Coterra Energy Inc. Q4 FY2024 earnings call

Fourth Quarter and Full Year 2024 Performance - Strong fourth quarter with oil and gas production above guidance, free hedge revenue significant, and net income and adjusted net income solid. - Full year 2024 saw excellent production and capital efficiency with lower capital spending and strong production. ### 2025 Capital Plan - Aligns with November announcement regarding Franklin Mountain and Avant acquisitions. - 2025 capital program includes integration of newly acquired Permian assets, with flexibility to pivot and reallocate capital. - Potential to accelerate Marcellus program if gas market outlook persists, adding $50 million to 2025 capital program. ### Acquisitions - Successfully closed Franklin Mountain and Avant acquisitions in late January, actively integrating assets to optimize efficiency. ### Three-Year Outlook - Updated three-year outlook positions Coterra for industry-leading profitable growth, capital efficiency, and reinvestment rates. ### Shareholder Returns - 2024 returned 89% of free cash flow through dividends and share buybacks. 2025 aims to prioritize deleveraging, repay $1 billion term loans, and return 50%+ of free cash flow to shareholders. ### Operational Highlights - Strong performance in Permian, Anadarko, and Marcellus basins with efficient operations, cost reductions, and productivity improvements. For example, Wyndham Row in Culberson County showed excellent reservoir performance, and Marcellus team achieved record low-cost structure.

In the fourth quarter of 2024, oil and natural gas production each came in over 3% above the high end of guidance. Free hedge revenue was over $1.4 billion, with oil making up 50% of total revenue during the quarter. Net income was $297 million ($0.40 per share) and adjusted net income was $358 million ($0.49 per share). For the full year 2024, total equivalent production beat the high end of guidance at 677 MBOE per day. Oil production grew 13% year over year, and natural gas production was in line with the high end. Capital costs for the full year were $1.76 billion, a 16% decrease year over year, and cash operating cost per unit was $8.66 per BOE.

2025 Production and Capital - First quarter 2025 production expected to average 710-750 MBOE per day. - Full year 2025 production expected to average 710-770 MBOE per day, with oil at 152-168 MBO per day and natural gas at 2.675-2.875 BCF per day. - Three-year outlook (2025-2027) anticipates 5% or greater oil volume growth and 0-5% per BOE growth with capital investment of $2.1-2.4 billion per year. - Prioritize deleveraging, aiming to repay $1 billion term loans and return 50%+ of free cash flow to shareholders in 2025.

Risks - Gas market volatility could impact production and capital allocation decisions. - Operational challenges in integrating acquired assets and maintaining efficiency. - Macroeconomic factors affecting cash flow and the ability to meet deleveraging and shareholder return goals.

Q: Could you discuss some of the key lessons learned from the Wyndham Row, including the interplay between the Wolfcamp and the Harkey programs?

A: Tom Jorden mentioned excellent reservoir performance, and Michael DeShazer noted data is still being analyzed but current plan is to co-develop where possible.

Q: Can you talk a little bit about what's happening in one queue on a sequential basis regarding the 2025 guide?

A: Blake Sirgo explained that the partial month of production from acquired assets affects the guide, but activity-wise it's smooth, and there's reallocation of capital to the Marcellus.

Q: What's your thought process on restarting two rigs in April in the Marcellus and what are the milestones to accelerate activity?

A: Tom Jorden said it's driven by constructive gas market fundamentals and economics, and Shane Young added it's based on current fundamentals and not just leaning into gas market.

Q: What's your perspective post-Franklin Mountains of further bolt-ons?

A: Tom Jorden stated they are opportunistic, acquire when it makes sense for the organization and owners, and only if entry price is reasonable.

Q: Will the focus continue to be primarily on Lower Marcellus and what about co-developing upper?

A: Michael DeShazer said they will return to the box in 2025 with overfilling of Upper Marcellus wells and co-development plans, with upper being lower in productivity but still part of the program.

Q: Regarding the three-year outlook and gas market, would both Anadarko and Marcellus return to growth if gas market plays out?

A: Blake Sirgo said it's a dynamic market, they position to take advantage, and price ratios matter in capital allocation across basins.

Q: Could you talk about downstream partnerships for data centers in Permian and other basins?

A: Blake Sirgo said Permian is where most discussions are, but it's uncharted waters with tough commercial deals.

Q: If ramping gas volumes further, can it be done in Marcellus?

A: Blake Sirgo said there's room in Marcellus takeaway capacity, and volumes could be grown with considerations of incremental costs.

Q: Regarding unit OpEx guide moving up, what's driving it?

A: Blake Sirgo said it's due to new assets being oily with low GOR, tilting the unit cost mix.

Q: On the gas asset and upper Marcellus threshold, what's the new threshold?

A: Tom Jorden said still looking at mid-threes, considering market resiliency and potential price drops.

Q: Impact of acquisitions on future cash taxes?

A: Shane Young said still refining tax allocations, expecting effective tax rate in 20% to 25% range, with improvement from bringing over basis.

Q: Runway in Dimock for Marcellus?

A: Michael DeShazer said there's still undeveloped north side of the box, with cost efficiencies and continued activity expected.

Q: Comparison of returns in traditional Permian program vs lower Marcellus today?

A: Tom Jorden said they are very comparable in the range of $4 Henry Hub and $70 WTI.