

Landlocked oil producer; oil provides about 90% of government revenue. Production reported at about 174,000 b/d (Ministry of Petroleum / Petroleum Authority, June 4, 2026), from the Muglad and Melut basins: GPOC (Blocks 1, 2, 4; ~60,000 b/d), DPOC (Blocks 3/7, Dar Blend), SPOC (Tharjiath, Block 5A; ~14,000 b/d) and Nilepet (~2,000 b/d). All exports transit Sudan by pipeline to the Red Sea. Exports were disrupted by the Sudan war: Dar Blend halted from February 2024 for about a year after pipeline damage, and drone strikes on Heglig (November 13, 2025) and a processing facility in White Nile State (November 15, 2025) halted flows for several days before full resumption was announced on November 19, 2025.

Key laws: Petroleum Act, 2012 (2012); Petroleum Revenue Management Act, 2013 (2013); Cooperation Agreement between Sudan and South Sudan, Agreement on Oil and Related Economic Matters (2012-09-27); Local Content Regulation 2019 (petroleum) (2019)

• Statutory framework (Petroleum Act 2012, Revenue Management Act 2013) is modern on paper, including transparency and local content rules, but fiscal terms are contract-specific and agreement texts were not located.
• Export depends entirely on pipelines through Sudan; the Sudan conflict has caused prolonged and repeated export shutdowns.
• FX shortages and a parallel-market premium are material operating risks; IMF engagement focuses on FX unification and oil revenue transparency.
• ICSID membership (2012) supports investor-state arbitration, but South Sudan is not a New York Convention party.
• Nilepet holds preferential rights and a carried role; an expanding national operator role is a policy objective.

Africa's largest proven oil reserves; OPEC member exempt from quotas. Output roughly 1.3-1.4 million b/d in 2025-26 (approximate; NOC target 2 million b/d by 2028), plus associated and non-associated gas largely piped to Italy (Greenstream) and used domestically. Key basins: Sirte, Murzuq, Ghadames, offshore Pelagian/Sirte.

Key laws: Petroleum Law (1955); Amendments to the Petroleum Law (1961, 1963, 1965) (1961); Law establishing the National Oil Corporation (1970); Decree No. 10 of 1979 on the reorganisation of the National Oil Corporation (1979); EPSA V model contract (2025 licensing round) (2025); New hydrocarbons law (draft) (2010)

• Framework rests on a 1955 statute plus NOC-negotiated EPSAs; contract terms carry most of the legal weight.
• EPSA V materially improves on EPSA IV (no B-factor, R-factor, fixed cost recovery), though full terms are not public.
• Government take historically among the world's highest (~88% under EPSA IV).
• International arbitration (ICC Paris) is contractual, but Libya is outside the New York and ICSID Conventions; treaty structuring matters.
• Political division, FX policy and security remain the main investment considerations.

Landlocked onshore oil producer: 55.5 million barrels in 2023 (about 152,000 b/d), exported via the Chad-Cameroon pipeline to Kribi. Main basins: Doba (south, the nationalised former ExxonMobil/Esso fields), Bongor and Lake Chad rift basins (CNPCI and others). No significant gas commercialisation.

Key laws: Law No. 006/PR/2007 of May 2, 2007 on hydrocarbons (2007-05-02); Ordinance No. 001/PR/2010 approving the model production sharing contract and amending Law 006/PR/2007 (2010); Ordinance No. 007/PC/TP/MH of February 3, 1962 (legacy concession regime) (1962-02-03); Law No. 003/PT/2023 nationalising all assets and rights of Esso Exploration and Production Chad Inc. (2023-03-29); Draft Petroleum Code (2026-09-03); CEMAC Regulation on exchange regulation (2018-12-21); BEAC Instruction raising the repatriation rate for extractive companies (2026-04-23)

• Fiscal terms are heavy and contract-specific (14.25% royalty in most CPPs, 40-60% State tax oil, 70% cost-oil cap).
• The 2023 nationalisation and pending arbitrations weigh on perceived stability; obtain strong treaty and arbitration protection and political risk cover.
• A new Petroleum Code is moving through the government; its stated aim is to protect State interests, so terms for new entrants may tighten.
• Export logistics depend on the Chad-Cameroon pipeline, adding counterparty and transit considerations.
• CEMAC FX rules will require 50% and then 70% onshore repatriation of export proceeds from 2027-2028.

Oil and gas producer and OPEC member in steep decline: crude output reported at about 20,000 b/d in September 2026 versus about 140,000 b/d in 2020 (Bloomberg). Offshore Rio Muni and Douala/Bioko basins (Zafiro, Ceiba/Okume, Alba, Aseng). Gas monetised through the Punta Europa LNG/methanol complex (Gas Mega Hub); new gas deals with US firms signed 2025-2026; Yoyo-Yolanda cross-border gas agreement with Cameroon (February 3, 2026).

Key laws: Law No. 8/2006 of November 3, 2006, Hydrocarbons Law (2006-11-03); Petroleum Regulations (Ministerial Order No. 4/2013) (2013-06-20); Ministerial Order No. 1/2014 on National Content in the oil and gas sector (2014); Law No. 1/2024 of November 19, 2024, General Tax Law (Tax Code) (2024-11-19); New Hydrocarbons Law (announced) (2026); CEMAC Regulation on exchange regulation (2018-12-21); BEAC Instruction raising the repatriation rate for extractive companies (2026-04-23)

• Production has fallen sharply and the government is rewriting the hydrocarbons law to attract drilling; early entrants may negotiate bespoke terms, but the new law's text is not yet public.
• Expect a minimum 20% State interest plus GEPetrol pre-emption, a reported 35% local ownership requirement and strict staffing quotas.
• Lower headline CIT (25%) since 2025 improves the fiscal picture; most PSC terms remain contract-specific.
• ICSID access since 2024 is an improvement, but there is no New York Convention coverage and award enforcement has been difficult; structure for treaty or offshore enforcement.
• Gas monetisation through Punta Europa is the strategic focus.

Natural gas producer, no crude oil production. Onshore/near-shore gas from Songo Songo, Mnazi Bay and the Ntorya development supplies power and industry (over 301 bcf produced March 2021-March 2025). About 47 tcf of gas (47.13 tcf per the Minister, January 2026) in deepwater Blocks 1, 2 and 4 (Shell, Equinor, ExxonMobil, Medco, Pavilion, TPDC) underpins the planned Tanzania LNG project at Likong'o, Lindi (~US$42bn). Also host and 15% (via TPDC) shareholder of the EACOP crude export pipeline from Uganda to Tanga.

Key laws: Petroleum Act, 2015 (2015); Natural Wealth and Resources (Permanent Sovereignty) Act, 2017 (2017-07-05); Natural Wealth and Resources Contracts (Review and Re-negotiation of Unconscionable Terms) Act, 2017 (2017); Oil and Gas Revenues Management Act, 2015 (2015); Petroleum (Local Content) Regulations, 2017 (2017-05-18); Foreign Exchange Regulations, 2022 (as amended by Foreign Exchange (Amendment) Regulations, 2026) (2022 / 2026-07-17)

• Gas-focused jurisdiction with a world-scale (~47 tcf) but still unsigned LNG project; signing of the HGA and other agreements is the key milestone.
• TPDC carries a default 25% participating interest and gas aggregator rights; fiscal take includes 12.5%/7.5% royalty, 30% CIT and Additional Profits Tax.
• The 2017 sovereignty laws restrict foreign arbitration and permit parliamentary review of contract terms; a 2026 amendment, reported enacted in October 2026, reopens a narrow foreign-seat option for Cabinet-approved agreements.
• Local content and FX rules (local banks, insurers, TZS pricing, earnings retention) require early structuring.
• A fifth licensing round with an updated model PSA has been prepared but not yet launched.