Highpeak Energy, Inc. annual report, FY2022

HighPeak Energy, Inc. — 2022 Form 10-K Summary

Reporting period: Fiscal year ended December 31, 2022. The filing is an annual report rather than a standalone fourth-quarter filing. HighPeak Energy is an independent oil and gas exploration and production company focused on the Midland Basin in West Texas, primarily Howard and Borden Counties. At year-end, it held approximately 125,730 gross acres, or 107,704 net acres, operated approximately 98% of its net acreage and had 47 full-time employees.

Business context and operating position

Production was concentrated in crude oil and NGLs, which represented approximately 94% of total production on a Boe basis.
Year-end acreage included approximately 56% held by production, with an average working interest of approximately 86%.
The company operated six drilling rigs and three frac crews at year-end and planned to average four to five rigs and two to three frac crews during 2023.
HighPeak completed the Hannathon and Alamo acquisitions and other bolt-on transactions, adding approximately 45,101 net acres and associated producing properties, infrastructure and drilling locations.

Financial and operating metrics

Metric	2022	2021	Change
Operating revenue	$755.7 million	$220.1 million	+$535.6 million
Net income	$236.9 million	$55.6 million	+$181.3 million
Diluted earnings per share	$1.93	$0.54	Increased
Income from operations	$422.6 million	$101.8 million	Increased
EBITDAX	$577.1 million	$164.2 million	Increased
Cash flow from operations	$504.0 million	$147.0 million	+$357.0 million
Net cash used in investing activities	$1.182 billion	$250.4 million	Higher investment
Net cash provided by financing activities	$674.0 million	$118.7 million	Higher financing
Average daily sales volume	24,485 Boepd	9,304 Boepd	+163%
Average realized price	$84.56/Boe	$64.82/Boe	+30%
Lease operating expense	$7.79/Boe	$7.38/Boe	+6%
DD&A expense	$177.7 million	$65.2 million	+$112.5 million
Derivative loss, net	$60.0 million	$26.7 million	Loss increased

Crude oil sales were $715.5 million, while NGL and natural gas sales were $40.2 million. Average realized prices were $94.61 per barrel for crude oil, $35.67 per barrel for NGLs and $5.36 per Mcf for natural gas. The largest purchaser accounted for approximately 88% of total sales revenue, compared with 94% in 2021.

Profitability, cash flow, liquidity and debt

Operating margin before corporate and other items was strong, with income from operations of $422.6 million on $755.7 million of revenue. The filing does not present a single GAAP operating-margin percentage; calculated operating margin was approximately 55.9%.
Net income benefited from higher production and commodity prices but was reduced by higher DD&A, interest expense, income taxes, lease operating costs, derivative losses and stock-based compensation.
Cash and cash equivalents were $30.5 million at December 31, 2022, compared with $34.9 million at December 31, 2021.
Total debt was $745.0 million before discounts and issuance costs: $270.0 million under the Credit Agreement, $225.0 million of 10.000% Senior Notes and $250.0 million of 10.625% Senior Notes. Net debt reported on the balance sheet was $704.3 million.
Credit Agreement borrowing capacity was $525.0 million of elected commitments against a $550.0 million borrowing base; $252.6 million of capacity remained available at year-end.
All principal debt was scheduled to mature in 2024. The Credit Agreement could spring to maturity on October 1, 2023 if the 10.000% Senior Notes were not extended, redeemed or refinanced as required.
2022 capital expenditures excluding acquisitions were approximately $1.0 billion. Development capital expenditures were $391.3 million, compared with $45.9 million in 2021.
The company paid $10.4 million of common stock dividends in 2022 and declared quarterly dividends of $0.025 per share through the period covered by the filing.

Material changes versus 2021

Revenue increased 243%, primarily from a 163% increase in production volumes and a 30% increase in average realized price per Boe.
Net income increased more than fourfold to $236.9 million, although interest expense rose to $50.6 million from $2.5 million and income tax expense rose to $75.4 million from $16.9 million.
Production growth reflected the horizontal drilling program and acquired properties. The company placed 92 gross, or 78.2 net, horizontal wells on production during 2022.
Proved reserves increased to 122,958 MBoe from 64,213 MBoe. Reserves were 92% crude oil and NGLs and 50% developed at year-end, compared with 45% developed in 2021.
Proved undeveloped reserves increased to 61,700 MBoe from 35,628 MBoe, driven by extensions and discoveries of 37,394 MBoe and purchases of 7,302 MBoe, partially offset by 15,446 MBoe converted to developed reserves and downward revisions of 3,178 MBoe.
Standardized measure of discounted future net cash flows increased to $3.417 billion from $1.119 billion. This measure is highly sensitive to commodity prices and development assumptions and is not fair value.
Stockholders’ equity increased to $1.170 billion from $553.1 million, supported by net income, shares issued for acquisitions and an $85.0 million private placement.

Guidance, outlook and management commentary

The 2023 capital budget was approximately $1.1 billion to $1.2 billion for drilling, completion, facilities and equipping, plus $50 million to $60 million for field infrastructure, land and other costs.
Management expected to fund the 2023 program with cash on hand, operating cash flow, Credit Agreement borrowings and potentially additional debt or equity financing.
Capital activity would remain flexible and be evaluated monthly based on commodity prices, drilling results, service availability, regulatory developments and available liquidity.
On January 23, 2023, the Board announced a review of strategic alternatives, including a potential sale of the company. The filing states that no transaction or timetable had been determined.
Hedging reduced exposure to commodity-price declines but also limited some benefit from higher prices. Outstanding 2023 hedges included 1.722 million barrels of WTI swaps at a weighted average price of $71.59 per barrel and 1.928 million barrels of deferred-premium puts with a net-of-premium average price of $53.43 per barrel.

Key risks, contingencies and unusual items

Refinancing and liquidity: The concentration of debt maturities in 2024 and the Credit Agreement’s springing maturity create significant refinancing and execution risk.
Commodity-price exposure: Revenue, reserves, borrowing capacity and capital spending depend heavily on volatile oil, NGL and natural gas prices.
Capital intensity: Planned 2023 spending substantially exceeds 2022 operating cash flow, increasing reliance on debt capacity, future operating performance and capital-market access.
Reserve uncertainty: 2022 included a 9,211 MBoe downward revision of proved reserves, primarily from technical revisions related to lower well performance and PUD adjustments.
Lease expirations: Approximately 19,391 net undeveloped acres were scheduled to expire in 2023, with additional expirations in 2024 and 2025. Management intends to retain substantially all of the acreage through drilling, completion operations, renewals or extensions.
Customer concentration: Delek represented approximately 88% of 2022 revenue. The company also had a long-term crude oil marketing agreement with minimum volume commitments and approximately $18.3 million of remaining monetary commitment if no additional volumes were delivered.
Other commitments: Remaining potential monetary commitment under the sand supply agreement was approximately $4.6 million, and the produced-water treatment agreement with a related party had an approximately $4.4 million commitment if no additional volumes were delivered.
Regulatory and environmental risk: Hydraulic fracturing, methane emissions, produced-water disposal, induced seismicity, climate regulation, environmental remediation and permitting could increase costs or restrict operations.
Unusual items: Stock-based compensation expense increased to $33.4 million, derivative losses were $60.0 million, and interest expense included substantial amortization of debt discounts and issuance costs.
The independent auditor issued an unqualified opinion on the consolidated financial statements. Management concluded that disclosure controls and internal control over financial reporting were effective; the company was not required to obtain an auditor attestation under its emerging-growth-company status.

Facts investors should verify

Whether the company refinanced, extended or redeemed the 2024 senior notes and Credit Agreement maturities, and the resulting interest burden and covenant compliance.
Whether the 2023 capital budget was achieved within the stated range and whether production growth and operating cash flow supported the development program.
The outcome of the strategic-alternatives review announced in January 2023, including any sale, merger, asset sale or refinancing transaction.
Actual realized commodity prices, hedge settlements and derivative mark-to-market changes relative to the 2023 and 2024 hedge schedule.
Reserve revisions, well performance and conversion of the 61,700 MBoe of proved undeveloped reserves into producing reserves.
Progress in retaining acreage scheduled to expire in 2023 through drilling, completion, renewal or extension.
Exposure to Delek and other purchasers, minimum-volume commitments and transportation, gathering, water-disposal and sand-supply obligations.
The filing text does not provide a clear standalone fourth-quarter revenue, profit or cash-flow presentation; investors seeking Q4-only metrics should verify the company’s fourth-quarter earnings release or Form 8-K.