SANDRIDGE ENERGY INC Q3 FY2024 earnings call

• Acquisition: Closed acquisition in Western Anadarko Basin in August. New assets contributed to a peak average daily rate of nearly 19 MBoe per day, 27% increase in Boe basis production from Q2, 65% increase in oil basis. Two DUCs from acquisition completed, last two DUCs to come online in November. Benefits of acquisition include bolstering production and cash flow, diversifying commodity mix, upgrading inventory in Cherokee play with breakevens ~$35 WTI.
• Capital Program: Focus on optimizing production from incumbent assets with projects like artificial lift conversions, heel completions, recompletions. Incumbent leasehold ~99% held by production. Cherokee play leasing to bolster development opportunities next year.
• Operating Expenses: Lease operating expense for quarter was ~$9.1 million or $5.82 per Boe, a 9% reduction from prior quarter due to acquisition integration and reduced water handling costs.
• ESG and Strategy: Committed to ESG, strategy includes maximizing cash value of incumbent assets, capital stewardship, maintaining M&A optionality, returning capital to shareholders, and upholding ESG commitments. Strategy has five points: optimize incumbent assets, invest in high-return projects, maintain M&A optionality, return capital, and uphold ESG.

In the third quarter, SandRidge Energy had adjusted EBITDA of nearly $18 million. Production averaged approximately 19 MBoe per day, with 52% liquids. Interest income for the quarter was approximately $1.6 million, nearly offsetting adjusted G&A of ~$1.6 million. Cash including restricted cash at the end of the third quarter was more than $94 million. Revenue for the recently acquired assets in July and August were recorded as downward adjustments to the purchase price. The company's adjusted EBITDA is unique due to no debt and a substantial NOL position shielding cash flows from federal income taxes. Commodity price realizations were $73.7 per barrel of oil, $0.92 per Mcf of gas, and $16.25 per barrel of NGLs.

• Plan to develop 11 DSUs with 22 two-mile laterals in Cherokee play over next couple of years. Plan to drill ~12 wells next year with one rig or partial rig. Allocate capital to high-return projects in Cherokee play where breakevens are ~$35 WTI in high-graded areas. Continue to assess paths to maximize shareholder value including strategic opportunities and return of capital.

• Commodity price risks: Natural gas prices and WTI prices impact financials. Incumbent non-Cherokee assets have higher gas content and need commodity prices firmly over $80 WTI and $4 Henry Hub for further development. - NOL risks: Dependence on NOL position shielding cash flows, but changes in tax laws could affect this. - M&A risks: Uncertainty around successful integration of acquisitions and realization of synergies.

Q: Could you expand on drilling activity plans for the Cherokee play asset?

A: Our recent plans are to complete the DUCs and put together a plan to initiate drilling on joint spacing units extending into next year. We have 11 DSUs with 22 two-mile laterals to develop over the next couple of years. Plan is to develop with one rig or partial rig year, drilling one well every 30 days, which would be ~12 wells next year.

Q: Can you provide details about well cost and expected returns in the Cherokee play compared to legacy asset?

A: Cherokee assets have higher oil content than legacy assets (more gassy). Economics are more attractive today due to WTI-Henry Hub ratio. Breakevens in Cherokee play are roughly $35 WTI in high-graded areas, returns are robust enough to allocate capital there going into next year. Legacy assets need commodity prices firmly over $80 WTI and $4 Henry Hub for further development