Tullow Oil plc

Tullow reported first-half 2026 production of 43,700 barrels of oil equivalent per day, up more than 7% versus the first half of 2025. Average realized price before hedging was $95/bbl, and the highest ever price for a Tullow cargo was about $130/bbl; a later cargo was priced at $119/bbl. Operating cash flow was $222 million in H1, while free cash flow was $4 million, held back by $70 million of one-off refinancing costs, CapEx timing, and fewer cargoes in H1. Full-year CapEx guidance remains $200 million, decommissioning spend was cut from $25 million to $15 million, and full-year free cash flow guidance was upgraded to $170 million-$250 million at an oil price of $70-$100/bbl. Management expects year-end net debt of $1.2 billion inclusive of accrued PIK interest, and said it had made a $48 million bond repayment in June with another repayment expected in November.

Ian Perks framed the quarter as evidence that Tullow’s operational reset is working, saying the business now has a “stable foundation” that is delivering better production, lower risk, and improved cash generation. He attributed the turnaround to greater rigor and focus, a project-delivery mindset, stronger well stability, improved power reliability, better water injection management, and top-quartile drilling performance. He sounded optimistic but measured, noting 99% uptime is unlikely to be sustained indefinitely while still stressing that the gains appear durable.

Richard Miller emphasized the financial translation of the stronger operating performance, highlighting H1 operating cash flow of $222 million and a full-year free cash flow outlook of $170 million-$250 million. He noted $70 million of one-off refinancing costs in H1, full-year CapEx of $200 million, reduced decommissioning spend of $15 million, and continued deleveraging through a $48 million bond repayment in June plus another planned for November. He also detailed the April refinancing: senior secured notes extended to 2028, Glencore debt to 2030, a new $100 million cargo prepayment facility, and cash interest costs lowered by over $50 million per year.

Analysts focused on what drove the operational step-change, what the 4D and OBN seismic are showing, the relationship between prompt oil pricing and realized cargo prices, and the likely path to a longer-term refinancing. Management said the production improvement came from better field focus, riser-based gas lift, water injection optimization, stronger power reliability, and excellent drilling execution; 4D seismic helped de-risk the recent campaign, while OBN data due later this year/next year should sharpen future well selection. On Ghana tax disputes, management said discussions remain ongoing, the next arbitration was deferred, and any settlement could be offset against receivables owed by the government. On refinancing, they said planning is already underway for a second-half solution, likely involving a trader-led structure and possibly banks for a more traditional E&P capital structure.