HighPeak Energy, Inc. — Q1 2023 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 assets in the Midland Basin of West Texas, primarily in Howard and Borden Counties. The filing covers the unaudited three months ended March 31, 2023, with comparison to the three months ended March 31, 2022. At quarter-end, the Company held approximately 127,227 gross and 112,745 net acres, operated approximately 98% of its net acreage and had five drilling rigs and four frac crews active.
Key financial and operating metrics
| Metric | Q1 2023 | Q1 2022 | Change |
|---|---|---|---|
| Total operating revenues | $223.8 million | $92.2 million | +143% |
| Income from operations | $88.6 million | $54.6 million | +62% |
| Operating margin | 39.6% | 59.2% | Down |
| Net income (loss) | $50.3 million | $(16.5) million | Improved |
| Diluted earnings (loss) per share | $0.39 | $(0.17) | Improved |
| Net margin | 22.5% | (17.9)% | Improved |
| Cash flow from operations | $190.0 million | $49.9 million | +280% |
| Capital additions to oil and gas properties | $379.1 million | $165.1 million | +130% |
| Average production | 37,222 Boe/d | 12,052 Boe/d | +209% |
Crude oil sales were $215.7 million, while NGL and natural gas sales were $8.1 million. Average production was approximately 31,507 Bbls/d of crude oil, 3,280 Bbls/d of NGLs and 14,611 Mcf/d of natural gas; liquids represented approximately 94% of production on a Boe basis.
Excluding derivatives, weighted average realized prices declined to $76.07 per crude oil Bbl from $96.15, $27.04 per NGL Bbl from $41.33 and $2.21 per natural gas Mcf from $4.16. Realized price per Boe declined 21% to $66.80. Production costs were $8.57 per Boe, broadly consistent with $8.62 in the prior-year quarter, while DD&A increased to $24.22 per Boe from $15.69. EBITDAX, a non-GAAP measure, was $173.9 million versus $51.1 million.
Cash and cash equivalents were $47.5 million at March 31, 2023, compared with $30.5 million at December 31, 2022. Operating cash flow and $146.5 million of financing cash inflows, primarily from $150.0 million of Credit Agreement borrowings, more than offset $319.5 million of investing cash outflows. The Company paid $2.8 million of dividends and dividend equivalents during the quarter.
Total debt principal was $895.0 million, consisting of $420.0 million outstanding under the Credit Agreement, $225.0 million of 10.000% Senior Notes due February 2024 and $250.0 million of 10.625% Senior Notes due November 2024. Reported debt, net of discounts and issuance costs, was $860.8 million. The Credit Agreement borrowing base was $700.0 million, elected commitments were $575.0 million and reported available borrowing capacity was $152.6 million. The Company obtained a waiver regarding its current-ratio covenant as of March 31, 2023.
Material changes versus the prior comparable period
- Production increased 209%, primarily from the horizontal drilling program, driving a 143% increase in revenue despite materially lower commodity prices.
- The Company generated a $3.1 million derivative gain versus a $66.4 million derivative loss in Q1 2022, including a $5.3 million noncash mark-to-market gain and $2.2 million of net cash settlement payments.
- DD&A increased 377% to $81.1 million, reflecting higher production, acquisitions and inflation in capital costs.
- Interest expense increased 414% to $27.0 million due to higher Credit Agreement borrowings, the 10.000% Senior Notes, the 10.625% Senior Notes and greater amortization of discounts and debt issuance costs.
- Capital spending increased substantially as the Company operated an average of five rigs and four frac crews during the quarter. The Company drilled 25 gross wells and completed 32 gross wells.
- Current liabilities increased to $561.4 million from $266.1 million, primarily because the 10.000% Senior Notes were classified as current.
Guidance, outlook, risks and unusual items
The Company reduced its 2023 development plan from a six-rig program to an expected average of two drilling rigs and two frac crews beginning in June 2023 and continuing through year-end. Current 2023 capital guidance is approximately $900 million to $975 million for drilling, completion, facilities and equipping, plus $50 million to $60 million for infrastructure and other costs, excluding acquisitions and certain corporate items.
Management expects operating costs and workover expenses per Boe to decline beginning in Q2 2023 as production returns after temporary outages, a new third-party facility reduces treating costs, natural gas takeaway capacity improves and workover activity decreases. Q1 production was affected by winter weather, a facility fire, offset completion operations and limited capacity at a new natural gas plant; management expected the gas takeaway issue to be resolved by late May or early June 2023.
The March 2023 Eighth Amendment increased the borrowing base to $700.0 million but requires the Company, by June 30, 2023, to redeem or refinance the 10.000% Senior Notes, allocate cash flow to retire them by November 30, 2023, or extend their maturity to at least February 15, 2025. Failure to satisfy this requirement would constitute an event of default and could accelerate the Credit Agreement. Management identified refinancing, additional secured borrowing, operating cash flow and equity or debt offerings as potential funding sources, but stated that these alternatives may not be available on attractive terms or at all.
On January 23, 2023, the Board began evaluating strategic alternatives, including a potential sale of the Company. The process remained exploratory, with no decision, timetable or assurance of a transaction as of the filing date.
Commodity prices, inflation, interest rates, supply-chain constraints, OPEC production decisions, geopolitical developments, regulatory changes and access to capital markets remain material risks. The Company had a $12.1 million net derivative liability at quarter-end and significant customer concentration: Delek accounted for approximately 76% of Q1 revenue and Energy Transfer Crude Marketing accounted for approximately 19%.
Subsequent to quarter-end, the Company terminated a related-party water-treatment contract in exchange for a $6.5 million payment during Q2 2023. It also entered into additional 2024 crude oil put options covering 5,000 Bopd from January through September 2024, with a $56.15 per Bbl strike price and $5.00 per Bbl deferred premium.
Most important facts for investors to verify
- Whether the Company successfully refinanced, redeemed or extended the $225.0 million 10.000% Senior Notes by the required deadlines and avoided a Credit Agreement default.
- Actual borrowing capacity, covenant compliance and liquidity after the April 2023 borrowing-base redetermination and subsequent debt activity.
- Whether the reduced two-rig/two-frac-crew plan supports production targets and the $950 million to $1.035 billion stated capital program.
- Resolution of the Flat Top natural gas takeaway constraints and the sustainability of Q1 production growth.
- Commodity price realization, hedge settlements and the effect of the Company’s 2023–2024 derivative positions on cash flow.
- Progress and ultimate outcome of the strategic alternatives review, including any transaction-related costs or financing implications.
- Exposure under minimum-volume, sand, crude oil delivery, connection-fee and other contractual commitments, including the reported remaining $16.3 million crude oil delivery commitment and $28.7 million sand commitment.