Betty Jiang

Sunil detailed 2027 sustaining capital of around $5 billion to $5.1 billion and a path to $4.5 billion by 2030.

Babatunde highlighted Powder River strength, about 41% above the industry average, with activity shifting from the DJ Basin.

Richard highlighted advanced recovery across Gulf Of America waterfloods, CO2 EOR, and unconventional opportunities as distinct advantage. Also cited operational excellence, workforce efficiency with AI deployment, and international partnership model. [Attribution inferred: the operator introduced this questioner only as "Analyst with Barclays" with no name stated; Betty Jiang is Barclays' covering analyst on OXY across adjacent quarters.]

Three commercial EOR projects expected online in 2028 with compression as main long-lead item. Continued positive demo results including Midland Basin Barnett CO2 EOR. EOR portfolio now concentrated at approximately 100 thousand barrels per day after optimization. [Attribution inferred: the operator introduced this questioner only as "Analyst with Barclays" with no name stated; Betty Jiang is Barclays' covering analyst on OXY across adjacent quarters.]

Jackson described DJ declining slightly while PRB ramps. PRB has higher oil cut with record Nio and Turner well performance. Deploying simul-frac in Rockies. Bronco greenfield project in DJ with more wells per pad. PRB production nearly doubles from Q1 to Q4.

Mathew framed 2026 capital as sustaining base for 2027 with modest growth potential from continued efficiencies. GoA waterflood injection wells increase in 2027. LCV lower with STRATOS completion. Jackson emphasized structural not deferred savings: wells per rig doubled since 2023, simul-frac scaled to 40%. Permian growing ~4% YoY.

Mathew explained benefits depend on domestic capital mix (~90% currently). 2026 benefits elevated by Battleground project qualifying for 100% bonus depreciation.

Hollub confirmed point source interest since 2008 but historically blocked by low carbon credit prices. OBBB parity makes industrial sources more willing to partner. Jackson added natural gas power generation as dual CO2 source and power supply opportunity.

Hollub confirmed confidence in reaching $15B target but pushed timing to first part of 2027, noting supplemental cash flow opportunities.

Jackson explained ethane rejection, divestitures, Bronco development with 140 locations at sub-$50 breakeven, and Powder River Basin resumption in H2.

Rodgers said ~$20M of Permian capital allocated to LOE reduction projects (SWD, compression consolidation). Riney acknowledged LOE savings fell short of 2025 hopes, mainly Permian struggle, but highlighted real success in North Sea and Egypt LOE without capital investment.

Rodgers said Gulf of America normalizes to $100-120M range. North Sea grows to ~$600M after-tax ARO through 2030, then $600M from 2031-2038 declining. Will provide more multi-year detail in Q1 2026 portfolio update. Riney confirmed shape unchanged from prior guidance.

Rodgers said Egypt FCF is up vs. beginning of year expectations thanks to gas price step change and production. BOE growth expected to continue into 2026 with modest FCF increases even with slight oil decline.

Rodgers explained the North Sea will reach a tax-loss position in 2026 through natural production decline and without needing additional investment. ARO will increase next year, peaking around 2030-2031.

Rodgers explained the bridge: running 6 rigs in 2026 plus continued overhead progress and early LOE pickup. Riney confirmed $800K/well savings is the majority driver. Christmann noted anything captured now has full-year impact in 2026.

Riney cited route optimizations, renegotiating vendor contracts for water disposal and compression as they come due, chemical costs, and operational practices across the field.

Christmann said confident visibility through 2029 with inventory additions typically exceeding wells drilled each year. Riney added they'll provide a more detailed Permian inventory view later in 2025.

Christmann outlined three buckets in priority order: capital (biggest), LOE, then G&A. Riney added the target came from rigorous internal/external benchmarking and $350M is 'probably on the conservative end.'

O'Brien explained the Pacific Basin supplement supports commercial optimization, and framed constructive, asymmetric-upside LNG margins as a material cash engine.

Andy framed the CapEx increase as operational continuity, not a macro bet. Nick detailed completion efficiency outpacing drilling. Ryan emphasized these are defensive moves to protect inventory.

Ryan Lance described exploring west and south of Willow for tieback opportunities into Willow and Alpine infrastructure. Historical Alaska hubs produced over 2x original FID volumes. Four wells this year, multiyear plan to maximize infrastructure.

Nick Olds described achieving steady-state at 24 rigs with significant drilling and completion efficiency improvements. 2026 capital run rate similar to Q3 levels.

Andy O'Brien guided to lower 2026 CapEx, ~2% underlying production growth as modeling starting point, and confirmed cash flow inflection is already beginning in H2 2025.

Ryan Lance acknowledged reinvestment rate may temporarily rise but emphasized projects are sub-$40 cost of supply and breakeven falls as projects come online.

Nick Olds walked through efficiencies, synergy capture, activity optimization in Eagle Ford and Bakken, and ~$200M modest deflation in 2025.

Blake Sirgo detailed supply-chain flexibility, best-practice sharing (simul-frac, long laterals) and AI benchmarking; noted the $800/foot reflects a 9-12 month trailing cost and most synergies are not yet in it.

Clay said board authorization imminent but declined to commit to specific catch-up numbers; both legacy teams excited about returning shareholder value with combined FCF and buying back material shares.

Clay and Jeff deferred to new combined board discussions; Jeff emphasized both companies historically investment grade with flexibility, signaling continuity of strong balance sheet philosophy.

Jeff said optimal absolute debt is $6-6.5B (current $8.9B less $2.5B target); will consider increasing returns once achieved.

John cited Powder River Basin Niobrara as best example: well costs declining from $13M to $12M with $10M vision well concept.

Clay explained paradox: Powder has worst economics but most upside potential; Delaware has most flexibility due to scale.

Jeff projected maintenance capital declining to ~$3.4-3.45B by 2027 from current $3.8B baseline through optimization.

Jiang probed capital return trajectory now that buyback has reinitiated. Young cited historical 94% and 75% return levels as targets, signaling robust 2026 return program without committing to specific percentage.

Jiang pressed on Delaware well productivity versus expectations and 2026 shape. Young confirmed productivity as expected to slightly better, cautioned Q4 exit rate of 175 MBoe won't necessarily sustain into 2026 start.

Shane Young explained 100% bonus depreciation and R&D expense return as primary drivers, plus step-up basis from acquisitions. Guided 70-90% current tax over next several years as timing benefits normalize.

Shane Young confirmed buyback focus returns post-debt paydown, targeting the historical 75-100% free cash flow return range. Noted a $250M maturity in late 2026 that needs to be factored in.

Tom Jorden expects Harkey remediation in months not years, calling it a mechanical not strategic issue. Blake confirmed Wolfcamp capital efficiency is actually slightly better in near term.

Shane Young confirmed substantial sequential production step-ups driven by meaningfully higher Q2 TILs flowing through to strong Q3-Q4 production.

Bonner said the $18-21B range covers five years of options including Kilby power, with capital discipline the priority. Direct.

Wirth confirmed TCO back at full rates after February repairs, debottlenecking showing encouraging results. $6B FCF guidance at $70 Brent unchanged. Concession renegotiation making good progress.

Wirth confirmed optimization: 4 rigs to 3 with similar output, workover fleet optimized, contracts renegotiated. Long laterals in 60% of wells this year, 90% by 2027. Targeting ~200K boe/d plateau focused on cash flow, mirroring DJ and Permian approach.

CFO attributed strong Q2 distributions to faster-than-expected TCO ramp and higher-than-guided prices. Q3 will include first $1B loan repayment in adjusted free cash flow metric.

Wirth reported strong customer demand requiring narrowing of prospects. Working toward FID before year-end. Acknowledged cost pressures but emphasized returns discipline.

Wirth confirmed power investment fits within existing CapEx guidance and won't be 100% equity, but declined to share specific terms or capital amounts. Confidentiality limited the response.