HighPeak Energy, Inc. — Form 10-Q Summary
Business Context and Reporting Period
HighPeak Energy is an independent exploration and production company focused on crude oil, NGL and natural gas in the Midland Basin of West Texas. The filing covers the unaudited three months ended March 31, 2024, compared with the three months ended March 31, 2023.
- Leasehold position: approximately 143,414 gross acres and 132,891 net acres; average working interest of approximately 93%.
- Development activity: two drilling rigs and one frac crew at March 31, 2024, with management expecting to maintain that average for the remainder of 2024.
- Average production: 49,729 Boepd, including 39,959 Bopd of crude oil, 5,147 Bbls per day of NGLs and 27,733 Mcf per day of natural gas.
Financial Performance and Key Metrics
| Metric | Q1 2024 | Q1 2023 | Change |
|---|---|---|---|
| Total operating revenue | $287.8 million | $223.8 million | +29% |
| Income from operations | $103.0 million | $88.6 million | +16% |
| Net income | $6.4 million | $50.3 million | -87% |
| Diluted earnings per share | $0.05 | $0.39 | Decrease |
| Net cash provided by operating activities | $171.4 million | $190.0 million | -10% |
| EBITDAX | $233.3 million | $173.9 million | +34% |
- Crude oil sales increased to $282.4 million from $215.7 million, while NGL and natural gas sales declined to $5.4 million from $8.1 million.
- Operating margin was approximately 35.8% of revenue, compared with 39.6% in the prior-year quarter. Net margin declined to approximately 2.2% from 22.5%.
- Production increased 34%, but average realized commodity prices excluding derivatives declined 5% to $63.59 per Boe. Crude oil prices increased 2% to $77.65 per barrel; NGL prices decreased 8% to $24.94 per barrel; natural gas prices decreased 40% to $1.33 per Mcf.
- Production costs decreased 8% to $30.3 million, or $6.30 per Boe excluding expense workovers, compared with $8.57 per Boe.
- DD&A increased 61% to $130.9 million, and DD&A per Boe increased 19% to $28.92, reflecting higher production and inflationary capital costs.
- Interest expense increased 62% to $43.6 million, primarily due to the $1.2 billion Term Loan Credit Agreement and higher borrowing costs.
- Derivative loss was $53.0 million, compared with a $3.1 million gain in Q1 2023, including a $47.9 million noncash mark-to-market loss and $5.1 million of cash settlement payments.
- Effective income tax rate was 26.3%, compared with 22.4%.
Cash Flow, Debt and Liquidity
- Cash and cash equivalents were $173.4 million at March 31, 2024, compared with $194.5 million at December 31, 2023.
- Cash used in investing activities was $148.2 million, including $147.7 million of additions to crude oil and natural gas properties.
- Cash used in financing activities was $44.4 million, including a $30.0 million mandatory term-loan repayment, $8.8 million of share repurchases and $5.6 million of dividends and dividend equivalents.
- Total debt, net of discounts and issuance costs, was $1.125 billion, including $1.170 billion of principal under the Term Loan Credit Agreement. Current maturities were $120.0 million.
- The Term Loan Credit Agreement matures September 30, 2026, bears interest at Adjusted Term SOFR plus a 7.50% margin, and requires quarterly principal installments of $30.0 million plus potential excess-cash-flow prepayments.
- The Senior Credit Facility Agreement has $100.0 million of commitments, with no borrowings outstanding at March 31, 2024. Reported available borrowing capacity was $93.1 million.
- Debt covenants include a minimum 1.50-to-1.00 asset coverage ratio and a maximum 2.00-to-1.00 total net leverage ratio.
- Management expects 2024 capital expenditures of approximately $450 million to $525 million for drilling, completion, facilities and equipping, plus $50 million to $60 million for infrastructure and other costs.
Material Changes Versus the Prior Comparable Period
- Production growth from the horizontal drilling program materially increased revenue, but lower NGL and natural gas prices and a $53.0 million derivative loss reduced net income.
- Twenty-five gross horizontal wells were drilled and 12 gross wells were completed during the quarter; all completed wells were in the Flat Top area.
- DD&A, interest expense and general and administrative expense increased materially, while production costs and exploration and abandonment expense decreased.
- The company initiated its first common-stock repurchase program in February 2024, authorizing purchases of up to $75.0 million through December 31, 2024. It repurchased 565,540 shares for approximately $8.8 million at an average price of $15.50 per share; approximately $66.2 million remained authorized at quarter-end.
- The quarterly dividend increased to $0.04 per share from $0.025 per share in the prior-year quarter.
- The company entered into the First Amendment to its Senior Credit Facility Agreement on March 29, 2024; current commitments remained $100.0 million.
Guidance, Outlook, Risks and Unusual Items
- Management plans to maintain an average two-rig and one-frac-crew program for the remainder of 2024, while assessing drilling and completion activity monthly based on economics.
- Gas takeaway issues continue to curtail some sales volumes. The company is working with gas-processing partners to address the constraint.
- Commodity prices remain the principal operating risk. A $1.00 per barrel change in crude oil prices would affect annualized revenue by approximately $15.1 million, excluding derivatives; a $0.10 per Mcf change in natural gas prices would affect annualized revenue by approximately $1.0 million.
- Hedging reduced exposure to commodity-price volatility but also generated a substantial Q1 loss as crude oil prices increased after contracts were entered into. Net derivative positions were a $13.5 million liability at quarter-end.
- Other risks include high leverage and mandatory debt amortization, floating interest rates, capital-cost inflation, drilling and completion execution, supply-chain and oilfield-service availability, geopolitical events, OPEC actions, regulatory changes, weather, cybersecurity and customer concentration.
- Delek represented approximately 76% of Q1 sales revenue and Energy Transfer Crude Marketing represented approximately 17%. Management believes alternative purchasers are available because the products are fungible.
- The company has a crude oil delivery commitment with an estimated remaining exposure of approximately $5.5 million if no additional volumes are delivered, and a sand-purchase commitment with an estimated remaining exposure of approximately $19.1 million if no sand is taken.
- The board’s strategic-alternatives review, including a potential sale of the company, remains exploratory. No timetable, transaction or specific strategic action has been approved.
- Management concluded that disclosure controls were effective and reported no material change in internal control over financial reporting. The company reported no material change to previously disclosed risk factors.
Important Facts for Investors to Verify
- Reconcile production growth and realized prices to revenue, including the effects of gas takeaway constraints and commodity mix.
- Review the sustainability of cash flow after $30.0 million quarterly debt amortization, planned capital spending, dividends and share repurchases.
- Monitor compliance with the asset-coverage and leverage covenants and the availability of the Senior Credit Facility.
- Evaluate derivative volumes, settlement prices, maturities and potential cash requirements, particularly given the Q1 $53.0 million derivative loss.
- Assess the impact of higher DD&A rates, capital-cost inflation and interest expense on future margins and returns.
- Track the remaining crude oil delivery and sand commitments, gas takeaway remediation and customer concentration.
- Determine whether the strategic-alternatives review progresses beyond its preliminary stage; the filing provides no clear expected outcome or valuation.