COMSTOCK RESOURCES INC annual report, FY2020

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Comstock Resources, Inc. — 2020 Form 10-K Summary

Reporting period: Fiscal year ended December 31, 2020. This is an annual report, not a standalone fourth-quarter earnings report. Comstock is an independent oil and natural gas producer, focused primarily on the Haynesville and Bossier shales in North Louisiana and East Texas. Comparisons below are with 2019 unless otherwise noted.

Financial and operating performance

  • Revenue: Oil and gas sales were $858.2 million, up 12% from $768.7 million. Natural gas sales increased to $809.4 million from $635.8 million as production rose; oil sales declined to $48.8 million from $132.9 million.
  • Production and realized prices: Total production increased 49% to 459.9 Bcfe (about 1.26 Bcfe per day). Natural gas production was 450.8 Bcf, at an average realized price of $1.80/Mcf versus $2.17/Mcf. Oil production fell to 1.5 million barrels from 2.7 million, and the average realized oil price fell to $32.36/barrel from $49.49.
  • Profitability: Operating income was $163.0 million, down from $274.9 million; operating margin was approximately 19% versus 36%. Net loss available to common stockholders was $83.4 million, or $0.39 per share, compared with income of $74.5 million, or $0.52 per diluted share. The 2020 loss primarily reflected a $124.5 million unrealized loss on derivatives; income from operations remained positive.
  • Cash flow and investment: Cash from operating activities was $575.7 million, up from $451.2 million. Cash capital expenditures were $509.7 million, implying approximately $66 million of operating cash flow less capital expenditures; this is a simple calculation, not a company-defined free-cash-flow measure. Reported 2020 capital expenditures were $491.9 million, including $436.1 million for drilling and completions.
  • Costs: Lease operating expense was $102.5 million, or $0.22/Mcfe, down from $0.27/Mcfe. Gathering and transportation expense increased to $106.6 million, while DD&A rose to $417.1 million with higher production. Interest expense increased to $234.8 million from $161.5 million.
  • Debt and liquidity: Year-end debt principal was $2.77 billion: $500 million under the bank facility, $619.4 million of 7.5% notes due 2025 and $1.65 billion of 9.75% notes due 2026. Cash was $30.3 million. The credit facility had a $1.4 billion borrowing base, with $500 million drawn; the company reported covenant compliance at year-end. The filing does not provide a clear current-ratio figure in the supplied text.
  • Reserves: Proved reserves totaled 5.63 Tcfe, 99% natural gas; 95% were in the Haynesville/Bossier. Reserves increased from 5.36 Tcfe in 2019, while the standardized measure of discounted future net cash flows fell to $1.94 billion from $2.91 billion, reflecting lower prices among other factors.

Material changes versus 2019

  • Production growth, primarily from the Haynesville/Bossier drilling program and the 2019 Covey Park acquisition, more than offset lower realized commodity prices, lifting sales by 12%.
  • Lower oil prices and production reduced oil revenue substantially. Cash derivative settlements rose to $134.9 million from $52.7 million and partly supported realized prices; however, unrealized derivative losses of $124.5 million weighed on reported earnings.
  • Interest expense rose following the issuance of an additional $800 million of 9.75% notes in 2020. Proceeds were used to repay bank-facility borrowings.
  • The company issued common stock and redeemed its Series A convertible preferred stock for $210 million plus accrued dividends. Series B preferred stock remained outstanding, carries a 10% dividend and is convertible into 43.75 million common shares.
  • All proved undeveloped reserves at year-end were natural gas; 2019 proved undeveloped oil reserves were removed, primarily because of the lower SEC oil price used for reserve estimates.

Outlook, risks and notable items

  • 2021 plan: Management expects to drill 62 operated horizontal wells (51 net), complete 19 wells drilled in 2020, and spend approximately $517–$560 million on development and exploration. The stated priorities are free cash flow generation and debt reduction. Natural gas production is expected to increase if development offsets declines from existing wells; oil production is expected to continue declining.
  • Commodity exposure and hedging: Year-end hedges covered substantial portions of expected 2021–2022 gas production, including swaps, collars and swaptions; oil collars covered 182,500 barrels. Management cautions that hedges may not fully offset market-price, basis, volume or counterparty risks. Subsequent to year-end, additional gas and oil hedges were entered into.
  • Debt and commitments: High debt and interest obligations constrain financial flexibility. The filing lists $272.0 million of transportation commitments and $6.0 million of drilling-rig and completion commitments, in addition to scheduled interest and debt maturities. A 10-year firm transportation agreement for 400,000 MMBtu/day is expected to begin in the fourth quarter of 2021; insufficient production could leave the company responsible for transportation costs.
  • Other risks: Results are sensitive to volatile oil and gas prices, reserve estimates, drilling outcomes, access to transportation, and the ability to fund development. The filing also identifies environmental and climate regulation, hydraulic-fracturing and induced-seismicity rules, operational hazards, cyber threats, and COVID-19-related uncertainty. Management said COVID-19 did not significantly disrupt 2020 operations apart from its effect on prices.
  • Unusual items and controls: The company received $10.2 million of AMT refunds under the CARES Act. It reported no legal proceedings expected to have a material adverse effect. The financial statements received an unqualified audit opinion, and the auditor also gave an unqualified opinion on internal control over financial reporting.

Important facts for investors to verify

  • Whether the 2021 drilling and spending plan can be funded from operating cash flow while producing meaningful debt reduction.
  • Actual production, realized pricing and hedge settlements versus the company’s 2021 assumptions, including the effect of swaptions and post-year-end hedges.
  • Debt balances, borrowing-base redeterminations, covenant headroom, interest costs and the company’s ability to manage its 2025 and 2026 maturities.
  • Progress and economics of the 400,000 MMBtu/day transportation commitment, including any shortfall or take-or-pay exposure.
  • Reserve revisions and future development spending: 3.60 Tcf of proved undeveloped gas reserves carried estimated future development costs of $2.45 billion.
  • Potential dilution and cash cost from the Series B preferred stock, including its 10% dividends and conversion into 43.75 million common shares.
  • Commodity-price assumptions behind reserve values: year-end SEC prices were $39.57/barrel for oil and $1.99/Mcf for gas; PV-10 is a non-GAAP measure and is not current market value.