HighPeak Energy, Inc. — Form 10-K Summary
Reporting period: Fiscal year ended December 31, 2021. The filing is an annual report rather than a standalone fourth-quarter filing. Comparisons with 2020 are affected by the August 21, 2020 business combination and the use of Successor and Predecessor periods.
Business Context
HighPeak Energy is an independent exploration and production company focused on crude oil, NGL and natural gas assets in Howard County, Texas, within the Midland Basin. At December 31, 2021, the Company held approximately 82,023 gross acres and 62,603 net acres, operated approximately 90% of its net acreage and had an average working interest of approximately 76%.
The Company owned interests in approximately 246 gross producing wells, including 59 gross horizontal wells. During 2021 it placed 30 gross horizontal wells on production, while 22 gross horizontal wells were awaiting completion or in various stages of completion at year-end.
Financial and Operating Metrics
| Metric | 2021 | 2020 comparable periods |
|---|---|---|
| Operating revenues | $220.1 million | $24.6 million combined Successor and Predecessor |
| Net income | $55.6 million | $(101.5) million combined net loss |
| Diluted earnings per share | $0.54 | $(0.18) for the Successor period |
| Average daily sales volumes | 9,304 Boepd | 1,925 Boepd for the full-year 2020 operating comparison |
| Average realized price | $64.82 per Boe | $34.94 per Boe |
| Lease operating expense | $7.38 per Boe | $10.68 per Boe |
| Cash provided by operating activities | $147.0 million | $(4.1) million combined Successor and Predecessor |
| Capital expenditures and acquisitions | $292.1 million total costs incurred, including $54.0 million of acquisitions | Not directly comparable because of successor/predecessor presentation |
Production was approximately 95% liquids by Boe. Average realized prices increased to $70.10 per crude oil barrel, $35.11 per NGL barrel and $3.88 per Mcf of natural gas, compared with $37.96, $14.06 and $1.04, respectively, in 2020.
Operating costs included $25.1 million of production costs, $10.7 million of production and ad valorem taxes, $65.2 million of DD&A, $8.9 million of general and administrative expense and $6.7 million of stock-based compensation. The Company recorded a $26.7 million net derivative loss, consisting of $11.3 million of cash settlement losses and $15.4 million of net mark-to-market losses.
At December 31, 2021, cash and cash equivalents were $34.9 million, total current assets were $87.0 million and total current liabilities were $103.0 million. Long-term debt, net of debt issuance costs, was $97.9 million, representing $100.0 million outstanding under the revolving credit facility. Stockholders’ equity was $553.1 million.
Material Changes Versus the Prior Period
- Revenue increased by $195.5 million, driven by a 383% increase in average daily sales volumes and an 86% increase in average realized price per Boe, excluding derivatives.
- Net income improved by approximately $157.0 million from the combined 2020 loss, primarily due to higher production and commodity prices, the absence of the $76.5 million terminated-acquisition expense recorded in 2020 and lower stock-based compensation.
- Production costs increased in total because of higher production, but lease operating expense declined to $7.38 per Boe from $10.68 per Boe due to greater scale and a larger horizontal-well base.
- Proved reserves increased to 64,213 MBoe from 22,515 MBoe. Reserves were 92% crude oil and NGL and 45% developed at year-end 2021.
- Standardized measure of discounted future net cash flows increased to $1.119 billion from $222.2 million, primarily reflecting extensions and discoveries, higher prices and acquisitions. This measure is based on SEC pricing assumptions and is not a current market valuation.
- The Company increased its revolving-credit borrowing base and commitments to $195.0 million by October 2021 and had $100.0 million drawn at year-end. It also raised $22.8 million net from an October 2021 equity offering.
- The Company initiated quarterly cash dividends of $0.025 per share and paid a special dividend of $0.075 per share in July 2021. Total dividends declared during 2021 were $0.125 per share.
Guidance, Outlook, Risks and Unusual Items
Management planned to operate four drilling rigs and an average of two frac fleets during 2022. The 2022 capital budget was approximately $715 million to $760 million for drilling, completion, facilities and equipping, plus $35 million to $40 million for infrastructure, land and other costs. Management stated that activity would be reassessed monthly and could change with commodity prices, capital availability, drilling results, service costs, regulatory developments and other conditions.
Management expected to fund the 2022 program with cash on hand, operating cash flow, borrowings, the February 2022 senior-notes offering and potentially additional debt or equity financing. In February 2022, the Company issued $225.0 million of 10.00% senior unsecured notes due 2024, receiving approximately $203.9 million of net proceeds. The proceeds were used to repay the revolving-credit borrowings and support the 2022 capital program. The revolving-credit borrowing base and commitments were reduced to $138.8 million.
- Commodity-price volatility remains the principal financial risk. A $1.00 per barrel change in crude oil prices would have affected 2021 revenue by approximately $3.1 million; a $0.10 per Mcf change in natural gas prices would have affected revenue by approximately $102,000.
- The Company had crude oil derivative swaps covering 2022 and the first half of 2023. Hedging reduces cash-flow volatility but can limit the benefit of higher prices and caused a material loss in 2021.
- A single purchaser accounted for approximately 94% of 2021 revenue, creating customer-concentration risk despite management’s view that alternative markets are available.
- The Flat Top crude oil marketing contract includes minimum volume commitments of 5,000 Bopd in the first year, 7,500 Bopd in the second year and 10,000 Bopd thereafter. The stated remaining monetary commitment was approximately $24.4 million if no further volumes were delivered.
- The Company had a produced-water disposal commitment with approximately $236,000 of remaining monetary exposure at December 31, 2021 if the remaining volume was not delivered.
- Approximately 21,155 net undeveloped acres were scheduled to expire in 2022 unless held by production, renewed or extended. Management intended to retain substantially all of this acreage.
- Texas restrictions on produced-water injection and potential induced-seismicity regulation could increase costs, restrict disposal capacity or delay development.
- Other material risks include drilling and completion performance, inflation and oilfield-service availability, transportation and processing constraints, environmental and climate regulation, hydraulic-fracturing restrictions, water and sand availability, cyber threats, reserve-estimation uncertainty and the need for substantial external capital.
- The filing reported no material legal proceedings and no impairments of proved or unproved oil and gas properties for the periods presented.
Investor Verification Items
- Reconcile the 2021 results with the Successor and Predecessor periods before making year-over-year comparisons.
- Verify the post-year-end capital structure, including the $225.0 million 2024 Notes, the reduced $138.8 million revolving-credit capacity and related covenants.
- Assess whether operating cash flow and available liquidity can support the $750 million-plus 2022 capital program under lower commodity prices or higher service costs.
- Review hedge volumes, fixed prices, settlement exposure and the effect of derivatives on realized revenue and cash flow.
- Evaluate the development schedule for 35,628 MBoe of proved undeveloped reserves and the estimated $389.5 million of associated future development costs.
- Monitor lease expirations, produced-water disposal restrictions and the Company’s ability to satisfy crude oil and water minimum-volume commitments.
- Consider customer concentration, controlled-company governance, potential dilution from warrants, stock awards and CVRs, and the timing and terms of CVR settlement.