Detailed narrative
Bumerangue (Brazil) — the flagship discovery
Management calls Bumerangue the largest discovery in 25 years, upgrading the column from 500m to 1,000m on log and sample response: 100m of oil at the base and 900m of rich gas condensate over at least 300 sq km, at least 1,000m of column height.
About two-thirds of samples have been evaluated; the published Slide 9 map is off predrill seismic, with pre- and post-drill imaging matching top/bottom of reservoir within a couple of feet. CO2 is characterized as manageable (though metallurgy may cost more) and helped by the oil-condensate column improving flow.
A rig is secured for a second appraisal well and flow test near end-2026/early 2027, focused on well productivity and how many wells are needed; gas-oil ratios and in-place volumes to be updated later. A partner will be brought in, likely after appraisal/flow test.
Exploration — best year in BP's history
BP is 12-for-14 on discoveries YTD, described as probably the best exploration year in its history, driven by the convergence of experienced teams, NVIDIA-chip supercomputing, wide-azimuth seismic and full-waveform inversion enabling much better sub-salt imaging in Egypt, Trinidad and Brazil.
Trinidad and Egypt each offer two development-ready discoveries. In Namibia (via Azule, the Eni JV), there are effectively three discoveries: Capricornus (38m, high-Darcy rock, good oil), and Volans in Q3 (~28m, rich gas condensate, 14km from Capricornus); operator Rhino continues lab testing, with the Namibian energy minister calling it the best block in the nation.
Exploration spend is held at ~$500-600M/year (~15 wells) to force quality-through-choice despite the success.
BPX (US onshore) — capital efficiency and liquids growth
BPX runs at ~$2.5B/year with strong productivity: 30% completions and 15% drilling improvement over 12 months, top-quartile drilling days per 10,000ft and NPV/dollar in each basin, and 13 wells effectively drilled 'for free' vs plan. It set a Haynesville record — a 4-mile lateral producing 80 MMcf/d.
Growth is liquids-led: the Permian is being filled (2-3 rigs to keep infrastructure full), while the Eagle Ford Blackhawk downspacing and refracs outperform original decade-old wells. Gas runs 8 rigs (potential move to 9 in 2026), with Haynesville growth following infield gathering and new offtake points established by trading/marketing.
Portfolio simplification and divestments
The $20B divestment program has ~$5B announced (~$1.7B proceeds in the door, ~$3.5B to come). Strong interest reported in Castrol (9 consecutive quarters of earnings growth) and Gelsenkirchen; Lightsource bp is at an earlier stage. Q3 actions: sanctioned Tiber, decided to divest the Culzean North Sea field, stopped the Rotterdam biofuels refinery, and completed a TANAP midstream stake disposal.
New Chair Albert is driving the portfolio review, born of exploration success. Kate notes no further significant infrastructure deals in the pipeline, so non-controlling interests should not increase and will decline as the prefinanced 2026 hybrid (~$1.4B left) is redeemed.
Balance sheet and financial resilience
Financial resilience is framed around total liabilities, not gearing (no gearing target). Beyond the net-debt target of $14-18B by end-2027 (~$10B reduction), Kate flags >$1B/year of Deepwater Horizon payments (~$2.2B more before end-2027) and ~$1.4B of prefinanced 2026 hybrid — a liability stack falling ~$13-14B over 2+ years even with no further action.
The UK pension trustee executed a buy-in with Legal & General as a derisking step; further derisking rests with the trustee board, not BP.
Downstream — record customers and refining, weaker trading
First-nine-months downstream underlying earnings were ~40% higher YoY. Customers posted its highest 3Q on record: Castrol +21% YoY (9M), tighter fuels-midstream integration, ~$0.5B of structural cost reductions, and ~$300M uplift from consolidating BP Bioenergy. Refining availability YTD is 96.4% (vs 96% target) with ~$200M of cost cuts, capturing an improved margin environment.
Trading was weaker in Q3 after a strong Q2, but 9-month trading is broadly in line with last year.
Iraq (Kirkuk) and new-country entry
In Kirkuk (Round 8), BP completed an initial production test agreed with the nation at 328 kbd of black oil, with 45 people on the ground beginning well work, acid jobs, compressor rewheels and procurement. Terms are better than first-round Rumaila: price upside, ability to take gas price, and exploration rights on surrounding and deeper acreage.
The PSA is not yet published, limiting economic disclosure. Management sees strong forward oil demand with non-OPEC+ supply near a plateau after early-2026, positioning countries like Iraq to help meet demand.
AI and cost/complexity reduction
BP is building a unified, cloud-based data platform (with Palantir and Databricks) across upstream, downstream, trading and finance, targeted for around mid-2026 to enable LLMs across all data. Cited results: ~98% kick detection in Gulf of America drilling; ~97% upstream availability aided by predictive fault detection; well-planning time cut ~90%; and a German service-station agent trial (20 sites) cutting food waste 45% over three months.
Structural costs improved ~$400M QoQ.