HighPeak Energy, Inc. (HPK) Q3 2026 earnings review
HighPeak Energy refinances its debt, but drilling costs climb
HighPeak Energy, a West Texas oil and gas producer, pumped more oil than its plan called for and lined up a deal to replace its $1.2 billion term loan. Third-quarter revenue rose 23% from a year ago as higher crude prices outweighed an 8% drop in daily volume. Chief executive Michael Hollis raised the full-year production target, but he also lifted the capital spending budget by $45 million at the middle of the range to keep one rig drilling.
| Average daily production | 44.2 MBoe/d -8% from a year ago, above plan |
|---|---|
| Operating revenue | $256.8M +23% from a year ago on higher oil prices |
| Free cash flow | $22.4M after $71.1M of capital spending |
| Full-year production and capex outlook | Both raised output +6%, capital budget +17% at middle of range |
⚖️ Verdict: 🟢 Bullish
The story got better because the October refinancing agreement removes the threat of a third-quarter loan default. Paying off the term loan with $450 million of preferred equity and a new $800 million credit facility solves the maturity and debt-limit problem that hung over the business. One caution: reinvesting into extra drilling meant third-quarter capital spending ran 69% above what the old plan pointed to by our math, leaving less free cash flow to cut total obligations.
The question now is how much the new $450 million preferred equity will cost common shareholders. Either the preferred carries a manageable dividend that lets free cash flow pay down the new credit line, or it charges a high rate and converts into common shares. The closing filing later in November will provide the exact terms.
🐂 Bull Case
Refinancing Agreement Replaces the Term Loan
HighPeak Energy, a West Texas oil and gas producer, entered the quarter facing tighter debt limits on its $1.2 billion term loan. In the third quarter, the company paid its first scheduled $30 million principal installment, reducing total carrying debt to $1.16 billion. Then on October 6, management announced a "transformational comprehensive refinancing through a strategic $450 million preferred equity investment and a new $800 million credit facility."
The company plans to "pay off its existing $1.2 billion term loan upon closing the refinancing transaction which is expected to close later this month." Retiring the term loan removes the quarterly debt-to-profit tests that threatened a default if oil prices fell. Because the transaction had not closed by the release date, the filing notes that failure to complete it could still harm liquidity.
What to watch: the closing filing and the quarterly report for the dividend rate and conversion rules on the $450 million preferred equity. Those terms will show how much cash flow the new capital structure leaves for common shareholders.
Stronger Well Output Prompted an Outlook Raise
HighPeak has run a single drilling rig since January to hold oil and gas output steady. Three months ago, its unchanged annual target pointed to a steep drop in the second half of the year, down to 36,544–42,544 barrels of oil equivalent per day (Boe/d, a combined measure of oil and gas volume) by our math.
Instead, third-quarter sales volumes averaged 44,181 Boe/d as the producer connected 13 gross operated wells to sales lines. Because output beat the implied second-half pace by 12% by our math, chief executive Michael Hollis raised the full-year production forecast by 2,500 Boe/d at the middle of the range, to 44,500–45,500 Boe/d. That keeps fourth-quarter output near 44,920 Boe/d by our math, up 2.8% from a year ago.
What to watch: fourth-quarter daily sales volumes against the implied 44,920 Boe/d pace. Holding that rate with 18 gross wells in progress will show whether one rig can prevent annual production declines in 2027.
Natural Gas Prices and Hedges Lifted Realizations
Pipeline bottlenecks in West Texas pushed HighPeak's unhedged natural gas price to negative $1.50 per thousand cubic feet (Mcf) in the second quarter, meaning the company paid to move its gas. In the third quarter, regional prices turned positive at $1.42 per Mcf before hedges, and natural gas price swaps — contracts that lock in a fixed selling price — lifted the realized price to $2.37 per Mcf.
Together with an unhedged crude oil price of $86.86 per barrel, the gas rebound lifted overall unhedged revenue per Boe by 33% from a year ago to $63.18. For the fourth quarter, the company has swaps on 35,000 million British thermal units per day at $4.131 on the Henry Hub benchmark, paired with regional basis swaps at negative $1.455.
What to watch: fourth-quarter realized natural gas prices including hedges. Staying above $2.00 per Mcf will confirm that the new swap book protects revenue from West Texas pipeline discounts.
🐻 Bear Case
Higher Drilling Spend Cut Into Free Cash Flow
"As drilling efficiencies continue to improve, rather than releasing a rig, we plan to keep activity steady and reinvest those efficiency gains into additional high-return opportunities," chief executive Michael Hollis said. That decision reversed the second-half spending slowdown that the prior annual budget had pointed to.
- Full-year capital budget: raised by $45 million at the middle of the range to $310–320 million
- Third-quarter capital spending: $71.1 million, 69% above the $34.5–49.5 million quarterly pace implied by the old plan by our math
- Expense workovers (maintenance on existing wells): $1.91 per Boe, up from $1.49 in the second quarter and $1.00 a year ago
- Free cash flow: $22.4 million after a $36.0 million cash outflow for drilling payables, down from $37.6 million in the second quarter
Keeping the rig busy drilled 9 gross wells and prevented a drop in future output, but it consumed cash originally meant for debt reduction. Total unit lease operating and workover costs reached $8.61 per Boe in the quarter, up from $7.92 in the second quarter.
What to watch: fourth-quarter capital spending against the $57.4 million remainder implied by the new budget by our math. Another budget increase would show that holding output flat requires over $300 million a year.
Hedge Losses and Write-Offs Drove a Net Loss
HighPeak's loan agreements required it to lock in prices on most of its oil output at ceiling prices in the $60s per barrel. When market oil prices averaged over $86 in the third quarter, those contracts cost the company $9.22 per barrel of oil, or $21.3 million in cash settlements by our math. Combined with an $86.2 million noncash accounting charge on future contracts, derivative losses pushed HighPeak to a $55.7 million net loss.
Below the surface, exploration and abandonment costs jumped to $11.0 million (4.3% of revenue, up 3.2 percentage points from a year ago) because of $10.7 million in expired leases, dry-hole costs and well plugging. Crude oil also made up 66.8% of total volume — better than 64.0% last quarter, but below the 68.3% second-half share needed by our math to hit the 67% annual target.
What to watch: year-end proved reserves and fourth-quarter abandonment charges in the annual report. Continued lease write-offs would show that the drilling inventory is shrinking faster than one rig can replace it.
Risks this quarter didn't answer
Five standing financial and governance questions were not readable from the third-quarter earnings release and await the quarterly filing or the refinancing closing documents.
- Preferred equity cost and dilution: the dividend rate, payment terms and conversion price on the $450 million preferred investment were not disclosed; the closing filing will show them.
- Third-quarter covenant compliance: exact debt-to-EBITDAX and asset-coverage ratios at September 30 were not in the release; Note 7 of the quarterly filing will report them.
- At-the-market share sales: basic shares rose by 44,000 in the quarter, and the quarterly filing will confirm whether the $150 million share-sale program remained unused.
- Partnership share overhang and strategic review: the release gave no update on the potential distribution of over 75 million shares by HighPeak Energy Partners or the board's review of strategic alternatives.
- Customer concentration: reliance on Delek, which bought 88% of first-half oil and gas revenue, is only updated in the quarterly filing footnotes.
💲 Other KPIs
Operating profit more than doubled from $32.6 million a year ago, lifting the operating margin by 12.3 percentage points to 27.9% by our math. Higher oil prices lowered depletion and depreciation — the noncash write-down of well costs — by 8.8 percentage points of revenue, while field production costs fell 2.3 points, offsetting a 3.2-point rise in lease abandonment write-offs.
Uncollected customer bills rose 32.0% from the second quarter and nearly doubled from $55.5 million at year-end, even though quarterly revenue dipped 5.7% from the prior quarter by our math. That receivable build tied up cash and drove a $20.0 million working-capital drain on operating cash flow, trimming reported cash from operations to $109.6 million.
The backlog of drilled wells awaiting completion fell by 3 gross wells from 21 at the end of June, including 16 gross (11.4 net) wells currently in completion stages. HighPeak connected 13 gross wells to sales lines during the quarter while drilling 9 and completing 5, drawing down the inventory built during the second quarter's accelerated completion push.
🔮 Guidance
Raised. The middle of the full-year range moved up by 2,500 Boe/d, or 5.9%, pointing to a 6.8% decline from 2025. By our math, after averaging 45,027 Boe/d across the first nine months, the new plan leaves about 44,920 Boe/d for the fourth quarter — up 1.7% from the third quarter and 2.8% above last year's fourth quarter.
Lowered cost target (a positive revision). The company cut its full-year unit field cost forecast by $0.575 per Boe at the middle of the range, to $8.125 per Boe. Across the first nine months, lease operating and workover costs averaged $7.90 per Boe. By our math, the new annual range leaves room for fourth-quarter unit costs of about $8.80 per Boe.
Increased spending budget. Management raised full-year capital spending by $45 million at the middle of the range, to $315 million, as faster drilling adds wells to the schedule. Even after the increase, annual spending sits 38.5% below 2025 levels. By our math, after spending $257.6 million in the first nine months, the budget leaves $57.4 million for the fourth quarter.
❓ Key Questions
What are the terms of the $450 million preferred equity?
The refinancing replaces the $1.2 billion term loan using $450 million of preferred equity and an $800 million credit facility, but the release omits the dividend rate, whether dividends are paid in cash or kind, and whether the preferred shares convert into common stock.
Why did accounts receivable jump 32% in one quarter?
Accounts receivable rose by $26.6 million from June to $109.6 million at September 30 while quarterly revenue declined 5.7%. Investors need to know if this reflects normal payment timing from its main buyer, Delek, or a delayed settlement.
What caused the $10.7 million in lease and well write-offs?
Abandoned leasehold, dry hole and plugging costs rose to $10.7 million in the third quarter from $2.3 million a year ago. Management has not said how many drilling locations were dropped or whether water encroachment caused the write-offs.
Will HighPeak terminate its $150 million share-sale program after refinancing?
Management put a $150 million at-the-market common stock program in place in May when term-loan covenants were tight. Once the new credit facility closes in November, investors need to know if that equity program will be cancelled.