COMSTOCK RESOURCES INC 10-Q

ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This report contains forward-looking statements that involve risks and uncertainties that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report and in our annual report filed on Form 10-K for the year ended December 31, 2020. Results of Operations Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Net Production Data: (In thousands except per unit amounts) Natural gas (MMcf) 124,083 116,477 237,376 239,263 Oil (MBbls) 362 360 688 814 Natural gas equivalent (MMcfe) 126,260 118,631 241,506 244,144 Revenues: Natural gas sales $ 321,520 $ 172,362 $ 645,480 $ 379,601 Oil sales 22,173 7,173 38,698 25,812 Total oil and gas sales $ 343,693 $ 179,535 $ 684,178 $ 405,413 Expenses: Production and ad valorem taxes $ 10,141 $ 9,569 $ 19,793 $ 17,970 Gathering and transportation $ 31,736 $ 26,590 $ 61,194 $ 55,001 Lease operating $ 26,011 $ 27,820 $ 50,574 $ 53,698 Depreciation, depletion and amortization $ 121,446 $ 103,347 $ 230,574 $ 213,772 Exploration $ — $ — $ — $ 27 Average Sales Price: Natural gas (per Mcf) $ 2.59 $ 1.48 $ 2.72 $ 1.59 Oil (per Bbl) $ 61.25 $ 19.97 $ 56.25 $ 31.72 Average equivalent (Mcfe) $ 2.72 $ 1.51 $ 2.83 $ 1.66 Expenses ($ per Mcfe): Production and ad valorem taxes $ 0.08 $ 0.08 $ 0.08 $ 0.07 Gathering and transportation $ 0.25 $ 0.22 $ 0.25 $ 0.23 Lease operating $ 0.21 $ 0.24 $ 0.21 $ 0.22 Depreciation, depletion and amortization $ 0.96 $ 0.87 $ 0.95 $ 0.88 Revenues – Oil and natural gas sales of $343.7 million increased by $164.2 million (91%) in the second quarter of 2021 as compared to $179.5 million for the second quarter of 2020. The increase was primarily due to higher prices received for our oil and natural gas production as well as increased natural gas production. Our natural gas production for the second quarter of 2021 was 124.1 billion cubic feet ("Bcf") (1.4 Bcf per day), which was sold at an average price of $2.59 per Mcf as compared to 116.5 Bcf (1.3 Bcf per day) sold at an average price of $1.48 per Mcf in the second quarter of 2020. Oil production of 362 MBbls (3,978 Bbls per day) was sold at an average price of $61.25 per Bbl in the second quarter of 2021 as compared to 360 MBbls (3,956 Bbls per day) sold at an average price of $19.97 per Bbl in the second quarter of 2020. Oil and natural gas sales of $684.2 million increased by $278.8 million (69%) for the six months ended June 30, 2021 compared to $405.4 million for the six months ended June 30, 2020, which was primarily due to higher prices received for our oil and natural gas production. Our natural gas production for the first six months of 2021 was 237.4 Bcf (1.3 Bcf per day) was sold at an average price of $2.72 per Mcf as compared to 239.3 Bcf (1.3 Bcf per day) sold at an average price of $1.59 per Mcf in the first six months of 2020. Oil production of 688 Mbbls (3,801 Bbls per day) was sold at an average price of $56.25 per Bbl in the first six months of 2021 as compared to 814 Mbbls (4,473 Bbls per day) sold at an average price of $31.72 per Bbl in the first six months of 2020. 19 We utilize natural gas and oil price derivative financial instruments to manage our exposure to changes in prices of natural gas and oil and to protect returns on investment from our drilling activities. The following table presents our natural gas and oil prices before and after the effect of cash settlements of our derivative financial instruments: Three Months Ended Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Average Realized Natural Gas Price: Natural gas, per Mcf $ 2.59 $ 1.48 $ 2.72 $ 1.59 Cash settlements on derivative financial instruments, per Mcf (0.13) $ 0.40 $ (0.10) $ 0.37 Price per Mcf, including cash settlements on derivative financial instruments $ 2.46 $ 1.88 $ 2.62 $ 1.96 Average Realized Oil Price: Oil, per Bbl $ 61.25 $ 19.97 $ 56.25 $ 31.72 Cash settlements on derivative financial instruments, per Bbl (5.43) 17.92 (4.19) 10.87 Price per Bbl, including cash settlements on derivative financial instruments $ 55.82 $ 37.89 $ 52.06 $ 42.59 Costs and Expenses – Our production and ad valorem taxes in creased $0.6 million (6%) to $10.1 million for the second quarter of 2021 from $9.6 million in the second quarter of 2020. Production and ad valorem taxes increased $1.8 million (10%) to $19.8 million for the first six months of 2021 from $18.0 million in the first six months of 2020. The increase was primarily due to the higher oil and natural gas sales in 2021. Gathering and transportation costs for the second quarter of 2021 increased $5.1 million (19%) to $31.7 million as compared to $26.6 million in the second quarter of 2020. Gathering and transportation costs for the first six months of 2021 increased $6.2 million (11%) to $61.2 million as compared to $55.0 million for the first six months of 2020. The increase is due primarily to higher average rates in 2021 in addition to the higher production in the second quarter of 2021. Our lease operating expense of $26.0 million ($0.21 per Mcfe) for the second quarter of 2021 decreased $1.8 million (7%) from lease operating expense of $27.8 million ($0.24 per Mcfe) for the second quarter of 2020. Our lease operating expense of $50.6 million ($0.21 per Mcfe) for the first six months of 2021 decreased $3.1 million (6%) from lease operating expense of $53.7 million ($0.22 per Mcfe) for the first six months of 2020. The decrease in average per unit cost is related to the growth in our lower cost natural gas production where much of the operating costs are fixed in nature. Depreciation, depletion and amortization ("DD&A") increased $18.1 million (18%) to $121.4 million in the second quarter of 2021 from $103.3 million in the second quarter of 2020. Our DD&A per equivalent Mcf produced increased $0.09 (10%) to $0.96 per Mcfe for the three months ended June 30, 2021 from $0.87 per Mcfe for the three months ended June 30, 2020. DD&A increased $16.8 million (8%) to $230.6 million in the first six months of 2021 from $213.8 million in the first six months of 2020. Our DD&A per equivalent Mcf produced increased $0.07 (8%) to $0.95 per Mcfe for the first six months of 2021 from $0.88 per Mcfe for the first six months of 2020. General and administrative expenses, which are reported net of overhead reimbursements, decreased to $7.9 million for the second quarter of 2021 from $8.3 million in the second quarter of 2020. General and administrative expenses decreased to $15.9 million for the first six months of 2021 from $17.0 million in the first six months of 2020. The decreases were primarily related to increased overhead reimbursements in 2021. We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the three months ended June 30, 2021, we had net losses on derivative financial instruments of $224.0 million, as compared to net losses on derivative financial instruments of $12.3 million during the three months ended June 30, 2020. Realized net losses from our oil and natural gas price risk management program were $18.8 million for the three months ended June 30, 2021 as compared to realized net gains of $53.2 million for the three months ended June 30, 2021. Realized losses from our interest rate risk management program were $292 thousand for the three months ended June 30, 2021 as compared to net gains of $63 thousand for the three months ended June 30, 2020. During the six months ended June 30, 2021, we had net losses on derivative financial instruments of $245.7 million, as compared to net gains on derivative financial instruments of $49.6 million during the the first six months of 2020. Realized net losses from our oil and natural gas price risk management program were $27.3 million and net gains of $98.6 million for the six months ended June 30, 2021 and 2020, respectively. Realized losses from our interest rate risk management program were $561 thousand for the six months ended June 30, 2021 as compared to net gains of $63 thousand for the six months ended June 30, 2020. 20 Interest expense was $56.9 million and $52.1 million for the three months ended June 30, 2021 and 2020, respectively. Interest expense was $120.7 million and $104.9 million for the six months ended June 30, 2021 and 2020, respectively. The increase in interest expense is due primarily to the issuance of additional 9.75% senior notes in 2020. Income taxes for the three months ended June 30, 2021 and 2020 were a benefit of $68.2 million and $11.4 million, respectively. Income taxes for the six months ended June 30, 2021 and 2020 were a benefit of $98.1 million and $0.1 million, respectively. The benefit for income taxes for the three months and six months ended June 30, 2021 reflect an effective tax rate of 27.5% and 23.8%, respectively. The benefit for income taxes for the three months and six months ended June 30, 2020 reflect an effective tax rate of 18.7% and 0.7%, respectively. The difference between the federal statutory rate of 21% and our effective rate is primarily due to the impact of state income taxes, including changes to Louisiana state tax law enacted in the second quarter of 2021. We reported net loss available to common stockholders of $184.1 million or $0.80 per share, for the three months ended June 30, 2021 due primarily to the $224.0 million in losses from derivative financial instruments and the $114.1 million loss on early retirement of our 9.75% senior notes. Income from operations was $146.5 million and we had interest expense of $56.9 million and $4.4 million in preferred stock dividends. We reported net loss available to common stockholders of $60.0 million or $0.29 per share for the three months ended June 30, 2020. In the first six months of 2021, we reported net loss available to common stockholders of $322.5 million or $1.39 per share. Our net loss during this period includes income from operations of $306.2 million, which were offset by losses on derivative financial instruments of $245.7 million, interest expense of $120.7 million and $352.6 million in losses on early retirement of debt. We reported net loss of $30.0 million or $0.15 per share for the six months ended June 30, 2020. Liquidity and Capital Resources Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or proceeds from asset sales. For the six months ended June 30, 2021, we generated $385.6 million in cash flow from operating activities as compared to $266.1 million in cash flow from operating activities for the six months ended June 30, 2020. The following table summarizes our capital expenditure activity: Six Months Ended June 30, 2021 2020 (In thousands) Exploration and development: Exploratory leasehold costs $ 13,401 $ — Development leasehold costs 6,061 6,336 Development drilling and completion costs 312,887 183,480 Other development costs 8,931 15,418 Total capital expenditures $ 341,280 $ 205,234 We drilled 50 (34.4 net) wells and completed 35 (24.5 net) Haynesville shale wells during the first six months of 2021. We expect to spend an additional $200 million to $240 million in the remaining six months of 2021 to drill 25 (21.7 net) additional wells, to complete 29 (24.3 net) wells and for other development activity. We expect to fund our future development and exploration activities with future operating cash flow. The timing of most of our future capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including additional equity or debt financings. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms. We do not have a specific acquisition budget for 2021 because the timing and size of acquisitions are unpredictable. We intend to use our cash flows from operations, borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions. 21 On March 4, 2021, we issued $1.25 billion principal amount of our 6.75% senior notes due in 2029 (the "2029 Notes") in a private placement and received net proceeds after offering costs of $1.24 billion, which were used to repurchase a portion of our 7.5% senior notes due in 2025 (the "2025 Notes") and 9.75% senior notes due in 2026 (the "2026 Notes") pursuant to a tender offer. The 2029 Notes mature on March 1, 2029 and accrue interest at a rate of 6.75% per annum, payable semi-annually on March 1 and September 1 of each year. Pursuant to the tender offer, we repurchased $375.0 million principal amount of the 2025 Notes and $777.1 million principal amount of the 2026 Notes for an aggregate amount of $1.26 billion, which included premiums paid over face value of $97.9 million, accrued interest of $12.5 million and $1.1 million of costs related to the tender offer. On June 28, 2021, we issued $965.0 million principal amount of our 5.875% senior notes due in 2030 (the "2030 Notes") in a private placement and received net proceeds after offering costs of $949.5 million, which were used along with cash on hand to redeem all outstanding 2026 Notes. The 2030 Notes mature on January 15, 2030 and accrue interest at a rate of 5.875% per annum, payable semi-annually on January 15 and July 15 of each year. On June 29, 2021, we completed the redemption of all outstanding 2026 Notes for $978.6 million, which included premiums paid over face value of $74.0 million and accrued interest of $31.7 million. As a result of the early retirement of the senior notes repurchased in the tender offer and the redemption of the 2026 Notes, we recognized a loss of $114.1 million and $352.6 million on early retirement of debt for the three months and six months ended June 30, 2021, respectively. At June 30, 2021, we had $475.0 million outstanding under our bank credit facility with a $1.4 billion committed borrowing base, which is re-determined on a semi-annual basis and upon the occurrence of certain other events, and matures on July 16, 2024. The borrowing base was redetermined at $1.4 billion on April 16, 2021. Borrowings under the bank credit facility are secured by substantially all of our assets and those of our subsidiaries and bear interest at our option, at either LIBOR plus 2.25% to 3.25% or a base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. We also pay a commitment fee of 0.375% to 0.50% on the unused portion of the borrowing base. The bank credit facility places certain restrictions upon our and our subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 4.0 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of June 30, 2021. In April 2021, we entered into a well stimulation agreement that extends to 2024 for exclusive use of a natural gas powered pressure pumping fleet. The minimum commitment under this contract is $19.2 million per year from 2022 through 2024. Income Taxes At June 30, 2021, we had $946.1 million in U.S. federal net operating loss ("NOL") carryforwards and $1.5 billion in certain state NOL carryforwards. As a result of the change of control in August 2018, our ability to use NOLs to reduce taxable income is generally limited to an annual amount based on the fair market value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt interest rate. Our NOLs are estimated to be limited to $3.3 million a year as a result of this limitation. In addition to this limitation, IRC Section 382 provides that a corporation with a net unrealized built-in gain immediately before an ownership change may increase its limitation by the amount of recognized built-in gain recognized during a recognition period, which is generally the five-year period immediately following an ownership change. Based on the fair market value of our common stock immediately prior to the ownership change, we believe that we have a net unrealized built-in gain which will increase the Section 382 limitation during the five-year recognition period from 2018 to 2023 by $117 million. Effective June 30, 2021, Louisiana state tax law was amended to provide that all NOL deductions claimed on any corporate income tax return filed on or after January 1, 2022 for NOLs relating to loss years on or after January 1, 2001 may be carried forward indefinitely until such losses are fully recovered, subject to other limitations. NOLs that exceed the Section 382 limitation in any year continue to be allowed as carryforwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year. NOLs incurred prior to 2018 generally have a 20-year life until they expire. NOLs generated in 2018 and after would be carried forward indefinitely. Our use of new NOLs arising after the date of an ownership change would not be affected by the 382 limitation. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carryforward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $800.5 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused. 22