HighPeak Energy, Inc. — FY2020 Form 10-K Summary
Business context and reporting period
HighPeak Energy is an independent oil and natural gas exploration and production company focused on the Midland Basin, primarily Howard County, Texas. The company completed its business combination with Pure Acquisition Corp. and HPK Energy, LP on August 21, 2020. Accordingly, the filing presents successor results for August 22–December 31, 2020 and predecessor results for January 1–August 21, 2020 and fiscal 2019; full-year comparisons are therefore not fully comparable.
- At December 31, 2020, the company held approximately 59,092 gross and 50,636 net acres, operated approximately 95% of its net acreage and had 25 full-time employees.
- Proved reserves totaled 22.515 MMBoe, consisting of 94% oil and NGL and 6% natural gas; 46% were proved developed.
- The company had approximately 115 gross producing wells, including 19 gross horizontal wells, and was operating one drilling rig at year-end.
Financial and operating metrics
| Metric | Successor period | Predecessor period | 2019 predecessor |
|---|---|---|---|
| Operating revenues | $16.4 million | $8.2 million | $8.1 million |
| Net loss | $16.4 million | $85.0 million | $11.6 million |
| Net cash provided by operating activities | $5.4 million | $(4.1) million | $(0.8) million |
| Net cash used in investing activities | $(71.9) million | $(67.9) million | $(51.4) million |
| Net cash provided by financing activities | $84.1 million | $51.2 million | $74.0 million |
On a combined basis for the two 2020 periods, revenues were approximately $24.6 million and net loss was approximately $101.5 million, but these amounts should not be treated as a single consolidated fiscal-year result because of the successor/predecessor accounting presentation.
- Combined 2020 average production was 1,925 Boe/d, up 317% from 462 Boe/d in 2019. Liquids represented approximately 95% of production.
- Full-year 2020 average realized prices were $37.96 per barrel for oil, $14.06 per barrel for NGLs and $1.04 per Mcf for natural gas, compared with $53.96 per barrel for oil and $1.92 per Mcf for gas in 2019.
- Full-year 2020 lease operating expense was $7.5 million, or approximately $10.68 per Boe, versus $20.00 per Boe in 2019. DD&A was $16.3 million, or approximately $23.08 per Boe.
- At December 31, 2020, total assets were $537.9 million, including $502.6 million of net oil and gas properties. Stockholders’ equity was $474.2 million and accumulated deficit was $107.2 million.
- Cash and cash equivalents were $19.6 million. The revolving credit facility was undrawn, with $20 million of elected commitments available at year-end; the borrowing base and bank commitments were increased to $50 million in March 2021, subject to documentation.
- The facility matures June 17, 2024, is secured by substantially all company assets, requires semiannual borrowing-base redeterminations and includes leverage and current-ratio covenants beginning with the quarter ending March 31, 2021.
- PV-10 of proved reserves was $235.5 million, while the GAAP standardized measure was $222.2 million. These reserve values use SEC-required historical pricing and are not estimates of fair market value.
Material changes versus the prior comparable period
- Production increased substantially due to horizontal drilling in the Wolfcamp A and Lower Spraberry formations, while lower commodity prices reduced realized prices and limited profitability.
- The company’s 2020 results included a $76.5 million expense for the terminated Grenadier acquisition, consisting of forfeited deposits and extension payments.
- Stock-based compensation was $15.8 million, primarily from options granted following the business combination; approximately 75% of the options vested immediately.
- Exploration and abandonment expense included a $4.8 million impairment of leasehold costs that the company did not successfully extend.
- Proved reserves increased from 11.497 MMBoe at December 31, 2019 to 22.515 MMBoe at December 31, 2020, primarily from extensions and discoveries, partly offset by downward technical revisions, lease removals and production.
- The company halted or curtailed most production and drilling in spring 2020 because of COVID-19, weak oil prices and storage constraints. Wells began returning to production in July, and the company resumed a one-rig development program in the second half of the year.
Guidance, outlook, risks and unusual items
- Management’s 2021 planning assumption contemplated approximately $115–$125 million of drilling, completion, facilities and equipment spending plus $20–$25 million for field infrastructure and other costs. The company planned to operate one drilling rig and approximately one frac fleet during the first quarter of 2021, subject to monthly economic review.
- Management expected to fund the capital program with cash on hand, operating cash flow and borrowings under the revolving facility, but acknowledged that liquidity and future activity levels depend heavily on commodity prices and capital availability.
- The company had no commodity hedges historically because it had no debt; the revolving facility requires hedging on a portion of proved developed producing reserves beginning in the first quarter of 2021.
- Key risks include oil, gas and NGL price volatility; COVID-19 and demand disruption; storage, gathering and transportation constraints; dependence on a small number of purchasers; drilling and completion risks; reserve-estimate uncertainty; lease expirations; water disposal and induced seismicity; environmental, hydraulic-fracturing and climate regulation; access to capital; and borrowing-base reductions.
- Approximately 30,257 net undeveloped acres were scheduled to expire in 2021 unless retained through production, extensions or renewals. Management intended to retain substantially all of this acreage.
- The company had commitments to deliver 5.5 MMBbl of produced water to third-party disposal companies. Failure to meet the commitments could result in approximately $1.8 million of penalties; management expected to satisfy them.
- At March 15, 2021, the company reported 92.7 million common shares, 9.5 million warrants and 10.2 million CVRs outstanding. CVRs may require additional shares to be issued if a 10% preferred simple annual return is not achieved, subject to the agreement’s terms.
- Management concluded that disclosure controls were effective, but did not provide an assessment of internal control over financial reporting because the post-business-combination control framework was still in development and the company relied on the emerging-growth-company exemption.
Important facts investors should verify
- Reconcile successor and predecessor results before assessing year-over-year revenue, earnings, margins or cash-flow trends.
- Confirm the company’s actual 2021 capital spending, drilling pace, production growth and funding sources relative to the stated $135–$150 million planning range.
- Monitor commodity prices, hedge positions, borrowing-base redeterminations, covenant compliance and available liquidity.
- Evaluate conversion of the 12.233 MMBoe of proved undeveloped reserves, including the estimated $112.6 million of development costs over three years.
- Track retention or expiration of the 2021 lease acreage and any resulting reserve revisions or impairment charges.
- Assess customer concentration, particularly the reliance on Lion Oil Trading and Transportation and other major purchasers.
- Review potential dilution from warrants, stock options, CVRs and registration rights held by major stockholders.
- Consider the $76.5 million terminated-acquisition charge, stock compensation, leasehold impairment and other unusual items when evaluating normalized profitability.