Chord Energy Corp Q3 FY2024 earnings call

Key Managerial Messages - Danny Brown discussed third quarter performance, noting strong operating results leading to adjusted free cash flow of ~$312 million and plans to return 75% of this to shareholders. He mentioned the divestiture of DJ Basin assets and the impact of North Dakota wildfires on production, with expected fourth quarter oil volume impact of about 900 barrels per day. - Darrin Henke highlighted operational momentum, including Chord's leadership in longer laterals, with over 100 3-mile lateral wells turned in, improved D&C cycle times, and plans for 4-mile lateral wells. He also spoke about well spacing, which contributes to shallow declines and low reinvestment rates. - Richard Robuck provided details on third quarter results, including oil and gas realizations, operating costs (LOE, GPT, G&A), liquidity, and updated guidance, noting increased oil guide, trimmed capital guidance, and lower gas volumes for non-operated Marcellus production.

Chord Energy delivered a strong third quarter with adjusted free cash flow of approximately $312 million. Oil volumes were toward the top end of guidance, driven by strong execution, well performance, and lower downtime. Capital was below expectations due to operational efficiencies and timing adjustments. Operating expenses also came in below expectations. In terms of revenue contribution, no specific product segments were detailed, but overall financial performance was robust with strong free cash flow generation.

Forward-Looking Statements - Net of the divestiture, Chord increased full year pro forma oil guidance for the second time in 2024, despite wildfire impacts. - Full year capital guidance was trimmed reflecting improved program efficiencies. - Gas volumes were lowered to reflect latest estimates for non-operated Marcellus production. - Fourth quarter oil guide midpoint of 152,000 barrels per day adjusted for DJ divestiture and wildfire shut-ins, with oil differentials improving in the Williston Basin. NGL realizations expected similar to third quarter, and natural gas realizations expected to improve with AECO pricing.

Risks - Forward-looking statements subject to risks and uncertainties, including those described in earnings release and SEC filings. - Wildfires in North Dakota impacting production and causing short-lived curtailments. - Commodity price volatility affecting oil and gas realizations. - AECO pricing dislocations negatively impacting gas realizations in the Bakken. - Operational risks related to midstream issues, disposal constraints, and artificial lift installation affecting early production data.

Q: Neal Dingmann asked about the 3-year plan, price sensitivities, and well breakevens in different parts of the Bakken.

A: Danny Brown responded that the plan is geared around current commodity prices, and if efficiencies increase, they would maintain production profile and let free cash flow increase. He also discussed similar breakevens in different parts of the acreage due to wider spacing and longer laterals.

Q: Scott Hanold inquired about updated 3-mile EURs and the 3-year outlook, including synergies.

A: Danny Brown mentioned data showing confidence in 3-mile EURs, and Darrin Henke added that wells brought online in the last 12 months show production matching forecasts. On synergies, the $200 million+ synergies include capital synergies from the Enerplus plan, but continuous improvement is also a factor.

Q: Noah Hungness asked about coiled tubing to TD on extended laterals and incorporation of 3-mile laterals on legacy Enerplus acreage.

A: Darrin Henke stated the team is performing admirably with coiled tubing, and Danny Brown said there would be a mix of 2-mile and 3-mile laterals on legacy Enerplus acreage in 2025.

Q: Phillips Johnston questioned modeling assumptions in the 3-year plan, average wells, and decline rates.

A: Danny Brown provided directional comments, noting operated well count decrease due to longer laterals and slight increase in non-op wells. He expects downward pressure on decline rates with more 3-mile laterals.

Q: Oliver Huang asked about simul-frac percentage and share repurchases.

A: Darrin Henke said simul-frac is in the 2025 plan and is improving efficiencies. Danny Brown stated share repurchases have always been part of the program and would continue to be leaned into in the current environment.

Q: David Deckelbaum inquired about base decline rate impact of longer laterals and spacing on Enerplus acreage.

A: Danny Brown said it's a combination of factors including no significant growth program, low downtime, and 3-mile laterals. Darrin Henke added spacing is tied to completion intensity and continuously evolving.

Q: John Abbott asked about base decline rate in 2022 vs 2024 and spacing conservatism.

A: Danny Brown noted base decline was higher in 2022, and they are looking into spacing optimization as part of continuous improvement.

Q: Paul Diamond asked about 4-mile laterals and hedge book.

A: Darrin Henke said 4-mile laterals are not in the 3-year plan but are exciting for potential capital efficiency. Hedging is programmatic, layering on hedges quarterly.

Q: Noel Parks asked about gas price rebound impact and remaining Enerplus synergies.

A: Richard Robuck said gas price rebound would positively impact realizations due to fixed contracts. Danny Brown discussed remaining synergies, including operational improvements in rod practices and completion techniques, expected to materialize in 2025.