Coterra Energy Inc. Q2 FY2025 earnings call

• Coterra had an excellent second quarter, exceeding production guidance for natural gas and total BOE, and coming well above midpoint on oil volumes. Revenues were balanced between oil and gas. - Update on Culberson Harkey program: Issues localized to Windham development, making progress with new wells in the vicinity showing strong performance. - Shane Young covered financial results, updated Q3 and full year 2025 guidance, with full year production midpoint increased by 4% to 768 MBoe per day, natural gas volume midpoint up 5% to 2.9 Bcf per day. - Blake Sirgo discussed operational activity: Maintaining rig counts, cost reductions in Permian, strong results in Marcellus and Anadarko, and new gas marketing deals like the power netback deal in the Permian.

During the second quarter, Coterra's oil production was 2% above the midpoint of guidance, natural gas was above the high end of the guidance range, and BOEs were also above the high end. Revenues for the quarter were nicely balanced between oil and natural gas, inclusive of natural gas liquids. Cash operating costs totaled $9.34 per BOE, down 6% quarter-over-quarter. Net income was $511 million or $0.67 per share, and adjusted net income was $367 million or $0.48 per share. Discretionary cash flow for the quarter was $949 million, and free cash flow was $329 million after cash capital expenditures. Oil contributed 52% of revenues, a 7% increase quarter-over-quarter due to higher oil volumes.

• For Q3 2025, total production is expected to average between 740 and 790 MBoe per day, oil between 158 and 168 MBoe per day, and natural gas between 2.75 and 2.9 Bcf per day. Capital for Q3 is at the midpoint of $650 million, expected to be the high quarter for the year. - Full year 2025: Increased annual MBoe per day production guidance midpoint by 4% to 768, maintained oil guidance midpoint, tightened natural gas volume guidance range, and expects full year capital to be about $2.3 billion with a reinvestment rate of around 50% of cash flow.

• Commodity price uncertainty due to factors like OPEC+ curtailments cessation and natural gas price weakening. - Potential impact of Tier 1 inventory decline leading to increased cost structure and commodity price increases. - Initial issues with Harkey wells in Windham development, though remediation efforts are successful and issues localized.

Q: Neil Mehta asked about conviction in resolving Harkey issues and timeline for optimal production, and about the $100 million activity increase in Marcellus.

A: Thomas E. Jorden said remediation efforts are successful, wellbore design changed, and Marcellus program has best returns currently. Blake A. Sirgo added consistent activity in Marcellus with lowered costs.

Q: Arun Jayaram inquired about oil growth trajectory beyond fourth quarter and Harkey wellbore design application.

A: Thomas E. Jorden stated steady upward trend in production, and Blake A. Sirgo mentioned consistent operational cadence. Thomas E. Jorden confirmed confidence in using new wellbore design in Culberson County.

Q: Doug Leggate asked about industry production impact and gas strategy considerations.

A: Thomas E. Jorden said Coterra's low cost of supply and stable cash flow help through cycles, and Blake A. Sirgo noted sales portfolio and tools like managing production if needed.

Q: Betty Jiang asked about cash taxes and buyback plans.

A: Shannon E. Young explained tax benefits from bonus depreciation and R&D, and mentioned buybacks will increase once term loans are paid off.

Q: Nitin Kumar inquired about oil volume trajectory beyond fourth quarter and gas marketing mix.

A: Thomas E. Jorden said steady growth with quarter-to-quarter fluctuations, and Blake A. Sirgo said new gas volumes are reallocations of existing sales for diversity and price enhancement.

Q: Scott Gruber asked about oil strategy and Harkey well design cost.

A: Blake A. Sirgo and Thomas E. Jorden discussed operational consistency and completion crews, and Blake A. Sirgo explained focus on mechanical isolation in well design.

Q: Kalei Akamine asked about cash use and buyback priorities.

A: Shannon E. Young said debt paydown is facilitator for buybacks, and they expect more buybacks once term loans are paid off.

Q: Nitin Kumar followed up on Mid-Con capital and Harkey well dewatering timeline.

A: Michael D. Deshazer talked about 3-mile projects in Mid-Con and Blake A. Sirgo said Harkey wells will dewater gradually over time.

Q: Derrick Whitfield asked about power gen success and Anadarko capital costs.

A: Thomas E. Jorden and Blake A. Sirgo discussed power deal benefits and Michael D. Deshazer talked about Anadarko's costs and lateral length extensions.

Q: Matthew Merrel Portillo asked about Dimock box wells and Northeast PA power opportunities.

A: Thomas E. Jorden and Blake A. Sirgo mentioned continued drilling in Dimock box and need for differentiated power deals in Northeast PA.

Q: Phillip Jungwirth asked about Avant acreage delineation.

A: Michael D. Deshazer discussed geological aspects and results in different intervals of the Northern Delaware Basin.

Q: Phillip Jungwirth followed up on Appalachia marketing.

A: Blake A. Sirgo and Thomas E. Jorden talked about marketing deals needing diversity or price enhancement.

Q: Paul Cheng asked about Anadarko M&A interest and gas marketing contracts.

A: Thomas E. Jorden said Anadarko is a solid part of portfolio, and Blake A. Sirgo said gas marketing contracts are about diversity and price enhancement with dynamic targets.

Q: Leo Mariani asked about Franklin Mountain and Avant acquisitions update.

A: Thomas E. Jorden said integrated operations with wells meeting or exceeding expectations, and Coterra's stamp on future results.