Kevin MacCurdy

Marcel said $200M is the ratable base EBITDA; high-volatility years run 1.5x-2x, with value driven by logistics optimization.

Josh cited fastest-ever Utica well plus ongoing focus on perfecting three-mile laterals in Haynesville. Haynesville rig count increase from competitors has not impacted costs yet. Service costs stable outside diesel inflation from Iran conflict.

Josh confirmed encouraging early results from first well online since early March. Confirmed good overpressured reservoir from pilot well. Second well spudded 50 miles north for acreage appraisal. Already on lower end of competitor cost curve on first well with expectation of further cost reduction.

Josh reported first horizontal well drilled at very low end of competitor costs in the Western Haynesville. Being completed with first production expected late Q1 to early Q2 2026. Two additional wells planned for acreage appraisal. Key focus on longer-term decline parameters.

Josh emphasized $225 million maintenance CapEx improvement in one year. Business efficient up to 7.75 Bcf per day but production level driven by mid-cycle price view of $3.50 to $4. The $0.50 range is significant and production will flex based on price environment.

Josh detailed 1.5 decades of data integration, calibrated models, and vertical well validation. Selected area with less structural complexity. Acknowledged uncertainty remains around long-term decline. First horizontal well in Q4. Can be measured given 20 years of Louisiana inventory.

Josh highlighted drilling improvements exceeding expectations plus two completion advantages: self-sourced sand mine (pays out in just over a year, enables 2-4 frac crews) and Gen 1 through Gen 3 completion design evolution with each generation outperforming the last.

Nick distinguished between capital spend (driven by long-term fundamentals, not changing) and production decisions (flexible based on near-term conditions). Productive capacity framework designed to build optionality rather than commit to production levels.

Nick firmly redirected to integration focus, noting high-bar nonnegotiables have worked historically. Signaled no near-term appetite for additional M&A.

Dan cited Plaquemines ramping, Golden Pass expected 2026, Louisiana LNG announced, all driving premium pricing at Gillis. Expects basis to widen favorably with pull across Haynesville.

Josh confirmed Q3 and Q4 CapEx trajectory roughly in line with Q2, consistent with full-year ~$3 billion target.

Kaes clarified the LOE beat was volume-driven with flat OpEx dollars and guided to circling the $6 range.

6.2M lateral feet for full year; 1.5-1.6M per quarter back half. Q1 lateral length lighter at 11.5%, full year target 12.9%, ramping through year.

5 wells tested with variable results (0 to 400-500 bpd uplift, avg 100). Studying what drove success vs failure. Version 1.0, could be mega theme extending basin life by a decade or 2.

Kaes cited EDS drop-down impact on LOE, higher unhedged power prices ($0.10-0.20 headwind), and increased workover/P&A spending. GP&T increase from CPI escalators and more molecules taken in kind.

Danny said Barnett needs an upgraded rig package due to depth and mud properties. Some areas like Spanish Trail will overlap with shallow development where they share facilities.

Kaes emphasized Viper's private data as a huge, underappreciated asset, allowing FANG to study and replicate peer developments faster than anyone else at scale.

Danny confirmed 15% casing inflation already absorbed with more anticipated; procurement agreement reprices quarterly on a formula basis.

Kaes said FANG is focused on debt and share count reduction rather than M&A; anything pursued would need to be extremely cheap.

Kaes provided clean breakout: $200M for Double Eagle, leaving $3.6-4.0B for legacy, tying to $900M-$1B Q1 CapEx guide.

Clay said WaterBridge relationship remains operationally important but equity ownership is option value; no obligation to hold or sell.

Clay acknowledged gas-driven Anadarko interest and structural pricing advantages vs Waha; Board regularly evaluates all portfolio options.

Clay confirmed 2026 productivity not sacrificed; efficiency gains (16→14→11 rigs) maintain same output.

Clay described monthly evaluation cycle; acknowledged current headwinds feel 'stickier' than recent 24-month volatility.

Clay cited Williston/Grayson $600K/well savings and BPX dissolution as key drivers, with no assumed deflation.

Andy attributed the CapEx range primarily to NFE/NFS timing uncertainty and potential non-operated Lower 48 ballots. Framed as general uncertainty rather than a specific risk scenario.

Kirk Johnson described 104 WA coming online a month early. Next pad 104 WB expected in ~12 months. New pads every 12-18 months at level-loaded pace. Gross volumes climbing despite higher royalties after payout. Capital and production tracking on trend.

Kirk Johnson outlined CapEx declining from ~$2B to ~$500M sustaining post first oil, with CFO from 100% oil at Brent premium driving the $4B FCF improvement.

Bill Bullock explained higher effective tax rate from income mix shift to higher-tax jurisdictions and discrete deferred items from Lower 48 dispositions.

Knop expected Appalachian basis divergence to become more real over the next year as demand sinks show up, though futures markets aren't yet pricing it.

Jeremy clarified higher TIL count reflects combo development lumpiness not growth setup; any intentional growth beyond efficiency-driven gains will be explicitly communicated.

Jeremy detailed roughly $80M of Olympus EBITDA from midstream, with assets sold at M2 pricing and potential to move volumes into the more premium M3 market via TeCo.

Jeremy clarified MVP capital contribution change is purely an accounting reclassification between distributions and contributions with no net impact on economics.

Tom Jorden confirmed parallel approach with debt repayment front-loaded and buybacks back-loaded. Cited historical 90% and 76% returns to shareholders as enabled by low leverage.

Michael Deshazer confirmed healthy DUC inventory with no frac line issues from Harkey-to-Wolfcamp swap. At 7 rigs long-term, maintaining a third frac crew would be difficult, but ample market capacity for spot work.