Callon Petroleum Company

Third-quarter total production averaged 102,000 BOE/d, and oil sales averaged about 58,000 bbl/d. Management said it generated nearly $50 million in adjusted free cash flow in the quarter, marking the 14th consecutive quarter of adjusted free cash flow generation. Quarter-end long-term debt was approximately $1.9 billion, down more than $300 million from the prior period. For Q4, Callon guided to oil production of 56,000 to 59,000 bbl/d and total production of 100,000 to 103,000 BOE/d, with approximately 79% liquids. The company also said full-year and fourth-quarter 2023 capital investment forecasts remain unchanged despite additional drilling and completion activity.

Joe Gatto framed the quarter as one of solid operational execution and improving financial discipline, with the company focused on maximizing free cash flow, reducing debt, and returning capital through buybacks. He emphasized that recent drilling, completion, and facilities improvements should be durable into 2024, enabling lower reinvestment rates and better capital efficiency. His tone was constructive but disciplined, noting near-term oil headwinds while stressing that Callon is prioritizing cash generation over headline production growth.

Kevin Haggard mainly handled opening remarks and process commentary, pointing investors to the release, supplemental slides, and non-GAAP reconciliations. The key financial figures discussed on the call were the nearly $50 million of adjusted free cash flow, about $1.9 billion of long-term debt, and management’s plan to repurchase shares using up to 40% of adjusted free cash flow in Q4. He also reiterated that the company remains focused on reducing debt and strengthening the balance sheet.

Analysts pressed management on where the expected 15%+ DC&F savings would come from, with Russell Parker breaking it down as roughly 15% on drilling, 5% on completions, and 50% on facilities, driven by fit-for-purpose design, casing reductions, better bits, sand/logistics improvements, and more efficient facility buildouts. Questions also focused on why oil volumes were weak in Delaware West, and management said higher GORs reflected the area’s gassier nature plus possible depletion from offset activity, leading to spacing and bench-design adjustments. Other questions addressed 2024 capital spending, which management said is more complicated than simply taking 15% off CapEx because cycle times, reinvestment discipline, and the timing of savings all matter.