Development programme drives EBITDA growth

9M26 provides clear evidence of operating improvement, with working-interest (WI) production reaching 43.0kboepd, facility uptime increasing to 96% and production opex declining to US$15.4/boe. Oando’s medium-term programme, comprising 62 development wells, 55 interventions and US$800m–1.0bn of upstream capex, targets more than 40kbopd of WI oil and 600mmscf/d of gas production by 2030. We model average output increasing from c 44kboepd in FY26 to 124kboepd in FY30, driving adjusted EBITDA from NGN225bn to NGN927bn, a c 42% CAGR, while EBITDA margin expands from 6.2% to 18.4% as higher-margin E&P becomes a larger contributor to group earnings.

Balance sheet restructuring is key to funding growth

The NAOC acquisition increased leverage after several years of deleveraging, making balance-sheet improvement important to the growth strategy. 9M26 showed meaningful progress, with gross borrowings declining to NGN2.16tn and net debt to c NGN1.99tn as stronger operating cash flow supported substantial debt repayments. Oando is also pursuing new equity, debt conversion, asset monetisation and refinancing. Our estimates include the Ebendo disposal but exclude the proposed equity raise and debt conversion. Successful execution of these measures would further reduce leverage and increase funding capacity.

Valuation: NGN188/share including 2C resources

Our 2P DCF implies c NGN176/share at a WACC of 13.5%. We value Oando’s 2C resources separately using the company-disclosed US$0.48/boe multiple, adding c NGN12/share and taking our combined value to c NGN188/share. Realising this value depends principally on delivery of the production ramp-up and funding of the associated development programme, with commodity prices and the discount rate also material sensitivities. Oando trades at a substantial discount to Nigerian peers on a reserve basis, while its forward EV/EBITDA multiples should decline significantly as production and earnings expand.

Company description: Nigerian integrated energy group

Oando is a Nigerian integrated energy group, with its principal operations in Exploration & Production (E&P) and Supply & Trading. The US$754m Nigerian Agip Oil Company (NAOC) acquisition, completed in August 2024, doubled its working interest in Oil Mining Leases (OMLs) 60–63 to 40% and transferred operatorship, materially increasing both the scale of the upstream portfolio and Oando’s control over capital allocation and development. The group reported 928mmboe of 2P reserves at end-FY25, of which c 61% is gas, compared with 9M26 working-interest production of 43.0kboepd. The reserve base is therefore large relative to current output. OMLs 60–63 also contain an established network of oil and gas processing, pipelines, export facilities and the Okpai power complex, allowing a substantial part of the planned production increase to use existing central infrastructure. 9M26 facility uptime of 96%, production opex of US$15.4/boe and 40.0kboepd of production from OMLs 60–63 indicate that the operating recovery has begun following the acquisition. Supply & Trading remains the dominant contributor to reported revenue, although the higher-margin E&P business should become progressively more important to group earnings and cash generation as production increases.

Financials: Production growth drives EBITDA and margin expansion

Oando targets more than 140kboepd of WI production by 2030, supported by US$800m–1.0bn of upstream investment. Recent operational improvements and deleveraging provide initial evidence of progress, increasing confidence in the company’s ability to deliver its medium-term targets. We model average production rising from c 44kboepd in FY26 to c 124kboepd in FY30, supported by c US$953m of upstream capex, with production opex declining to US$14/boe, below management’s US$15/boe target. Higher gas volumes and domestic contract repricing provide an additional source of growth as consensus oil prices normalise from currently elevated levels over the medium to long term, offering some diversification relative to more liquids-weighted producers. We forecast E&P revenue increasing from NGN777bn to NGN2.0tn, with its share of group revenue rising from c 21% to c 40%. Together with lower unit costs, this supports adjusted EBITDA growth from NGN225bn to c NGN927bn, a c 42% CAGR, with the group margin expanding from 6.2% to 18.4%. Net operating cash flow reaches NGN553bn by FY30, while net debt/EBITDA declines from 8.6x in FY26 to 2.1x. Alongside stronger internal cash generation, the ongoing balance sheet restructuring, including proposed equity issuance, debt conversion and refinancing, could further strengthen funding capacity for the development programme. Our base case incorporates the Ebendo disposal but excludes the proposed equity issuance and debt conversion.

Valuation: NPV of NGN188/share including 2C resources

Our 2P DCF at a 13.5% WACC gives a value of c NGN176/share, based on the existing capital structure and 9.44bn shares outstanding excluding treasury. We value the reported 2C resources separately using the company-disclosed US$0.48/boe multiple, adding c NGN12/share and taking the combined value to NGN188/share, c 470% above the current NGN33.1 price. The long duration of the reserve base and large net-debt deduction make the equity value particularly sensitive to the discount rate. Oando trades at c US$1.8/boe of 2P reserves compared with US$7.3/boe for Seplat and US$5.8/boe for Aradel, while its FY26–27 EV/EBITDA multiples remain substantially higher. On our medium-term estimates, the multiple declines to c 2.5x by FY30, below peers’ current forward trading ranges, as the enlarged reserve base is converted into production and earnings.

Sensitivities: Execution and balance sheet remain key

Execution of the 2026–30 growth programme remains the principal risk, alongside Nigeria’s operating and regulatory environment and the balance sheet. Our production assumptions require substantially higher drilling and depend on well productivity, facility availability, pipeline integrity and gas offtake. OMLs 60–63 require renewal and conversion under the Petroleum Industry Act ahead of their June 2027 expiry. With gross borrowings of c NGN2.16tn, the funding position remains a key risk. The proposed rights issue is priced above the current share price, and subject to regulatory approval, while the US$300m debt conversion terms remain undisclosed. Oil and gas prices and naira movements also affect earnings, cash generation and leverage.

Company description

Oando is a Nigerian energy group listed on the Nigerian Exchange and the Johannesburg Stock Exchange, with its principal operations in E&P and Supply & Trading. The upstream portfolio was materially enlarged by the US$754m acquisition of NAOC in August 2024, which doubled Oando’s working interest in OMLs 60–63 from 20% to 40% and transferred operatorship of the joint venture (JV) to the group. OMLs 60–63 now account for substantially all of the producing reserve base and c 93% of 9M26 WI production.

The company’s working-interest production averaged 43.0kboepd in 9M26, including 40.0kboepd from OMLs 60–63. Independently assessed 2P reserves stood at 928mmboe at end-FY25, comprising 332mmbbl of crude oil, 3.4tcf of gas and 27mmbbl of natural gas liquids (NGLs). Gas accounts for c 61% of the reserve base on a barrel of oil equivalent basis, leaving Oando with a materially larger gas exposure than its current production mix implies.

OMLs 60–63 comprise an established oil, gas and power system across the Niger Delta. The JV includes 12 flowstations, oil processing and export facilities, the Kwale and Obiafu-Obrikom gas plants, the Okpai power complex and approximately 1,190km of pipelines, together with supporting power and logistics infrastructure. Some export pipelines also carry third-party production. The installed infrastructure reduces the requirement for major new central processing capacity as production increases, although the maturity of the system creates an ongoing requirement for integrity, maintenance and security expenditure. 9M26 facility uptime of 96.1% and production opex of US$15.4/boe provide further evidence of the operating improvement across the enlarged portfolio.

Outside the producing portfolio, Oando has development interests in OML 90, OML 122, OML 131 and OML 145 and exploration interests in Nigeria, São Tomé and Príncipe and Angola. OML 131 is the most significant disclosed development asset by resource scale. Oando Trading remains the dominant contributor to reported revenue, while Clean Energy and Mining are still small relative to the upstream and trading businesses.

NAOC acquisition doubled exposure and transferred control

The US$754m acquisition of NAOC in August 2024 doubled Oando’s working interest in OMLs 60–63 from 20% to 40% and transferred operatorship of the JV to Oando. Following completion, NAOC was renamed Oando Energy Resources Nigeria Limited (OERNL). The original 20% interest had been acquired through the ConocoPhillips Nigerian transaction in 2014, leaving Oando as a minority non-operator in its principal producing assets for the following decade.

On the reserve estimates used around completion, the additional interest increased Oando’s 2P position from c 506mmboe to c 999mmboe, equivalent to approximately 493mmboe of incremental reserves. Subsequent independent assessments put group 2P at 950mmboe at end-FY24 and 928mmboe at end-FY25. The acquisition consideration therefore equates to c US$1.5/boe of incremental transaction-period 2P, before attributing separate value to the associated processing, pipeline, export and power infrastructure.

The low acquisition multiple was accompanied by a mature asset base operating below its production potential. Production had been affected by shut-in wells, pipeline and security disruption, constrained facility availability and deferred integrity work. Operatorship gives Oando control over drilling, interventions, maintenance and facility optimisation across the core portfolio, allowing capital to be directed towards both production recovery and new development.

Production from OMLs 60–63 increased from a working interest (WI) production of 21.3kboepd in FY24 to 29.7kboepd in FY25 and 40.0kboepd in 9M26. The latest improvement reflects new Idu wells, workovers and restoration of previously constrained facilities, with facility uptime reaching 96.1%. The seven-well FY26 campaign remains in progress and is expected to add c 16–20kboepd gross on completion, helping offset underlying field decline and support the next stage of the production ramp-up.

At current production, OMLs 60–63 remain lightly produced relative to the booked reserve base. The medium-term programme is therefore focused on increasing well deliverability and infrastructure utilisation to convert booked reserves into production, with funding and execution more important than near-term exploration success.

Reserves and resources

Oando maintained a broadly stable 2P reserve base of around 500mmboe for much of the decade before the NAOC transaction. The acquisition produced a major step-change in FY24, while subsequent reserve movements have been relatively modest.

Large, gas-weighted 2P reserve base

Oando reported independently assessed 2P reserves of 928mmboe at end-FY25, down 2% from a restated 950mmboe at end-FY24. Oil reserves declined 3% to 332mmbbl and gas reserves 2% to 3.4tcf, while NGL reserves fell slightly from 29mmbbl to 27mmbbl. Gas accounts for c 61% of total 2P based on barrels of oil equivalent, compared with c 36% for crude oil and c 3% for NGLs.

At 9M26 production of 43.0kboepd, the reserve base represents a reserve life of c 59 years. At the c 140kboepd implied by management’s 2030 oil and gas production targets, the same reserve base would still represent approximately 18 years of production on a static basis, before allowing for further reserve upgrades. Oando is therefore not reserve constrained at its current level of output; the rate of development and capital available to sustain higher production are more relevant to its medium-term profile. The booked position is overwhelmingly concentrated in OMLs 60–63. The scale of the reserve base relative to current output also differentiates Oando from the larger domestic peers.

2C resources provide additional development inventory

Oando reported 169mmboe of 2C resources at end-FY25, comprising 89mmbbl of oil and 478bscf of gas, up 4% year-on-year. The group does not disclose an asset-level reconciliation of these resources. OML 131 is one of the larger disclosed development positions: Oando owns 100% of the licence, while the Chota discovery is being unitised with the adjacent Bolia discovery in OML 135. The Bolia-Chota unit contains gross 2C resources of 241mmbbl of oil and 1tcf of gas, with a provisional 40% participating share allocated to Oando under the existing Pre-Unit Agreement. These gross unit resources and Oando’s provisional participation are not directly comparable with the group’s reported net 2C resources, for which the company has not provided an asset-level reconciliation.

Development remains at concept stage. A standalone leased-FPSO scheme had previously been considered for Bolia-Chota, while work during 2025 shifted towards oil and gas tie-back alternatives. Unitisation, licence renewal, final development configuration and capital requirements remain to be resolved. Given the absence of a group-wide asset-level 2C split, we value contingent resources separately using a resource multiple approach.

Operating portfolio

Production recovering after a prolonged decline

Oando’s production history reflects acquisition-led changes in working interest alongside field decline and periods of materially different operating availability. Production increased to c 53kboepd in 2015 following the first full-year contribution from the ConocoPhillips assets, remained around 39–45kboepd through 2020 and then fell to 26.8kboepd in 2021 and 20.7kboepd in 2022 as pipeline disruption, sabotage, shut-ins and lower investment reduced output.

Production recovered to 23.3kboepd in 2023 and 24.5kboepd in 2024, before increasing to 32.5kboepd in FY25 and 43.0kboepd in 9M26. The recent recovery combines the larger interest in OMLs 60–63 with higher underlying field output following the return of wells, improved facility availability and resumed development drilling.

OMLs 60–63: Mature conventional Niger Delta assets

The four licences cover more than 5,300km² across onshore and coastal-swamp areas of the Niger Delta. OML 60 covers c 358km², OML 61 c 1,499km², OML 62 c 1,221km² and OML 63 c 2,246km². The field complex contains producing oil, condensate and gas accumulations alongside undeveloped discoveries and exploration prospects.

Production is principally from stacked clastic sandstone reservoirs within the Agbada Formation, charged from the deeper Akata petroleum system. The portfolio has been extensively drilled and delineated over several decades, leaving the current development programme predominantly brownfield. Interventions, recompletions and new development wells can be tied into an established gathering, processing and evacuation system.

The mature operating system also carries material integrity requirements. Ageing pipelines, restrictions on in-line inspection caused by historical repairs, deferred tank inspections and other maintenance backlogs form part of the inherited operating position. Current integrity work includes pipeline inspection, cathodic-protection reinstatement, tank programmes and facility upgrades. Funding of maintenance remains relevant as the development programme accelerates.

Security has improved but remains an operating sensitivity. Spill incidents across the operated assets declined by 62% in 2025 and estimated spill volumes by 71%, while more than 88% of incidents remained associated with third-party interference. Higher surveillance and improved security have supported production recovery, but theft, sabotage and pipeline interference continue to affect evacuation and reconciliation losses.

The four OMLs are due to expire in June 2027 and require renewal and conversion to Petroleum Mining Leases under the Petroleum Industry Act. Our medium-term production assumptions implicitly assume successful renewal; this is therefore an important regulatory milestone ahead of the larger FY27–30 drilling programme.

Production recovery supported by uptime and lower costs

OMLs 60–63 WI production averaged 40.0kboepd in 9M26, up 16% y-o-y, comprising 10.6kbopd of crude oil, 27.3kboepd of gas and 2.1kbpd of NGLs. Crude production increased 14%, while gas and NGL output grew 15% and 53%, respectively.

Facility uptime increased to 96% from c 85% in 9M25 and production opex fell to US$15.4/boe from US$19.7/boe. Higher output improved fixed-cost absorption, while transport, logistics, service and ICT costs also declined. Reconciliation losses moderated to 2.8%, although security and pipeline integrity remain continuing constraints on delivered volumes.

Development drilling is contributing alongside the brownfield recovery. Idu 6ST and Idu 15 are complete and onstream, workovers at Samabri 4T and 7T have been completed, while Idu T and Samabri A50 were being drilled at the time of the 9M results. The seventh and final well, Ogbainbiri, is scheduled to spud in December. Oando expects the full campaign to add c 16–20kboepd gross, supporting plateau production and offsetting natural field decline.

Gas and power: Infrastructure ahead of current throughput

OMLs 60–63 have access to more than 2bscf/d of gas-processing capacity, compared with gross deliveries of c 233mmscf/d at the time of Oando’s March 2026 strategy presentation. Long-term gas sale agreements (GSAs) cover approximately 1.3bscf/d gross, principally with Nigeria Liquefied Natural Gas (NLNG), alongside industrial and power customers. The OERNL JV also includes the Okpai Independent Power Plant, with c 930MW of gross installed generation capacity and c 372MW attributable to Oando through its 40% JV interest.

The processing-capacity, contractual and current-delivery figures measure different parts of the gas system, but the scale differential is material. Higher gas sales require additional wells, compression, gathering capacity and reliable evacuation. Central processing capacity does not appear to be the immediate constraint, while existing infrastructure and contracted offtake should accommodate a substantial increase in production before requiring material expansion of central processing capacity or new sales agreements.

Gas utilisation was 92.4% in 9M26, broadly in line with 91.5% in 9M25. Completion of the Ob/Ob–Kwale reverse-flow project increased gas supply to Okpai by 80%, supporting higher power generation and demonstrating the potential to monetise additional gas through domestic power demand. Existing contracted volumes cover most of Oando’s 2030 gross gas-production target of 1.5bscf/d, implying a relatively modest requirement for new or expanded offtake arrangements.

The commercial framework should also evolve as production increases. Management expects realised gas prices to begin rising from FY27 as legacy contracts mature, with pricing moving towards US$2.4–3.0/mscf and more volumes directed to higher-value outlets. At Okpai, the original 20-year Nigerian Bulk Electricity Trading (NBET) power purchase agreement expired in December 2025 without renewal or exercise of the purchase option, and an interim energy-sales agreement became effective in January 2026. NBET continues to purchase electricity under the interim arrangement. The historical Okpai relationship also resulted in a significant receivable balance. The US$225m NBET receivable was factored in December 2025, with OERNL receiving US$213.75m in January 2026 at a 31 December 2025 value date. Cash collection therefore remains relevant to the economics of the power business alongside generation volumes and tariff terms.

Smaller producing assets

Qua Ibo is a 40%-owned oil field operated by Network E&P. Production averaged 384bopd WI in 9M26, down 29% year-on-year, primarily reflecting natural field decline. Oando’s end-FY25 2P interest was 3.9mmbbl.

Ebendo is a 45%-owned oil and gas asset operated by Energia. Production averaged 2,585boepd WI in 9M26, broadly unchanged year-on-year. End-FY25 2P reserves were 4.6mmboe. Oando agreed in June 2026 to sell its interest for US$48.45m plus closing adjustments, with a US$9.69m deposit received. The asset remained classified as held for sale at end-September.

Development and exploration portfolio

OML 131 is the most significant disclosed development asset. In addition to Bolia-Chota, the licence contains the Ebitemi discovery and several prospects including Chota East, Chota North and Ebipre. Both standalone and tie-back concepts remain under consideration, including potential connections to neighbouring developments. The development timetable remains dependent on unitisation, licence renewal and selection of an economically viable evacuation route.

OML 145 is a 21.05%-owned deepwater position operated by ExxonMobil and contains the Uge, Orso, Uge North and Nza discoveries. A leased-FPSO early-production concept has previously been assessed; recent work has focused on improved seismic imaging and further development definition. OML 90 contains the undeveloped Akepo field in shallow water. OML 122 contains the Bilabri, Orobiri and Owanare discoveries, but a long-running funding and legal dispute with the operator limits near-term development visibility.

The exploration portfolio includes positions in Nigeria, São Tomé and Príncipe and Angola. In Angola, Oando holds a 45% participating interest and operatorship of KON-13 in the onshore Kwanza Basin. Following execution of the production-sharing contract in March 2026, the contractor group has continued technical studies and is preparing a 2D seismic acquisition programme ahead of a potential exploration-well phase. Oando also holds interests in OPLs 321 and 323 through Equator Exploration. The deepwater Nigerian licences contain several identified prospects, but their licence position remains subject to a long-running legal and commercial dispute. We therefore treat them separately from the group’s active exploration programme.

Trading provides a separate commercial platform

Supply & Trading generates the majority of group revenue but operates at much lower margins than E&P. The business has been repositioned following the structural change in Nigeria’s refined-products market, reducing exposure to lower-margin PMS imports and focusing more heavily on crude oil alongside selected refined-product and gas opportunities.

Crude volumes were 17.5mmbbl in 9M26, down 12% year-on-year, although the number of cargoes increased to 32 from 21 as activity shifted towards smaller parcels and greater sourcing from marginal-field producers. Supply & Trading external revenue was broadly stable at NGN2.22tn. The lower volumes partly reflect changes to one NNPC-linked crude-marketing programme following the introduction of a new crude-backed financing structure rather than a reduction in the group’s underlying trading capability.

FY26 crude-trading guidance remains 22–26mmbbl, compared with 25.7mmbbl in FY25. Oando also expects to expand refined-products activity as commercial opportunities develop. Trading therefore remains commercially relevant and an important contributor to group liquidity and crude marketing, although its high-turnover, low-margin economics mean its contribution to earnings is considerably smaller than its share of reported revenue.

Clean Energy and Mining remain early stage

Oando Clean Energy is focused on electric mobility, recycling and renewable-energy projects, although the business remains early stage relative to the core operations. In electric mobility, the Lagos e-bus service recorded more than 212,000 rides in 9M26 at 73% average capacity utilisation. A further 11 buses have arrived, taking the fleet to 13, with the enlarged fleet expected to enter service in Q426. In PET recycling, land title has been secured for the planned 2,750t/month facility in Ogun State, with due diligence ongoing.

Oando Mining is building a portfolio across tin, lithium, gold and bitumen, with tin currently the most advanced development opportunity. Following resource evaluation and development planning during H126, the company reported that it is targeting Q227 for the start-up of its Bauchi tin project. Earlier disclosures envisaged small-scale or light-mechanised operation aimed at generating early revenues, although Oando has not yet provided public information on the project’s resource, planned production capacity, capex or economics. With tin prices remaining close to historically high levels, even a relatively small-scale initial operation could represent a visible source of cash flow and value. The group is also assessing lithium licences in Southwest Nigeria and advancing gold exploration in Kebbi State. We currently assign no value to Mining, although commencement of the Bauchi project and disclosure of its economics could provide a basis for valuation.

Management

Oando is led by a long-standing executive team. Group Chief Executive Jubril Adewale Tinubu and Deputy Group Chief Executive Omamofe Boyo have served on the board since 2000 and have overseen the group through the ConocoPhillips and NAOC acquisitions as well as the earlier disposals of downstream and midstream assets. Group CFO Adeola Ogunsemi joined Oando in 2009 and was appointed to the board in 2022, with prior experience at BP and across fund-raising, M&A and JV finance. Alex Irune, executive director and managing director of Oando Energy Resources Nigeria, leads the operated upstream business.

The board comprised 12 directors at end-FY25, including five executive and seven non-executive directors, of whom five were independent. The board structure has expanded alongside the enlarged operating portfolio, including greater independent representation in audit, risk and strategic-planning oversight.

Oando in the industry context

Nigeria: Large resource base and recovering production

Nigeria combines a very large hydrocarbon resource base with production materially below historical capacity. Oil and condensate production averaged c 1.63mmbpd in 2025, peaking at around 1.73mmbpd early in the year before easing towards year-end. Output improved relative to the disruption seen earlier in the decade, supported by better security and reopening of shut-in production, but ageing infrastructure, theft, maintenance and evacuation constraints remain significant across the Niger Delta.

The regulatory focus on restoring shut-in production, reducing losses and accelerating brownfield development is particularly relevant to Oando's OMLs 60–63 programme. National targets call for oil production of 2mmbpd and gas production of 10bscfpd by 2027, rising to 3mmbpd and 12bscfpd, respectively, by 2030.

The structure of the upstream sector is also changing. IOC divestments have transferred large mature onshore and shallow-water portfolios to domestic operators, including Oando’s acquisition of NAOC, Seplat’s acquisition of Mobil Producing Nigeria Unlimited (MPNU) and the transfer of Shell’s former onshore position into Renaissance. These transactions have created a group of materially larger Nigerian operators with responsibility for assets that require both higher reinvestment and improved operating availability.

The Petroleum Industry Act has provided a clearer fiscal and licensing framework, while regulatory enforcement has tightened around royalty payments, statutory obligations and export approvals. For mature operators with large legacy liabilities, compliance and liquidity are therefore directly connected to operating continuity as well as financing. Oando’s OMLs 60–63 renewal ahead of June 2027 sits within this broader transition.

Gas has a different demand backdrop. Nigeria has more than 200tcf of gas reserves but persistent shortages in electricity and industrial energy supply. Available grid generation was only c 4.3GW against 13.6GW of installed capacity in April 2026. Oando’s gas reserve base, processing capacity and power interests give it direct exposure to domestic gas and power demand, alongside its established NLNG contracts.

Nigeria’s domestic gas market remains partly regulated, with pricing differentiated by end-user. The domestic base price for 2026 was set at US$2.18/mmBtu for the power sector, while commercial customers pay US$2.68/mmBtu and gas-based industries operate within a separate regulated band. The framework is intended to provide progressively more cost-reflective pricing while retaining differentiated prices for strategic sectors. For producers such as Oando, realised pricing also depends on the legacy contract mix: older fixed-price GSAs can sit below prevailing domestic reference prices, creating scope for improved realisations as contracts mature and volumes are redirected towards higher-value industrial and power customers.

In addition, operating conditions remain an important consideration. Security, pipeline interference, evacuation availability and host-community relations have historically affected production across the Niger Delta. Oando's recent improvement in uptime and reconciliation losses demonstrates that these variables can materially affect production from an unchanged subsurface reserve base.

Industry positioning

Oando’s most relevant domestic peers are Seplat Energy and Aradel Holdings, both of which have also expanded materially through acquisitions. The comparison below highlights the gap between Oando’s reserve position and current production.

Oando’s 928mmboe 2P reserve base is equivalent to c 93% of Seplat’s 1,001mmboe and significantly above the c 665mmboe pro forma figure for Aradel, while 9M26 production of 43kboepd was only c 30% of the 145kboepd reported by both peers. On a simple static basis, Oando’s reserve life is therefore around 59 years, compared with roughly 20 years for Seplat and 13 years for Aradel, although the reserve reporting bases are not fully like-for-like.

Oando’s reserve mix is also more gas weighted, with gas representing c 61% of 2P. Despite its materially lower production base, 9M26 production opex of US$15.4/boe compares favourably with Seplat’s US$16.0/boe, which includes c US$1.8/boe of additional Yoho restoration costs. Aradel reported significantly lower field operating costs of US$7.9/boe, although differences in cost definitions and portfolio composition limit direct comparability. These benchmarks, alongside Oando’s recent cost reductions discussed below, suggest scope for production opex to decline below the company’s US$15/boe medium-term target as volumes increase. At the same time, Oando’s balance sheet remains much more leveraged, with 9M26 net debt of US$1,493m compared with US$284m for Seplat and US$347m of net cash for Aradel.

Growth strategy: Transformational expansion

Development activity to step up after FY26

Oando is moving from post-acquisition recovery into a materially larger development programme. 9M26 production averaged 43.0kboepd, within the narrowed FY26 guidance range of 40–45kboepd. The current seven-well OMLs 60–63 campaign is progressing, with two development wells and two workovers completed, two wells being drilled at the time of the 9M results and the final well scheduled to spud in December. Management expects the FY26 campaign to add c 16–20kboepd gross once completed. Upstream capex was approximately US$81m in 9M26 against FY26 guidance of US$90–100m.

Beyond the current programme, Oando’s 2026–30 development framework comprises 62 development wells, 55 interventions and US$800m–1.0bn of attributable upstream expenditure. Management is targeting more than 40kbopd of WI oil production and 600mmscf/d of WI gas production by 2030. The programme remains predominantly brownfield, with new wells and interventions directed at known reservoirs and tied into existing facilities.

This implies a significant increase in activity post-FY26. Deducting current-year capex guidance leaves approximately US$700–910m of the medium-term framework for FY27–30, equivalent to c US$175–228m per year. Geological delineation and installed infrastructure reduce greenfield development risk, but well productivity, facility integrity, evacuation capacity and funding availability will determine the pace at which the reserve base is converted into production.

Gas production can increase within existing processing capacity

Consistent with the company’s gas-weighted reserves, gas is expected to account for a substantial part of the production increase, with Oando targeting 600mmscf/d WI, or 1.5bscf/d gross, by 2030. Existing processing capacity of more than 2bscf/d appears sufficient to accommodate much of the planned increase, leaving drilling, compression, gathering infrastructure and facility upgrades as the more immediate requirements.

Long-term contracted volumes of approximately 1.3bscf/d gross also cover most of the 2030 production target, reducing the requirement for incremental offtake as volumes increase. Contract repricing should provide an additional earnings benefit as legacy gas agreements mature.

Cost target largely achieved ahead of schedule

Oando’s August 2026 medium-term framework set a 2030 production-opex target of US$15/boe from a reference base of approximately US$23/boe. Cost reduction has progressed rapidly, with production opex declining to an estimated US$12.6/boe in Q326 and US$15.4/boe in 9M26, from US$19.7/boe a year earlier and US$16.8/boe in H126. The reduction reflects ongoing savings in transport, logistics, services and ICT, alongside improved absorption of the largely fixed field-cost base as production increased.

With current unit costs already close to, and most recently below, the 2030 target, the focus shifts from achieving US$15/boe to maintaining a mid-teens cost base as drilling, intervention and integrity activity increases materially. Higher production should support further fixed-cost absorption, although absolute operating expenditure will increase as the upstream business scales. The integration programme also includes broader organisational savings. Workforce restructuring following the NAOC acquisition is expected to generate approximately NGN30bn of annualised savings, although this sits primarily outside the production opex KPI and should not be double-counted with field-cost savings.

Balance sheet transformation

First signs of deleveraging post NAOC acquisition

Oando materially reduced leverage following the 2014 ConocoPhillips acquisition, with debt declining substantially through 2018 as assets were divested and acquisition facilities repaid. The US$754m NAOC transaction reversed part of this progress, with acquisition financing and subsequent funding of the enlarged JV increasing gross borrowings to c NGN2.70tn at end-FY25.

Deleveraging accelerated during 9M26 as higher production, stronger realised pricing and lower unit costs improved operating cash flow. Cash generated from operations before interest and tax reached NGN285bn, while repayments of NGN793bn exceeded new borrowings of NGN458bn. Gross debt consequently declined 20% from year-end to NGN2.16tn and net debt fell by NGN286bn to NGN1.99tn, taking gross borrowings 22% below the post-acquisition peak of NGN2.77tn at end-FY24.

However, further deleveraging is required ahead of the larger development programme as the company anticipates upstream expenditure of US$800m–1.0bn over 2026–30, with capex and drilling activity increasing significantly from FY27. While higher production and cost reductions should continue driving internally generated cash flow, execution of the planned development programme will also require continued access to lower-cost external capital.

Debt remains predominantly US dollar denominated and expensive

At end-FY25, term loans represented c 37% of gross borrowings, reserve-based lending (RBL) facilities 27%, project finance 16% and the corporate facility 13%, with working-capital and trade-finance facilities accounting for the remaining c 7%. The majority of borrowings are denominated in US dollars, broadly matching the currency of upstream and Trading revenues but increasing the reported naira liability when the local currency weakens.

Near-term liquidity remains relatively constrained, with current borrowings representing c 77% of total debt at end-FY25 and c 75% at end-September 2026, despite the reduction in total debt during the period. While the restructuring of the Corporate Facility and Medium-Term Loan has cleared outstanding principal and interest arrears and restored the facilities to good standing, improving the near-term funding position, it has not removed the broader refinancing requirement.

At the same time, funding costs remain high. Average interest rates on the principal RBL, corporate, term and project-finance facilities were approximately 12–14% at FY25, with working-capital facilities at c 14.5% and trade finance at c 19.5%. Finance costs amounted to NGN244bn in 9M26, while cash interest of NGN144bn absorbed approximately 50% of cash generated from operations before interest and tax.

The FY25 contractual maturity profile included c NGN242bn due in 2026, NGN157bn in 2027 and NGN126bn in 2028, followed by larger maturities of c NGN428bn in 2029, NGN736bn in 2031 and NGN288bn in 2037. This profile predates the 2026 restructuring of the Corporate Facility and Medium-Term Loan but illustrates the refinancing requirement that the wider capital-management programme is intended to address.

Several routes to a lower funding burden

Alongside the expected increase in operating cash generation Oando is pursuing several measures aimed at reducing the debt burden. These include an equity raise of up to NGN500bn in two tranches expected by Q426 and Q127, conversion of up to US$300m of existing debt into equity, asset disposals and a US$1.5bn multi-instrument issuance programme. The initial rights-issue application has been filed with the Securities and Exchange Commission. The multi-instrument issuance is primarily intended to refinance existing obligations at longer maturities and lower funding costs, with documentation being updated for resubmission following SEC feedback. Management targets completion of the wider restructuring by end-Q127.

The US$48.45m Ebendo disposal is the most advanced asset monetisation initiative and provides a defined source of non-dilutive liquidity. Higher upstream cash generation, asset monetisation and refinancing could reduce leverage and funding costs. The proposed equity raise and debt-to-equity conversion would reduce debt more directly but increase the equity base. A further c 3.0bn treasury shares remain following the completed shareholder distributions, providing additional capital-structure flexibility, although no specific monetisation programme has been announced.

Financials

Historical financial performance

Oando’s historical financial performance combines changes in upstream production with a much larger, low-margin Trading revenue base and substantial movements in foreign exchange, impairments and other accounting items. The company’s revenue increased from NGN477bn in FY20 to NGN2.85tn in FY23 despite production declining from 44.6kboepd to 23.3kboepd, as higher commodity prices, greater Trading volumes and naira depreciation more than offset lower oil and gas output. Realised oil prices increased from US$34.2/bbl in FY20 to US$109.6/bbl in FY22, while crude traded rose from 16.1mmbbl to 32.8mmbbl by FY23.

Reported profits have been considerably more volatile than the underlying operating trend. Asset impairments and reversals, foreign-exchange movements and acquisition accounting have had a pronounced effect on headline earnings. FY24 operating profit included the bargain-purchase effect from the NAOC acquisition, while FY25 recorded a NGN2.8bn gross loss but NGN241bn of operating profit following large impairment reversals and other below-gross-profit items. Gross profit, adjusted EBITDA and cash flow generation therefore provide more useful measures of underlying operating performance.

The NAOC acquisition reset both the company’s production and the cost base. FY25 working-interest production increased 32% to 32.5kboepd and upstream capex rose materially, reflecting the first full year of the enlarged asset base and the return to development activity, while Trading revenue declined as Nigerian refined-product imports were reduced. Cash generation also improved, with cash generated from operations before interest and tax amounting to NGN258bn, although interest and tax payments reduced net operating cash flow to only c NGN32bn.

Revenue mix: Trading dominates turnover, E&P increasingly drives earnings

Oando’s reported revenue is dominated by Supply & Trading, although the revenue split overstates the relative economic weight of the business. Physical crude and product trading generates high turnover on thin margins and requires substantial working-capital and trade-finance investment. The trading business generated c US$1.7bn of revenue and US$11m of net profit in FY25, while crude volumes increased 24% to 25.7mmbbl. The 26% decline in trading revenue reflected lower refined-product activity following the start-up of domestic refining capacity and weaker commodity prices, despite higher crude volumes.

The enlarged upstream portfolio is gradually changing the group mix, a trend we expect to continue as production continues to scale. E&P external revenue was c NGN446bn in FY25, equivalent to c 14% of group revenue, and increased further to NGN554bn in 9M26, or c 20% of the group total. Oil accounted for c 68% of FY25 E&P revenue and c 72% in 9M26, while gas represented c 20% and c 19%, respectively. NGLs, IPP, pipeline income and other activities contributed the balance. The gas-weighted reserve base and substantial spare processing and power capacity provide scope for gas, power and infrastructure income to become more significant over time.

The change is more pronounced at the earnings level. E&P generated segment operating profit of NGN184bn in 9M26 compared with a NGN139bn loss in 9M25, while Supply & Trading recorded a NGN28bn operating loss on NGN2.22tn of external revenue. While Trading is likely to remain the largest contributor to reported revenue, we expect group earnings and cash generation to become increasingly driven by E&P. Upstream is structurally higher-margin than the high-turnover, low-margin Trading business, so a rising E&P contribution should support group profitability. At the same time, trading business will remain important to crude marketing and liquidity, although its scale means relatively small working-capital movements can materially affect cash flow.

9M26 results: Upstream recovery drives earnings, cash flow and deleveraging

Oando’s 9M26 results showed continued improvement across the upstream business, with higher production, lower unit costs and reduced leverage. Average production increased 14% year-on-year to 43.0kboepd, supported by new wells, workovers and higher facility availability. E&P external revenue consequently increased 58% to NGN554bn from NGN349bn, while Trading revenue was broadly flat at NGN2.22tn. Group revenue rose 9% to NGN2.78tn. Q3 showed a further step-up in upstream activity, with E&P external revenue increasing to NGN209bn from NGN82bn a year earlier.

The stronger revenue contribution was accompanied by a further reduction in unit costs. Production opex declined 22% to US$15.4/boe in 9M26 from US$19.7/boe, with our calculations implying Q3 opex of just c US$12.6/boe, around 25% below H126. The reduction reflected higher production over a largely fixed field-cost base as well as savings across transport, logistics, services and ICT. As a result, E&P operating profit increased to NGN184bn from a NGN139bn loss in 9M25, including NGN134bn in Q3. At group level, gross profit increased to NGN175bn from NGN30bn, company adjusted EBITDA improved to NGN182bn from negative NGN194bn and operating profit reached NGN160bn versus a NGN110bn loss. At the same time, reported PAT declined 47% to NGN106bn, principally reflecting the absence of substantial non-recurring finance income recognised in the prior period.

The earnings improvement also translated into stronger cash flow generation and accelerated balance-sheet deleveraging. Cash generated from operations before interest and tax reached NGN285bn in 9M26, supported by a NGN77bn working-capital inflow, while net operating cash flow was NGN218bn compared with a NGN235bn outflow in 9M25. Q3 net operating cash flow remained strong at c NGN108bn against capex of c NGN29bn. Oando repaid c NGN461bn of borrowings during the quarter against only c NGN20bn of new proceeds, reducing gross debt from NGN2.70tn at H126 to NGN2.16tn at end-September. Cash declined from NGN545bn to NGN176bn over the same period, partly funding the repayments, while net debt fell by c NGN170bn to NGN1.99tn.

FY26 guidance: Production range narrowed, capex on track

Oando narrowed FY26 WI production guidance to 40–45kboepd from 40–50kboepd previously, with 9M26 production of 43.0kboepd within the revised range. The seven-well OMLs 60–63 campaign remains on track, with the final Ogbainbiri well scheduled to spud in December. Management expects the completed programme to add c 16–20kboepd gross and support plateau production.

Upstream capex guidance remains US$90–100m, with approximately US$81m deployed by end-September, leaving c US$9–19m for Q4. Crude-trading guidance was also maintained at 22–26mmbbl following the earlier reduction from 30–35mmbbl, with 9M26 volumes of 17.5mmbbl implying 4.5–8.5mmbbl in Q4 to reach the full-year range.

Production opex of US$15.4/boe in 9M26 was already comfortably below the previous FY26 target of below US$18/boe, although no updated cost target was included in the 9M outlook.

Treasury-share distributions provide an additional shareholder return

Oando acquired 4.28bn of its own shares in FY25 following settlement of a shareholder loan, with the shares subsequently recognised as treasury shares. Shareholders approved a phased pro rata distribution of part of this holding, with 679.4m shares distributed in the first tranche and a further 604.3m shares in H126. In total, c 1.28bn treasury shares have therefore been returned to eligible shareholders.

The distributions reduced the treasury-share balance from 3.6bn at end-FY25 to c 3.0bn at end-September 2026, while increasing ordinary shares in circulation to c 9.4bn. A further c 3.0bn treasury shares remain available, with their eventual treatment dependent on future shareholder and board decisions. We view the completed distributions as an additional form of shareholder return alongside the broader balance-sheet and capital-allocation programme.

Operating assumptions and financial forecasts

Our estimates are based on Oando’s published 2026–30 development framework and 2030 targets of more than 40kbopd of WI oil production and 600mmscf/d of WI gas production. We use company guidance and medium-term targets where available, supplemented by our assumptions on the annual phasing of production, development activity and capex, underlying field decline, sales volumes, commodity pricing and funding. We model E&P by oil, gas and NGL production and sales, with Supply & Trading forecast separately.

Our key modelling assumptions are as follows:

• Production: We model average WI production increasing from c 44kboepd in FY26 to c 124kboepd in FY30, with an FY30 exit rate of c 136kboepd, broadly in line with the c 140kboepd implied by management’s oil and gas targets. We assume underlying decline of 15% pa for oil and 7% pa for gas and NGLs. The production build reflects the combined contribution of new drilling, well interventions, restoration of existing production, higher facility availability and debottlenecking across the OMLs 60–63 system.
• Development programme: Oando’s 2026–30 framework includes 62 development wells, 55 interventions and US$800m–1.0bn of attributable upstream investment. Public disclosure is insufficient to model the programme reliably on a well-by-well basis, particularly given the contribution expected from interventions, infrastructure upgrades and restoration of constrained production. We therefore model the production ramp-up at portfolio level, informed by management’s disclosed activity programme, current operating performance and medium-term production targets. On our assumptions, upstream capex totals c US$953m over FY26–30, within the company’s stated framework.
• Production costs: We assume production opex averages c US$15.3/boe in FY26 before declining towards c US$14/boe as production scales. This is modestly below Oando’s US$15/boe 2030 target, but is supported by the strong cost performance in 9M26 and the implied Q326 level of c US$12.6/boe. While we do not assume that this run-rate is sustainable as drilling, intervention and integrity activity increases, we see some scope for unit costs to outperform our assumptions. Our forecasts reflect further fixed-cost absorption from higher production alongside a higher absolute field-cost base as the development programme expands.
• Sales volumes: We normalise oil liftings towards production and assume progressively higher gas commercialisation as field output increases. Gas sales rise from c 73% of production in FY26 to around 90% by FY30, reflecting higher utilisation of existing processing and contracted offtake capacity rather than significant new central processing infrastructure.
• Commodity prices: Nigerian crude pricing is broadly linked to international benchmarks. We use consensus oil price assumptions of c US$90/bbl in FY26, US$83/bbl in FY27 and US$72/bbl in FY28, declining to a long-term US$70/bbl. Realised gas pricing increases from c US$2.3/mscf in FY26 towards c US$3.25/mscf by FY30. This increase is driven by gradual repricing of legacy contracts and a greater contribution from higher-value domestic sales rather than convergence towards international gas benchmarks.
• Forex: We assume an average exchange rate of c NGN1,380/US$ from FY27. A significant proportion of Oando’s revenue is effectively US dollar-linked, while a substantial part of the operating cost base is incurred in naira. A weaker naira therefore supports reported naira revenues and reduces the US dollar equivalent of local costs, with a stronger naira having the opposite effect. This operating exposure is partly offset at the balance-sheet level by the predominantly US dollar-denominated debt, which increases in naira terms when the local currency weakens.
• Trading: We assume FY26 crude-trading volumes broadly in line with the lower end of management’s 22–26mmbbl guidance, followed by a gradual recovery towards c 30mmbbl pa. Trading remains a high-turnover, low-margin business in our forecasts and therefore contributes considerably less to earnings than its share of group revenue.
• Long-term assumptions: Beyond FY30, we maintain the FY30 production level through FY40, supported by continued development expenditure to offset field decline, before production declines towards depletion of the existing 2P reserve base. Long-term Brent is held at US$70/bbl, production opex at US$14/boe and gas price at US$3.25/mscf, with no terminal value assigned to residual upstream reserves.

Earnings forecast and margin expansion

The production ramp-up drives a progressively larger contribution from the higher-margin E&P business. We forecast group revenue increasing from c NGN3.63tn in FY26 to NGN5.04tn in FY30 despite consensus oil price assumptions declining from c US$90/bbl to US$70/bbl over the period. This partly reflects Oando’s gas-weighted growth profile and its significant exposure to the domestic gas market, with our realised gas price assumption rising from c US$2.3/mscf to US$3.25/mscf as legacy domestic contracts are repriced and incremental volumes are directed towards higher-value outlets. Higher gas volumes and prices therefore partly offset declining oil prices, providing an additional source of growth and higher earnings visibility compared to more liquids-weighted producers. E&P revenue increases from c NGN777bn to c NGN2.0tn, raising its share of group revenue from c 21% to c 40%.

We expect profitability to improve substantially faster than revenue, reflecting both operating leverage within E&P and the changing composition of group earnings. Higher production volumes, lower unit operating costs and improved fixed-cost absorption support upstream margins, while the increasing weight of E&P relative to the high-turnover, low-margin Trading business lifts consolidated profitability. As a result, we forecast adjusted EBITDA increasing from c NGN225bn in FY26 to c NGN927bn in FY30, equivalent to a c 42% CAGR, with the group EBITDA margin expanding from 6.2% to 18.4%.

The existing debt burden delays the recovery in pre-tax earnings, with PBT remaining negative through FY28 before turning positive in FY29. Thereafter, the combination of operating and financial leverage drives a more pronounced recovery in net profit and EPS, as higher production and margins translate into stronger operating earnings while financing costs are absorbed by a substantially larger earnings base.

Our forecasts are most sensitive to production delivery, commodity prices and operating costs, with changes in upstream assumptions having a considerably greater impact on EBITDA than on consolidated revenue given the significant top line contribution from the lower-margin Trading business. Based on our estimates, a 10% reduction in E&P production would lower FY30e EBITDA by c 12%, while a 10% decline in benchmark oil prices would reduce EBITDA by c 13%. A 10% reduction in realised gas prices would have a smaller but still material impact of c 8%, reflecting the increasing contribution from domestic gas sales. The existing debt burden amplifies these effects on leverage, with net debt/EBITDA increasing from 2.1x in our base case to 2.7x, 2.8x and 2.4x, respectively.

Cash generation improves, supporting deleveraging

We expect cash generation to improve significantly over the forecast period, although substantial interest payments and rising development expenditure constrain free cash flow in the initial years. Net operating cash flow is forecast at c NGN245bn in FY26, increasing to c NGN553bn by FY30 as upstream earnings expand. Annual capex rises from c NGN138bn in FY26 to c NGN333bn by FY30, reflecting the acceleration of the development programme. We forecast negative free cash flow in FY27–28, before a recovery to c NGN51bn in FY29 and c NGN220bn in FY30, equivalent to c 24% of adjusted EBITDA.

The improvement in cash generation supports a gradual reduction in leverage despite the substantial investment programme. Our base case incorporates the Ebendo disposal and assumes a gradual reduction in borrowing costs, but excludes the proposed rights issue and debt-to-equity conversion given uncertainty over their timing and terms. Net debt increases from c NGN1.93tn in FY26 to a peak of c NGN2.21tn in FY28 before declining to c NGN1.93tn by FY30. Our forecasts include c NGN145bn of additional borrowing in FY28 to fund the investment programme. Combined with EBITDA growth, this reduces net debt/EBITDA from 8.6x to 2.1x, while EBITDA/cash interest coverage improves from c 1.1x to 3.7x. Successful execution of the wider balance-sheet restructuring programme could accelerate deleveraging and further reduce financing costs.

Valuation: Combined 2P and 2C value of NGN188/share

We value Oando’s 2P reserves using a DCF approach at our 13.5% WACC, with Supply & Trading included in the consolidated cash-flow forecasts. To this, we add the value of the 2C resources derived using the company-disclosed resource multiple. Our combined equity valuation is NGN1.77tn, equivalent to NGN188/share.

2P discounted cash flow: NPV of NGN176/share

We value Oando’s 2P reserve base using the production, cost and capital assumptions outlined above. On our estimates, production reaches an exit rate of c 136kboepd by FY30e and is maintained through FY40e with continued development expenditure to offset field decline, before declining towards depletion of the existing 2P reserve base. We do not apply a terminal value to the upstream assets.

Applying a 13.5% discount rate, we derive an enterprise value of c NGN3.6tn. After deducting NGN1.93tn of FY26e closing net debt, this gives an equity value of c NGN1.66tn, equivalent to NGN176/share, using 9.44bn ordinary shares outstanding excluding the remaining c 3.0bn treasury shares. The valuation is based on end-FY26 cash flows and net debt, with the Ebendo disposal already incorporated in our forecasts.

Our calculated WACC of c 13.5% reflects Oando’s current capital structure and its cost of capital. It is based on the Nigerian equity-risk premium of 12.6% (source: Damodaran) and an assumed 12.5% cost of debt. Oando’s high debt weighting and lower cost of debt versus equity partly moderates the discount rate, although the large net debt position significantly reduces the equity value attributable to shareholders. Cash-tax assumptions incorporate US$1.33bn of reported petroleum-profits-tax losses, US$730m of company-income-tax losses and US$729m of unused capital allowances, which we understand have no expiry, subject to their utilisation by the relevant taxable entities.

The long duration of the company’s reserve base makes the valuation particularly sensitive to the discount rate. At a 12% discount rate, the 2P value increases to c NGN220/share, while at 15% it declines to c NGN137/share.

Balance sheet restructuring scenario

Our central valuation uses the existing capital structure. The proposed restructuring would reduce debt but also increase the number of shares outstanding, and we therefore consider the effect of the announced equity measures separately.

The initial proposed rights issue would raise c NGN220bn through the issuance of 4.42bn shares at NGN50/share. Assuming the proceeds are applied to debt repayment, net debt would fall to c NGN1.71tn and the share count would increase to c 13.85bn. On an NPV basis, the resulting 2P value is approximately NGN136/share, compared with NGN176/share under the current capital structure. The reduction in per-share value reflects the proposed NGN50 issue price being below our pre-transaction NPV. The transaction would therefore materially improve leverage but dilute per-share value for existing shareholders on these assumptions.

The proposed conversion of up to US$300m of RBL debt provides scope for a further reduction in leverage, although the conversion price has not been disclosed. For illustration, assuming conversion at NGN50/share would reduce net debt by a further c NGN415bn and add approximately 8.3bn new shares, resulting in a 2P NPV of c NGN104/share.

The principal benefit of the combined restructuring is therefore a stronger balance sheet, greater capacity to fund the development programme and potentially lower financing costs. Addressing the balance-sheet and funding constraints could also reduce the risk premium currently reflected in the shares.

2C resources add c NGN12/share

Oando reported 169mmboe of 2C resources at end-FY25. Asset-level disclosure is insufficient to construct bottom-up field development models, and we therefore adopt a resource multiple approach. We use US$0.48/boe, the benchmark applied by Oando in its FY25 assessment of exploration and evaluation assets for impairment, based on comparable market transactions and forward commodity price assumptions. We consider this a conservative approach compared with Oando’s current multiple of c US$1.6/boe of combined 2P reserves and 2C resources, although the discount also reflects the greater development uncertainty associated with contingent resources. Applying the multiple to the reported 2C resource base gives a value of c US$81m, equivalent to c NGN110bn or approximately NGN12/share.

Peer group valuation

We view Seplat Energy and Aradel Holdings as Oando’s closest listed Nigerian comparators. Both have substantial Nigerian upstream portfolios and have expanded materially through recent acquisitions, providing a more relevant comparison than a broader international E&P peer group.

Oando continues to trade at a substantial discount to peers on a reserve basis. Its current enterprise value of c US$1.71bn (excluding treasury shares) equates to US$1.8/boe of 2P reserves, compared with US$7.3/boe for Seplat and US$5.8/boe for Aradel, discounts of c 75% and 68%, respectively. This partly reflects the much lower current monetisation of Oando’s reserve base: its 928mmboe of 2P is close to Seplat’s 1,001mmboe, while 9M26 production of 43kboepd was only c 30% of the output reported by either peer.

The company’s near-term earnings multiples remain elevated, at 10.2x FY26e EV/EBITDA and 7.5x FY27e, compared with 3.2–3.3x and 3.4–4.1x for the peers. However, these multiples capture Oando in the early stages of the planned production ramp-up. Our estimates imply adjusted EBITDA increasing from NGN225bn in FY26e to NGN927bn in FY30e, equivalent to a c 42% CAGR, as average production rises from 44kboepd to 124kboepd and unit costs decline. On our forecasts, Oando’s EV/EBITDA multiple falls to c 2.5x by FY30e, below the peers’ current forward trading ranges.

The peer comparison therefore becomes more supportive as the development programme progresses. Delivery of the production and cost targets would materially narrow the gap in production and earnings while Oando would retain a sizeable discount on its reserve base. While the pace of this convergence remains dependent on development execution and the balance sheet programme, our medium-term forecasts reflect a substantially different earnings profile from that reflected in the FY26–27 multiples.

Risks and sensitivities

Oando’s valuation remains sensitive to delivery of the operating and balance sheet transformation. The principal risks relate to the Nigerian operating and regulatory environment, execution of the 2026–30 development programme, the group’s elevated leverage and refinancing requirements, and commodity prices. These factors can affect both the pace of earnings growth and ultimately the extent to which higher operating cash flow translates into shareholder returns.

• Nigeria and regulatory risk: Oando’s principal producing assets are concentrated in Nigeria and remain exposed to changes in fiscal and regulatory policy, licence renewal, security and infrastructure availability. OMLs 60–63 require renewal/conversion under the Petroleum Industry Act ahead of their current June 2027 expiry. Pipeline interference, theft and other security incidents have historically affected production and reconciliation losses across the Niger Delta. Currency movements are also material: a weaker naira benefits the translation of predominantly US dollar-linked revenues and lowers the dollar equivalent of local costs, but increases the naira value and servicing burden of US dollar debt.
• Development execution: Our estimates broadly reflect the company’s 2026–30 operating programme and assume a substantial increase in drilling activity, with average production rising from 44kboepd in FY26 to 124kboepd in FY30. Delivery depends on well productivity, drilling and intervention schedules, facility availability, evacuation infrastructure and higher gas offtake. Delays or weaker well performance would reduce earnings and cash generation while development expenditure remains substantial.
• Liquidity and balance sheet: Gross borrowings remain high at c NGN2.16tn, while 9M26 interest payments absorbed c 50% of operating cash generated before interest and tax. Oando’s balance sheet restructuring programme is therefore important to the funding of the planned growth programme. The proposed rights issue is priced at NGN50/share, materially above the current market price, and remains subject to regulatory approvals, creating uncertainty over timing and execution. The proposed US$300m debt-to-equity conversion also lacks disclosed conversion terms. Failure or delay in completing the restructuring could increase reliance on further debt and maintain elevated financing costs.
• Commodity prices: Oil remains the principal commodity exposure and Nigerian crude pricing is broadly linked to international benchmarks. Lower Brent prices would reduce upstream revenue, EBITDA and operating cash generation and, given the current leverage, have a disproportionate effect on equity value and leverage metrics. Oando has implemented a hedging programme covering 6kbopd through purchased put options at US$59/bbl, providing some downside protection while retaining upside exposure. Gas pricing is less directly linked to international benchmarks and depends on domestic reference prices, contract renegotiation and customer mix; slower repricing of legacy contracts would reduce the expected benefit from higher gas production.