[DVN] Devon Energy: Q3 2026 Earnings Test Oil Output After Coterra Merger

Devon Energy is a US onshore oil and gas producer that closed its all-stock merger of equals with Coterra Energy on May 7, 2026[1], giving it assets in the Delaware Basin, the Rockies, the Anadarko Basin, the Marcellus Shale and the Eagle Ford. Devon will report results for the Third quarter 2026 (three months ended September 30, 2026) after the market closes on November 5 and will hold its earnings call on 2026-11-06[2]. In the latest disclosed quarter, the second quarter of 2026, Devon produced 1,359,000 barrels of oil equivalent (Boe) per day, including 503,000 barrels of oil per day, both at the top end of guidance; net earnings were $1.9 billion, or $2.03 per diluted share, core earnings were $1.57 per share and adjusted free cash flow was $1.7 billion[3]. Guidance issued in August calls for third-quarter oil output of 550,000-560,000 barrels per day, total output of 1,660,000-1,690,000 Boe per day, gas output of 4,450-4,500 million cubic feet (MMcf) per day, capital spending of $1.4-$1.5 billion, lease operating expense (LOE) of $4.60-$4.90 per Boe and gathering, processing and transportation (GP&T) cost of $3.40-$3.50 per Boe[3]. The 14 analysts compiled by Drillr estimate average third-quarter earnings of $1.31 per share, within a range of $0.93-$1.53, and average net income of $1.232 billion[4].

Three things matter most in Devon's Q3 2026 earnings. The first is the combination of oil output and capital spending: the third quarter is the first full quarter after the merger, so whether oil reaches the 555,000-barrel-per-day guidance midpoint while capital stays within $1.5 billion will directly test whether the merger improves capital efficiency, because second-quarter capital of $1.269 billion came in 2% below the guidance midpoint[3] and management said part of that spending simply moved into the third quarter[5]. The second is the realized gas price: gas output more than doubled after the merger, yet the second-quarter realized gas price including hedges was only $1.05 per thousand cubic feet (Mcf), which the company attributed to weak regional Waha pricing caused by Delaware Basin takeaway constraints, so whether third-quarter gas prices and GP&T land within guidance will decide whether cash margin per barrel holds[3]. The third is debt reduction and portfolio change: management targets total debt of about $9 billion by the end of 2027[5], Devon has agreed to sell its Eagle Ford assets for $4.2 billion, and the third-quarter release will explain the sale's effect on guidance[2] alongside an initial 2027 outlook[5].

Company Background and Business Structure

Devon Energy is a long-established US independent oil and gas producer; 2025 marked its 54th year in the oil and gas business and its 37th year as a public company[6]. On May 7, 2026, Devon completed its all-stock merger with Coterra at 0.70 Devon share for each Coterra share, leaving pre-merger Devon shareholders with about 54% of the combined company and former Coterra shareholders with about 46%[1]. To complete the merger, Devon issued about 532 million shares for total consideration of $24.946 billion and assumed $3.256 billion of long-term debt[7].

Devon has a single exploration and production reporting segment and discloses volumes and prices by region[7]. On a combined basis, second-quarter output of 1,359,000 Boe per day came from the Permian (Delaware Basin) at 748,000, the Rockies at 192,000, the Marcellus at 210,000, the Anadarko at 128,000 and the Eagle Ford at 77,000 Boe per day; the Marcellus is almost entirely gas at 1,258 MMcf per day, while Permian gas output was 1,274 MMcf per day[3]. The Eagle Ford assets cover about 90,000 net acres and represent about 4% of total output, and Devon agreed in October to sell them to Crescent Energy[2].

Devon's business is drilling horizontal wells, completing them and selling the oil and gas downstream. Crude is either sold at the wellhead at an agreed index price net of differentials or delivered to a contractual delivery point where the buyer takes title, and payment typically arrives within 30 days of the end of the production month; a separate stream of marketing revenue comes from reselling oil and gas bought from third parties[6]. Second-quarter marketing and midstream expenses of $1.874 billion largely offset that revenue[7]. The main costs are LOE, GP&T, production taxes of about 6.7% of oil, gas and NGL sales, and depletion[6], while full-year 2026 capital spending guidance is $4.8-$5.0 billion[5].

The company's asset base rests on reserves and drilling inventory. Proved reserves at the end of 2025 were about 2.428 billion Boe, calculated from the 2.155 billion Boe at the end of 2024 after revisions, extensions, purchases, production and sales, with proved undeveloped reserves of 584 million Boe, or 24%; of 2025 output of 307 million Boe, the Delaware Basin contributed 180 million and the Williston Basin 63 million[6]. In the second quarter, Devon paid $2.6 billion in cash at a New Mexico federal lease sale for 16,300 net acres and about 400 top-tier locations with an 87.5% net revenue interest, and it plans to begin developing that acreage in 2027[3].

Financial History and Current Position

In 2025, Devon kept generating strong cash despite falling oil prices. Output was 307 million Boe, or about 841,000 Boe per day, with oil at 389,000 barrels per day, up 12%; WTI averaged $64.87 per barrel, about 14% below the 2024 average of $75.79, yet the company generated $6.7 billion of operating cash flow[6]. The cost showed up in cash margin per Boe, which fell from $29.63 in 2024 to $24.97, while LOE rose to $6.27 per Boe; total debt at the end of 2025 was $8.389 billion, including a $1.0 billion term loan due in September 2026[6].

The first quarter of 2026, the last quarter before the merger, showed steady operations but thin earnings. Oil output was 387,000 barrels per day and total output 833,000 Boe per day, capital spending was $848 million, 6% below guidance, and free cash flow was $816 million[8]. Net earnings for the quarter were $120 million, down from $562 million in the fourth quarter of 2025[9].

The second quarter of 2026 included about 55 days of Coterra and showed a much larger income statement. Total revenue was $7.417 billion and net earnings $1.911 billion, compared with $4.284 billion and $917 million a year earlier[7]. Oil, gas and NGL sales were $5.1 billion, with realized prices including hedges of $88.09 per barrel of oil, $22.70 per barrel of NGL and $1.05 per Mcf of gas; diluted earnings were $2.03 per share, and core earnings, which exclude items analysts typically leave out, were $1.57 per share[3].

Second-quarter cash flow and the balance sheet show Devon still returning cash and cutting debt after the expansion. Operating cash flow was $3.7 billion and adjusted operating cash flow $2.9 billion, capital spending was $1.269 billion and adjusted free cash flow was $1.7 billion[3]; the reinvestment rate was 43%, down from the mid-50% range of the prior two years[5]. Devon returned $1.063 billion in the quarter through a dividend raised to $0.32 per share, renewed buybacks and debt repayment; at the end of June it held $1.0 billion of cash, an undrawn $3.0 billion credit facility and $11.4 billion of total debt, and in July it repaid the remaining $750 million of its term loan, leaving no maturities until the second quarter of 2027[3].

Operating Model

Devon's revenue is volume times realized price, and marketing and derivatives make quarterly total revenue more volatile. Oil, gas and NGL sales equal each product's daily output multiplied by the days in the period and its realized price, and this line was $5.1 billion in the second quarter on output of 1,359,000 Boe per day[3]. Marketing and midstream revenue largely offsets $1.874 billion of marketing expense, while total revenue also includes derivative gains and losses, so quarterly total revenue swings more than oil, gas and NGL sales[7]. Changes in volume and price reach revenue in the same quarter, and cash is usually collected within 30 days of the end of the production month[6].

Operating profit depends on unit cash costs and depletion. Operating profit roughly equals oil, gas and NGL sales minus volume times unit LOE and GP&T, less production and property taxes, depletion, general and administrative expense and net marketing cost; in the second quarter LOE was $5.06, GP&T $3.16 and production and property taxes $3.05 per Boe, the company-wide realized price was $41.30 per Boe and cash margin was $30.03 per Boe[3]. Depreciation, depletion and amortization was $1.416 billion in the quarter[7], and third-quarter guidance for that cost is $10.75-$11.25 per Boe[3]. Product mix changes unit costs directly: the 10-Q said LOE per Boe fell and GP&T per Boe rose in the second quarter because of the different post-merger asset and product mix[7].

Free cash flow is operating cash flow minus capital spending excluding acquisitions, and capital turns into output with a lag. Rigs and completion crews first become wells placed online and then become later output; in the second quarter Devon averaged 34 operated rigs and 10 completion crews and brought 120 net operated wells online[3]. Cash goes first to the dividend, which management keeps at 10-15% of discretionary cash flow, and the rest goes to buybacks and debt reduction, with $7.8 billion of repurchase authorization remaining[5]. After-tax proceeds from the Eagle Ford sale will also go to accelerated buybacks and debt reduction[2].

This model has clear limits. Devon does not disclose regional income statements, single-well returns or the dollar amount of synergies achieved, and the second quarter includes only part of Coterra, so it is not comparable with pre-merger quarters; on a pro forma basis that assumes Coterra had been combined since January 1, 2025, second-quarter total revenue was $8.150 billion[7]. The Eagle Ford sale has not closed, and its effect on fourth-quarter and later guidance will only be explained with the third-quarter results[2].

Industry and Competitive Position

The combined Devon is one of the largest US independent oil and gas producers, competing in the Permian with companies such as EOG, Diamondback Energy and Occidental for drilling locations and oilfield services. Second-quarter output was 1,359,000 Boe per day[3]. The 10-K warns that some major integrated and independent competitors have substantially greater resources and may have established superior long-term strategic positions and relationships[6].

Devon's advantages are the depth of its Delaware Basin inventory and its multi-basin portfolio. In the second quarter, cash margin per Boe was $33.39 in the Permian and $55.39 in the Eagle Ford, compared with only $6.89 in the Marcellus and $18.84 in the Anadarko, and the roughly 400 new New Mexico locations further extend Delaware development inventory[3]. Devon said the Eagle Ford sale lengthens its inventory life, lowers its corporate breakeven and reduces its base production decline rate[2].

Devon's disadvantage is concentrated in gas takeaway. In the first quarter, the unhedged Delaware Basin gas price was only $0.73 per Mcf while Henry Hub averaged $5.05[8]; management said on that call that Devon had been aggressive in pipeline participation and had only marginal exposure to Waha[10], yet the second-quarter release still blamed weak gas prices on Delaware takeaway constraints[3]. In October, Devon cited its investment in the Solitude pipeline to integrate its gas from wellhead to market[2]. This comparison has limits, because the materials come only from Devon's own disclosures, so peers' cash margins and takeaway arrangements cannot be compared on the same basis.

Core Debates

In its first full quarter after combining with Coterra, can Devon lift oil output above 555,000 barrels a day while keeping capital spending within $1.5 billion?

This question matters because the merger moved Devon up a size class. Output rose from 833,000 Boe per day in the first quarter to 1,359,000 in the second[8][3], but the second quarter included only about 55 days of Coterra production, so the third quarter is the first to fully reflect combined capacity and costs. Devon will also give an initial 2027 outlook with its third-quarter results[5], and the market will use it to judge whether the merger improves capital efficiency.

The current evidence leans positive but does not settle the question. Second-quarter oil output of 503,000 barrels per day and total output of 1,359,000 Boe per day were both at the top end of guidance, which Devon attributed mainly to Delaware Basin well performance, and capital spending of $1.269 billion was 2% below the guidance midpoint[3]. Third-quarter guidance is 550,000-560,000 barrels of oil per day and $1.4-$1.5 billion of capital, and management called the third quarter the highest capital quarter of the year, partly because spending shifted from the second quarter[5]. An alternative reading is that the below-midpoint second-quarter capital was only a timing shift; if third-quarter capital lands at the top of the range while output reaches only the bottom, the merger has not improved capital efficiency.

The financial transmission runs from rigs to cash flow. The second quarter's 34 rigs and 10 completion crews determine wells placed online, those wells and Delaware well performance determine oil and Boe output, and output times realized price produces oil, gas and NGL sales ($5.1 billion in the second quarter) that flow into operating cash flow[3]. Capital spending in the same period determines how much operating cash flow is left as free cash flow, and its effect on output appears only once new wells come online.

What remains unresolved is whether post-merger capital efficiency can last. The third-quarter report should show whether oil output is at least the 555,000-barrel-per-day midpoint, whether capital stays within $1.4-$1.5 billion and what capital the initial 2027 outlook needs to sustain output; oil below 550,000 barrels per day would mean combined capacity or completion pace fell short of plan, and capital above the $1.5 billion ceiling would mean output was bought with extra spending. Management also said fourth-quarter capital should decline on lower activity in the Marcellus, Anadarko and Powder River basins, with oil output similar to or higher than the third quarter[5].

With gas now a much larger share of output, will Waha takeaway constraints and low-priced Marcellus gas drag down Devon's cash margin per barrel?

The gas mix matters because the merger sharply raised gas's weight in Devon's output. Gas output rose from 1,373 MMcf per day in the first quarter to 3,252 in the second, and third-quarter guidance of 4,450-4,500 MMcf per day equals about 45% of total output on a Boe basis; yet the second-quarter realized gas price including hedges was only $1.05 per Mcf, and Marcellus cash margin was only $6.89 per Boe, far below $33.39 in the Permian and $55.39 in the Eagle Ford[3]. High oil prices hide this low-margin volume, but when oil falls, company-wide margin per barrel would decline faster.

The evidence so far shows that the margin improvement came from oil prices rather than gas prices. Company-wide cash margin was $30.03 per Boe in the second quarter, up from $27.78 in the first, while GP&T rose from $2.54 to $3.16[3]; the 10-Q attributed the higher GP&T to the different post-merger asset and product mix, the unhedged realized gas price in the first half of 2026 was $0.74, only 19% of the $3.98 Henry Hub average, and Devon has Waha basis swaps covering 350,000 MMBtu per day in the second half[7]. An alternative reading is that the gas discount reflects seasonal pipeline maintenance that will fade once new takeaway capacity starts in the third quarter, and that the GP&T increase is a mix effect rather than costs running out of control. Management likewise said on the second-quarter call that new egress capacity should provide a tailwind, while Gulf Coast and Permian gas price volatility remains a risk[5].

The financial transmission works on both price and cost. Permian takeaway capacity, the Waha basis and Marcellus gas prices set the realized gas price, which times volume produces gas revenue, while gathering fees on Marcellus and Permian gas raise unit GP&T, and together they set cash margin per barrel and feed operating cash flow[3]. Third-quarter GP&T guidance of $3.40-$3.50 per Boe is already above the second quarter's $3.16[3] and the full-year 2025 level of $2.71[6].

What remains unresolved is whether the takeaway bottleneck eases and where the Marcellus fits in the portfolio. The third-quarter report should show whether the realized gas price including hedges rises above $1.05, whether GP&T stays within $3.40-$3.50 and whether Marcellus cash margin improves or the portfolio review reaches the Marcellus. A realized gas price below $1.05 again would mean the bottleneck has not eased, and GP&T above $3.50 would mean gathering costs are rising faster than planned.

Can merger synergies, the Eagle Ford sale and free cash flow carry Devon toward $9 billion of total debt while it keeps returning cash to shareholders?

The debt path matters because the merger raised leverage as it added scale. Devon assumed $3.256 billion of Coterra's long-term debt[7], total debt reached $11.4 billion at the end of the second quarter, and at the same time Devon raised its quarterly dividend to $0.32 and resumed buybacks[3], a 33% dividend increase[5]. Management targets total debt of about $9 billion by the end of 2027 and leverage at or below 1x through the cycle[5]; the October Eagle Ford sale is the first result of the portfolio review[2], while shareholders Toms Capital and Kimmeridge are still pressing for further simplification[11][12].

The evidence shows debt reduction running ahead of plan, but the source of the cost improvement is still unclear. Second-quarter adjusted free cash flow was $1.7 billion, and Devon repaid $250 million of senior notes and $250 million of its term loan, paid the $2.6 billion New Mexico lease acquisition with cash on hand and repaid another $750 million in July[3], completing its full-year 2026 debt reduction target of $1.25 billion during the second quarter[5]. LOE fell from $6.48 per Boe in the first quarter to $5.06[3], but the 10-Q attributed the decline mainly to the post-merger mix[7]. An alternative reading is that almost all of the LOE decline came from the low-cost Marcellus mix rather than synergies, and because the Eagle Ford has the highest margin per barrel, selling it will dilute the average margin of the remaining assets.

The financial transmission links synergies, the asset sale and debt. Devon has identified more than 350 synergy initiatives and targets at least $1.0 billion of annual pre-tax synergies by the end of 2027, with about $600 million captured during 2027, but it has not disclosed how much it has achieved[3][5]. Synergies and cost actions lower unit LOE, operating cash flow minus capital spending produces adjusted free cash flow, and together with after-tax Eagle Ford proceeds that cash funds debt reduction and buybacks, which show up in total debt and financing costs; the Eagle Ford sale is for $4.2 billion in cash, has an effective date of July 1, 2026 and is scheduled to close around year-end[2].

What remains unresolved is whether synergies and asset sales can support both debt reduction and shareholder returns. The third-quarter report should show whether LOE is within $4.60-$4.90 per Boe, whether total debt at the end of the third quarter is below about $10.65 billion (the $11.4 billion at the end of June minus the $750 million repaid in July) and how the Eagle Ford closing, use of proceeds and 2027 plan are progressing; LOE above $4.90 would mean synergies are lagging, and rising total debt would mean free cash flow is not covering shareholder returns. Management said after-tax sale proceeds will first go toward the $9 billion end-of-2027 debt target, which may itself be adjusted for the post-sale portfolio[5].

Risks and Falsifiers

Oil prices are Devon's largest single risk, and the exposure sits in oil revenue. The second-quarter realized oil price including hedges was $88.09 per barrel[3], far above the 2025 WTI average of $64.87, while Devon's 2026 hedges cover only about 30% of expected oil and gas volumes[6]. On third-quarter oil guidance of about 555,000 barrels per day, each $10 per barrel change in the realized oil price moves quarterly oil revenue by about $500 million. If the third-quarter realized oil price stays above the 2025 WTI average and Devon does not cut its capital or buyback plans, this risk has not materialized.

The portfolio review and shareholder pressure create transaction uncertainty, with exposure in output and free cash flow. Toms Capital wants the company to consider a full sale[11], Kimmeridge wants a simpler portfolio[12], and management has said the review will conclude in months, not years[5]. Asset sales would reduce output and free cash flow while bringing proceeds and taxes, and selling at a low price could destroy value. If Devon gives a clear portfolio direction with its third-quarter results and later sales are priced no lower than the value of keeping the assets, this concern eases.

Post-merger execution risk is concentrated in the third quarter, with exposure in oil revenue and capital spending. The two companies' drilling and completion programs are running together for a full quarter for the first time, and if completion pace or new Delaware wells disappoint, oil output would land at the bottom of guidance[3]. Each 5,000-barrel-per-day shortfall in oil at $88.09 per barrel cuts quarterly oil revenue by about $40 million, and extra activity to make up volume could push capital above the $1.5 billion ceiling. If third-quarter oil is at least 555,000 barrels per day and capital is within $1.4-$1.5 billion, this risk is falsified.

The Permian gas takeaway bottleneck depresses realized prices for associated gas, with exposure in gas revenue. Waha prices can fall sharply during pipeline maintenance or when takeaway is short[3], and management also lists Gulf Coast and Permian gas price volatility as a risk[5]. On third-quarter gas volume of about 4,475 MMcf per day, each $0.50 per Mcf change in the realized gas price moves quarterly gas revenue by about $200 million. If the third-quarter realized gas price is above $1.05 and Devon reports improved Permian gas prices, this risk has not materialized.

Synergy and portfolio execution could lag plan, with exposure in free cash flow and margin per barrel. Devon targets about $600 million of synergies captured during 2027[3]; a miss would reduce free cash flow and delay the path to $9 billion of debt, and because the Eagle Ford represents about 4% of output and carries the highest margin per barrel, output and revenue will fall after closing[2]. If Devon reports synergies achieved in line with target and cash margin per barrel does not fall after closing, the current understanding is supported.

What to Watch Next

• Oil output and capital: third-quarter oil versus 503,000 barrels per day in the second quarter and guidance of 550,000-560,000; below 550,000 weakens the case. Capital versus $1.269 billion in the second quarter and guidance of $1.4-$1.5 billion; above $1.5 billion weakens it, and the initial 2027 outlook shows the capital needed to hold output.
• Gas mix and margins: the realized gas price including hedges versus $1.05 per Mcf in the second quarter; another reading below $1.05 weakens the case. GP&T versus $3.16 per Boe and guidance of $3.40-$3.50, and cash margin versus $30.03 per Boe; GP&T above $3.50 weakens it.
• Synergies, sale and debt: LOE versus $5.06 per Boe and guidance of $4.60-$4.90; above $4.90 weakens the case. Quarter-end total debt versus $11.4 billion at the end of June less the $750 million July repayment, plus the Eagle Ford closing and use of proceeds; a rise in total debt weakens it.

Conclusion

Three things drive Devon's business: oil output and oil prices produce most of its revenue, gas takeaway and the asset mix set unit costs and margin per barrel, and capital spending and asset sales decide how much cash is left for debt reduction and shareholder returns. In the second quarter, combined output was 1,359,000 Boe per day and adjusted free cash flow $1.7 billion, but total debt stood at $11.4 billion and the realized gas price including hedges was only $1.05 per Mcf[3]. The central unresolved relationship is whether the merger's added scale can turn into better capital efficiency and faster debt reduction in a third quarter with weak gas prices and peak annual capital spending.

The independent views published after the second-quarter results all focus on portfolio complexity. Hedgeweek reported on September 24 that Toms Capital believes the enlarged post-merger portfolio has created unnecessary complexity that is depressing how the market prices the company, and that it is advocating a broader strategic review that could include selling the whole company[11]; John Bromels of The Motley Fool reported on September 25 that Kimmeridge has also publicly urged management to streamline the portfolio but has stopped short of asking for a sale of the whole company[12]. The two shareholders agree that the portfolio is too complex and differ on whether the remedy is selling some assets or the entire company; the October Eagle Ford sale fits the first path[2], and management's comments on the Marcellus, Anadarko and other assets with third-quarter results will test how far the review goes. These are outside shareholder interpretations, not established facts, and they do not represent a majority view.

The current understanding would be materially strengthened by a combination of observations: third-quarter oil of at least 555,000 barrels per day with capital within $1.5 billion, a realized gas price including hedges above $1.05 with GP&T within $3.50, LOE within $4.60-$4.90, quarter-end total debt below about $10.65 billion, and an initial 2027 outlook showing lower capital needed to sustain output. Conversely, oil below 550,000 barrels per day with capital above the ceiling, renewed weakness in gas prices, rising total debt, or a post-Eagle Ford portfolio that lowers cash margin per barrel would materially weaken it.

Sources

[1] DVN Coterra merger closing 8-K filed 2026-05-07 · 2026-05-07 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001090012&type=8-K&dateb=&owner=include&count=40

[2] DVN Eagle Ford divestiture 8-K filed 2026-10-08 · 2026-10-08 · 8-K · https://www.sec.gov/Archives/edgar/data/1090012/000119312526417944/d141547dex991.htm

[3] DVN Q2 2026 8-K filed 2026-08-04 · 2026-08-04 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001090012&type=8-K&dateb=&owner=include&count=40

[4] Drillr analyst estimates DVN Q3 2026 retrieved 2026-11-03 · 2026-11-03 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[5] DVN Q2 2026 earnings call 2026-08-05 · 2026-08-05 · earnings-call · https://gateway.drillr.ai/mcp/private

[6] DVN 10-K filed 2026-02-18 · 2026-02-18 · 10-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001090012&type=10-K&dateb=&owner=include&count=40

[7] DVN Q2 2026 10-Q filed 2026-08-05 · 2026-08-05 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001090012&type=10-Q&dateb=&owner=include&count=40

[8] DVN Q1 2026 8-K filed 2026-05-05 · 2026-05-05 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001090012&type=8-K&dateb=&owner=include&count=40

[9] DVN Q1 2026 10-Q filed 2026-05-06 · 2026-05-06 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001090012&type=10-Q&dateb=&owner=include&count=40

[10] DVN Q1 2026 earnings call 2026-05-06 · 2026-05-06 · earnings-call · https://gateway.drillr.ai/mcp/private

[11] Hedgeweek on Toms Capital letter to Devon 2026-09-24 · 2026-09-24 · Hedgeweek · https://hedgeweek.com/news/toms-capital-urges-devon-energy-to-consider-sale

[12] Motley Fool on Kimmeridge and Devon portfolio 2026-09-25 · 2026-09-25 · The Motley Fool · https://www.aol.com/articles/bp-walked-away-potential-4-223801000.html