Baytex Energy Corp. Q2 FY2025 earnings call

Operational Results

• Pembina Duvernay achieved highest 30-day peak oil rates in West Shale Basin. Eagle Ford delivered strong refracs at half cost of new wells. Heavy oil production up 7% QoQ.

Financial Results

• Adjusted funds flow was $367 million or $0.48 per basic share, net income $152 million, free cash flow $3 million. Net debt decreased $96 million to $2.3 billion. Repurchased USD 41 million of 8.5% long-term notes.

Efficiency Gains

• 12% improvement in drilling and completion costs in Pembina Duvernay, 11% improvement in Eagle Ford, and heavy oil operations capital-efficient.

Pembina Duvernay

• First pad achieved average 30-day peak production rates of 1,865 BOE per day per well with 3,800-meter completed lateral length. Second pad came on stream with similar lateral lengths and averaged 1,264 BOE per day per well over the last 26 days. Third pad expected onstream in September. Drilling and completion costs improved by 12% compared to 2024. Plan to transition to full commercialization with targeting 18 to 20 wells per year, resulting in production ramping to 20,000 to 25,000 BOE per day by 2029 - 2030.

Eagle Ford

• Brought on stream 15 wells, with approximately 11% improvement in drilling and completion costs. Delivered 2 additional refracs with initial rates comparable to broader development program at approximately half the cost, and 300 refrac opportunities identified across acreage.

Heavy oil

• Production grew by 7% quarter-over-quarter. Brought on stream 43 wells across Peavine, Peace River and Lloydminster.

Forward-looking

• Expect to generate approximately $400 million of free cash flow in 2025, majority weighted to second half. Plan to allocate 100% of free cash flow to debt repayment after funding quarterly dividends, targeting net debt of approximately $2 billion by year-end. Oil-weighted production profile with ~84% of production weighted towards crude oil and liquids. Every USD $5 per barrel change in WTI impacts annual adjusted funds flow by approximately $225 million on unhedged basis.

Q: Can you let us know what your average well cost is averaging up there in the Pembina Duvernay?

A: The average well cost so far this year has been running right at $12.5 million. So for a 12,000-foot lateral, a 12,500-foot lateral, that's right at $1,000 per completed lateral foot.

Q: Is the decline rate different post the refracs in the Eagle Ford?

A: It's still a little early. The early rates are strong. The pressure performance is strong. But it's a little bit too early on the 2 refracs in 2025 to know really with data specificity around decline rates.

Q: What are you doing differently over in the Eagle Ford to get the cost improvement?

A: A combination of service cost reductions (due to drill rig and frac activity levels dropping), continued efficiency gains (measured in lateral footage per day or completion pump hours per day), and switching to field gas on the frac side instead of burning diesel.