Why BP is looking at Devon Energy’s Eagle Ford assets while trying to cut debt

BP p.l.c. (LSE: BP.) is weighing a potential acquisition of Devon Energy Corporation’s Eagle Ford operations in South Texas as the British energy major re-enters the market for sizeable United States shale assets. Reuters reporters David French and Arathy Somasekhar reported that BP has accessed data rooms for several predominantly oil-producing properties valued between approximately $2 billion and $5 billion, including Devon Energy’s Eagle Ford portfolio. Devon Energy’s South Texas assets have been estimated at roughly $3.5 billion to $4.5 billion, although accessing confidential sale information does not mean BP will submit a formal bid. The strategic attraction is substantial because BP already operates at scale in the Eagle Ford through BPX Energy, while the financial tension is equally clear: BP is simultaneously trying to reduce debt and execute a major asset-disposal programme.

The potential transaction comes at a moment when both companies are reshaping their portfolios. Devon Energy completed its all-stock combination with Coterra Energy in May 2026, creating a much larger United States shale producer whose portfolio is anchored by the Delaware Basin, while BP has placed greater emphasis on its conventional oil and gas operations under Chief Executive Officer Meg O’Neill. Devon Energy has since been reviewing its expanded asset base, creating a logical opportunity to sell operations that are less central to the combined company’s Delaware-focused strategy.

How much production could Devon Energy’s Eagle Ford assets add to BPX Energy?

The production arithmetic helps explain why BP might be interested. Reuters reported that BPX Energy produced approximately 545,000 barrels of oil equivalent per day during the second quarter of 2026, including about 205,000 barrels of oil equivalent per day from its existing Eagle Ford operations. Devon Energy’s Eagle Ford portfolio, covering roughly 90,000 net acres, produced approximately 77,000 barrels of oil equivalent per day during the same quarter.

On a simple pro forma basis, adding those 77,000 barrels to BPX Energy’s reported second-quarter production would produce approximately 622,000 barrels of oil equivalent per day. BP has previously set a target for BPX Energy to reach about 650,000 barrels of oil equivalent per day by 2030, meaning the Devon Energy assets alone would theoretically take BPX to roughly 96% of that target before allowing for future organic production growth. BP’s published United States materials confirm that BPX Energy operates across the Permian, Eagle Ford and Haynesville basins and has been building toward the 650,000-barrel target.

That calculation should not be treated as a forecast. Shale production naturally declines without continued drilling, Devon Energy’s output could change before any transaction closes, and BP would need to determine how much capital should be reinvested in the acquired acreage. Nevertheless, the scale comparison illustrates why this particular asset could have greater strategic value to BP than an unrelated shale purchase carrying similar production.

Geography also strengthens the industrial logic. BP already understands the Eagle Ford operating environment, infrastructure and subsurface characteristics, and part of Devon Energy’s acreage was previously held through a joint venture involving BP before that partnership was dissolved in 2025, according to Reuters. Acquiring assets adjacent to an established operating position can create opportunities to consolidate infrastructure, drilling programmes, procurement and field services rather than requiring BP to establish another operating platform from scratch.

Why would Devon Energy sell Eagle Ford assets after completing its Coterra Energy merger?

Devon Energy’s potential willingness to sell is closely connected to the scale created by its Coterra Energy transaction. Devon Energy and Coterra Energy completed their merger on May 7, 2026, after announcing a combination with an estimated pro forma enterprise value of about $58 billion. The combined company operates under the Devon Energy name and is centred on a major Delaware Basin position alongside assets in the Marcellus, Anadarko, Rockies and Eagle Ford.

The original merger presentation described approximately 90,000 net Eagle Ford acres and identified the Delaware Basin as the core franchise of the enlarged business. Devon Energy said the combination was expected to generate approximately $1 billion of annual pre-tax synergies and give the company more than a decade of high-quality inventory in the Delaware Basin. Once a merger creates that level of portfolio scale, divesting non-core or lower-priority acreage can serve two purposes: simplifying capital allocation and converting assets into cash that can be deployed toward debt reduction, shareholder returns or higher-return drilling opportunities.

Devon Energy has considerable flexibility because the combined company is no longer dependent on Eagle Ford production to establish scale. Its operations now span five major areas, and the company reported approximately 1.6 million barrels of oil equivalent per day of pro forma 2025 production across the portfolio. Selling roughly 77,000 barrels of oil equivalent per day would therefore remove a meaningful operation without fundamentally altering Devon Energy’s status as one of the largest independent United States producers.

The valuation Devon Energy can obtain may ultimately be more important than the decision to sell itself. Reuters cited estimates ranging from approximately $3.5 billion to $4.5 billion for Eagle Ford, with TPH Research placing the asset at around $4.5 billion. At 77,000 barrels of oil equivalent per day of second-quarter production, that range equates to roughly $45,000 to $58,000 for each flowing barrel of daily production, although transaction economics also depend on reserves, drilling inventory, commodity mix, operating costs and future development requirements.

Can BP justify a multi-billion-dollar shale purchase while it is reducing net debt?

This is where the potential transaction becomes a more demanding capital-allocation test for BP. The company reported second-quarter 2026 underlying replacement cost profit of $5.73 billion and operating cash flow of $10.86 billion, supported by stronger energy prices, refining margins and trading performance. Net debt fell to $22.25 billion from $25.31 billion at the end of the first quarter, while second-quarter capital expenditure was approximately $3.09 billion.

A hypothetical $4 billion acquisition would therefore be financially material even for BP. It would equal around 18% of BP’s second-quarter net debt, while a $4.5 billion transaction would represent about 20%, although those comparisons do not indicate how BP would actually finance a purchase. The company could theoretically use cash generation, additional borrowing, disposal proceeds or some combination of funding sources, and no acquisition structure has been disclosed because no transaction has been announced.

That funding question matters because BP has also been working through a large divestment programme. Reuters reported that the company has been targeting approximately $20 billion of disposals while seeking to strengthen its balance sheet, and BP generated only $609 million of divestment and other proceeds during the second quarter and $857 million during the first half of 2026. The tension is therefore not whether BP possesses the financial capacity to pursue acquisitions, but whether buying additional shale production can generate better long-term returns than keeping incremental cash available for debt reduction or other projects.

A transaction could still fit the broader restructuring if BP simultaneously sells lower-return or strategically peripheral assets and reallocates capital into operations where it believes it has stronger competitive advantages. Portfolio simplification does not necessarily mean shrinking every business. It can also mean exchanging assets, reducing exposure to activities with weaker economics and increasing investment in operations where infrastructure, technology and existing operating knowledge can produce higher returns.

Could BP’s existing Eagle Ford position make Devon Energy’s assets worth more to it than to another buyer?

Strategic buyers can sometimes justify valuations that financial buyers or operators without nearby infrastructure cannot because part of the acquisition value comes from synergies rather than stand-alone production. BP already produces substantially more oil and gas from Eagle Ford than Devon Energy does, meaning operational integration could potentially reduce duplicated infrastructure and overhead while increasing the utilisation of BPX Energy’s existing systems. Reuters reported that people familiar with the process viewed geographic proximity and BP’s knowledge of the local geology as reasons the transaction could make sense.

The potential benefits would still need to exceed the acquisition premium and future development capital. Paying toward the top of the reported valuation range could become difficult to justify if oil prices retreat materially, drilling productivity deteriorates or the acquired inventory requires greater reinvestment than expected. Conversely, a transaction priced conservatively enough to capture operating synergies without relying on persistently elevated oil prices could help BP accelerate BPX Energy’s production strategy.

Commodity conditions complicate that negotiation. Oil prices have recently been elevated by Middle East supply concerns, strengthening cash generation across the petroleum industry but also potentially increasing sellers’ valuation expectations. Reuters noted that heightened commodity-price volatility has made agreement between buyers and sellers more difficult because purchasers risk paying prices based on temporary market conditions while sellers are reluctant to accept valuations anchored to lower long-term assumptions.

That makes the reported $3.5 billion to $4.5 billion range unusually important. A difference of $1 billion is large enough to materially change acquisition returns, particularly for a company that has made balance-sheet improvement one of its priorities. BP does not simply need to establish that Devon Energy’s Eagle Ford acreage fits operationally; it needs to demonstrate that the price preserves the economics that make the strategic fit attractive in the first place.

What does the BP and Devon Energy share-price reaction reveal about investor expectations?

Devon Energy shares closed at $48.90 on September 24, up 1.79% for the session, with approximately 17.6 million shares traded. The stock remained below its 52-week high of $52.71 but well above its 52-week low of $31.47. The Reuters report emerged during the trading day and Devon Energy shares extended their gains following publication, although a one-day move cannot establish how much of the reaction reflected the potential asset sale rather than broader oil-market conditions.

BP shares closed in London at 571.8 pence on September 24, gaining 2.62% and extending the previous session’s increase. The shares had closed at 542.3 pence on September 22, meaning they gained about 5.4% over the following two sessions, while remaining below their 52-week high of approximately 609.4 pence. Energy prices and broader sector conditions were also moving during this period, making it inappropriate to attribute BP’s market performance solely to the Devon Energy report.

For Devon Energy, a sale near the upper end of the reported valuation range could provide additional capital flexibility only months after completing the Coterra Energy merger. For BP, the market test would be different: shareholders would need evidence that renewed acquisition activity does not reverse recent progress in reducing leverage and improving capital discipline.

What would show whether a BP acquisition of Devon Energy’s Eagle Ford assets creates value?

The immediate proof point is whether BP submits a formal proposal at all. Reuters sources specifically cautioned that entering a data room does not guarantee a bid, and competing purchasers, valuation differences or BP’s own investment thresholds could prevent negotiations from advancing. Until a definitive agreement exists, the reported process should be treated as evidence of BP’s renewed interest in United States shale M&A rather than as an announced acquisition.

If a transaction does emerge, the purchase price and funding structure will determine much of the financial assessment. Investors would also need details on proved reserves, remaining drilling locations, oil weighting, decline rates, operating expenses, planned capital expenditure and expected synergies with BPX Energy’s existing Eagle Ford operation. Those variables would show whether BP is purchasing production at attractive full-cycle returns or primarily paying to accelerate a headline production target.

The strategic case is nevertheless stronger than it would be for an acquisition in a new basin. Devon Energy’s approximately 77,000 barrels of oil equivalent per day could place BPX Energy close to BP’s 2030 production objective on current output figures, and the acreage sits inside a region BP already knows. The unresolved issue is whether BP can capture that operational advantage at a price that remains compatible with its balance-sheet goals.

A disciplined transaction could demonstrate that BP’s portfolio reset is becoming more selective rather than simply smaller, with proceeds from lower-priority assets recycled into oil and gas positions where BP believes it can generate stronger returns. Paying too aggressively, particularly while the company is emphasising debt reduction, would create the opposite signal. The measurable test will therefore be less about whether BP returns to shale acquisitions and more about whether any eventual purchase price, financing structure and synergy target demonstrate the capital discipline management has made central to its strategy.

Key takeaways on BP’s potential Devon Energy Eagle Ford acquisition

• BP is reportedly evaluating Devon Energy’s South Texas Eagle Ford operations as part of renewed interest in United States shale acquisitions.
• Devon Energy’s Eagle Ford portfolio covers roughly 90,000 net acres and produced about 77,000 barrels of oil equivalent per day in the second quarter.
• Reported valuation indications range from approximately $3.5 billion to $4.5 billion.
• BPX Energy produced about 545,000 barrels of oil equivalent per day in the second quarter, including roughly 205,000 from Eagle Ford.
• Adding Devon Energy’s current Eagle Ford production would produce an illustrative BPX total of roughly 622,000 barrels of oil equivalent per day.
• BP is targeting approximately 650,000 barrels of oil equivalent per day from BPX Energy by 2030.
• BP reported $22.25 billion of net debt at the end of the second quarter, making acquisition price and financing important capital-allocation considerations.
• Devon Energy completed its combination with Coterra Energy in May, creating a much larger portfolio centred on the Delaware Basin.
• Geographic overlap could create operating synergies, but those benefits would need to justify the purchase premium and future drilling expenditure.
• The next measurable catalyst is a formal bid, definitive agreement or confirmation that BP has withdrawn from the sale process.