• Production Volumes: Averaged over 51,000 barrels of oil per day in Q3 2024.
• Free Cash Flow: Generated positive free cash flow for the fifth consecutive quarter.
• Production Guidance: Increased full-year 2024 production guidance to 48,000 to 51,000 BOEs per day, a 10% increase from the initial 2024 guide.
• Capital Expenditures: Expected to fall within $540 million to $580 million for 2024.
• EBITDAX per BOE: Unhedged EBITDAX per BOE at $45.68, over 65% higher than peer group average.
• Lease Operating Expense: Reaffirmed 2024 guidance despite additional expenses due to storm damage.
• Well Costs: Drilling, completion, and equipping costs running 9% below Q1 2024 levels.
• Middle Spraberry Well Performance: Kallus well achieved a max oil IP of roughly 1,500 barrels of oil per day.
• Wolfcamp A Well Performance: Judith well reached an oil IP of 1,700 barrels of oil per day.

• Warning! GuruFocus has detected 3 Warning Signs with HPK.

Release Date: November 05, 2024

For the complete transcript of the earnings call, please refer to the full earnings call transcript.

Positive Points

• HighPeak Energy Inc (NASDAQ:HPK) achieved another solid quarter of execution, with production levels outperforming initial expectations.
• The company generated positive free cash flow for the fifth consecutive quarter, utilizing it to pay down debt and execute a share buyback program.
• Production volumes averaged over 51,000 barrels of oil per day, leading to an increase in full-year production guidance.
• HighPeak's EBITDAX per BOE remains significantly higher than peers, driven by a high oil mix and low operating expenses.
• The company has identified approximately 300 Middle Spraberry locations, adding to its inventory of sub-$50 breakeven wells.

Negative Points

• Operations were affected by a major storm, causing some production volumes to be offline and increasing lease operating expenses.
• Despite strong performance, the company faces challenges in convincing the market of its cost structure advantages compared to peers.
• The company's acreage is shallower, which could lead to less natural gas production compared to peers, impacting revenue diversification.
• There is a need for continued infrastructure investment to support field-wide operations and maintain cost efficiencies.
• The strategic alternatives process is ongoing, with no specific details provided, creating uncertainty about future directions.

Q & A Highlights

Q: Focusing on slide 8 and your Kallus 34-39 Spraberry Well. Do you plan to offset that? And if so, to what direction and what would be the timing on offsetting this Middle Spraberry well? A: John, this is Mike. We're extremely excited about the Middle Spraberry results. We would like to have more wells like the Kallus well, which is producing 1,500 barrels of oil a day. We plan to delineate further, possibly moving a couple of miles north, south, or east to test a larger swath of our acreage. We expect to conduct these tests in the next quarter or two.

Q: On the Judith 67-5, you've extended your Wolfcamp A further to the east. How do you feel about this expansion? A: Absolutely, John. We're seeing strong results from our wells in the northern extension of Flat Top. Early results are promising, and we expect to provide more data next quarter. Our inventory is strong across our acreage, supporting our 1,150 sub-$50 breakeven wells. We anticipate adding more wells to this category as we continue testing.

Q: On both the Kallus well and the Judith well, what can you take from the log penetrations and the data you got while the well was drilling to help de-risk the locations? A: Jeff, the wells behaved consistently during drilling, and we gather extensive data, including log data and cutting samples. This data supports our confidence in the commerciality of wells across our acreage, substantiating our large inventory.

Q: Does the performance of the Judith well reflect any changes in drilling or stimulation methods? A: The Judith well is a standalone parent well. We continuously optimize our completion techniques, which could lead to better performance. The geology is consistent, and improvements are due to incremental changes in our processes.

Q: Your cost differences versus the central part of the Midland Basin are due to being further up on the shelf, correct? A: That's correct. Our acreage is shallower, requiring less drilling time and materials, which reduces costs. This allows our rigs to drill more wells per year, enhancing our efficiency and cost-effectiveness.

For the complete transcript of the earnings call, please refer to the full earnings call transcript.