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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Net Production Data: (In thousands except per unit amounts) Natural gas (MMcf) 128,896 102,560 366,272 341,823 Oil (MBbls) 346 354 1,034 1,168 Natural gas equivalent (MMcfe) 130,968 104,687 372,474 348,831 Revenues: Natural gas sales $ 488,303 $ 168,374 $ 1,133,783 $ 547,975 Oil sales 22,873 9,637 61,571 35,449 Total oil and gas sales $ 511,176 $ 178,011 $ 1,195,354 $ 583,424 Expenses: Production and ad valorem taxes $ 16,675 $ 9,798 $ 36,468 $ 27,768 Gathering and transportation $ 35,402 $ 22,422 $ 96,596 $ 77,423 Lease operating $ 26,576 $ 25,412 $ 77,150 $ 79,110 Depreciation, depletion and amortization $ 128,739 $ 99,056 $ 359,313 $ 312,828 Exploration $ — $ — $ — $ 27 Average Sales Price: Natural gas (per Mcf) $ 3.79 $ 1.64 $ 3.10 $ 1.60 Oil (per Bbl) $ 66.11 $ 27.20 $ 59.55 $ 30.35 Average equivalent (Mcfe) $ 3.90 $ 1.70 $ 3.21 $ 1.67 Expenses ($ per Mcfe): Production and ad valorem taxes $ 0.13 $ 0.09 $ 0.09 $ 0.08 Gathering and transportation $ 0.27 $ 0.21 $ 0.26 $ 0.22 Lease operating $ 0.20 $ 0.25 $ 0.21 $ 0.23 Depreciation, depletion and amortization $ 0.98 $ 0.95 $ 0.96 $ 0.90 Revenues – Oil and natural gas sales of $511.2 million for the third quarter of 2021 increased by $333.2 million (187%) as compared to $178.0 million for the third quarter of 2020. The increase was primarily due to higher prices received for our oil and natural gas production as well as higher natural gas production. Our natural gas production for the third quarter of 2021 increased 26% to 128.9 billion cubic feet ("Bcf") (1.4 Bcf per day), and was sold at an average price of $3.79 per Mcf as compared to 102.6 Bcf (1.1 Bcf per day) sold at an average price of $1.64 per Mcf in the third quarter of 2020. Oil production of 346 MBbls (3,761 Bbls per day) was sold at an average price of $66.11 per Bbl in the third quarter of 2021 as compared to 354 MBbls (3,851 Bbls per day) sold at an average price of $27.20 per Bbl in the third quarter of 2020. Oil and natural gas sales of $1.2 billion increased by $611.9 million (105%) for the nine months ended September 30, 2021 compared to $583.4 million for the nine months ended September 30, 2020, due primarily to higher prices received for our oil and natural gas production. Our natural gas production for the first nine months of 2021 was 366.3 Bcf (1.3 Bcf per day), which was sold at an average price of $3.10 per Mcf as compared to 341.8 Bcf (1.2 Bcf per day) sold at an average price of $1.60 per Mcf in the first nine months of 2020. Oil production of 1,034 Mbbls (3,788 Bbls per day) was sold at an average price of $59.55 per Bbl in the first nine months of 2021 as compared to 1,168 Mbbls (4,263 Bbls per day) sold at an average price of $30.35 per Bbl in the first nine months of 2020. 20 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Average Realized Natural Gas Price: Natural gas, per Mcf $ 3.79 $ 1.64 $ 3.10 $ 1.60 Cash settlements on derivative financial instruments, per Mcf (0.89) $ 0.31 $ (0.38) $ 0.36 Price per Mcf, including cash settlements on derivative financial instruments $ 2.90 $ 1.95 $ 2.72 $ 1.96 Average Realized Oil Price: Oil, per Bbl $ 66.11 $ 27.20 $ 59.55 $ 30.35 Cash settlements on derivative financial instruments, per Bbl (7.53) 6.32 (5.31) 9.49 Price per Bbl, including cash settlements on derivative financial instruments $ 58.58 $ 33.52 $ 54.24 $ 39.84 Costs and Expenses – Our production and ad valorem taxes in creased $6.9 million (70%) to $16.7 million for the third quarter of 2021 from $9.8 million in the third quarter of 2020. Production and ad valorem taxes increased $8.7 million (31%) to $36.5 million for the first nine months of 2021 from $27.8 million in the first nine months of 2020. The increase was primarily related to the higher oil and natural gas prices in 2021. Gathering and transportation costs for the third quarter of 2021 increased $13.0 million (58%) to $35.4 million as compared to $22.4 million in the third quarter of 2020. Gathering and transportation costs for the first nine months of 2021 increased $19.2 million (25%) to $96.6 million as compared to $77.4 million for the first nine months of 2020. The increase is due primarily to higher average rates and higher production in the third quarter and the first nine months of 2021. Our lease operating expense of $26.6 million ($0.20 per Mcfe) for the third quarter of 2021 increased $1.2 million (5%) from lease operating expense of $25.4 million ($0.25 per Mcfe) for the third quarter of 2020. Our lease operating expense of $77.2 million ($0.21 per Mcfe) for the first nine months of 2021 decreased $2.0 million (2%) from lease operating expense of $79.1 million ($0.23 per Mcfe) for the first nine months of 2020. The decrease in average per unit cost is related to the growth in our lower cost natural gas production. Depreciation, depletion and amortization ("DD&A") increased $29.7 million (30%) to $128.7 million in the third quarter of 2021 from $99.1 million in the third quarter of 2020 due to higher production and an increase in the average rate. Our DD&A per equivalent Mcf produced increased $0.03 (3%) to $0.98 per Mcfe for the three months ended September 30, 2021 from $0.95 per Mcfe for the three months ended September 30, 2020. DD&A increased $46.5 million (15%) to $359.3 million in the first nine months of 2021 from $312.8 million in the first nine months of 2020. Our DD&A per equivalent Mcf produced increased $0.06 (7%) to $0.96 per Mcfe for the first nine months of 2021 from $0.90 per Mcfe for the first nine months of 2020. General and administrative expenses, which are reported net of overhead reimbursements, decreased to $8.1 million for the third quarter of 2021 as compared to $9.0 million in the third quarter of 2020. General and administrative expenses decreased to $24.0 million for the first nine months of 2021 from $26.0 million in the first nine months of 2020. The decreases primarily resulted from higher overhead reimbursements that we received in 2021. We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the quarter ended September 30, 2021, we had substantial losses related to our derivative financial instruments of $510.3 million, as compared to net losses on derivative financial instruments of $121.6 million during the quarter ended September 30, 2020. Realized net losses from our oil and natural gas price risk management program were $117.1 million for the quarter ended September 30, 2020 as compared to realized net gains of $34.2 million for the quarter ended September 30, 2021. During the nine months ended September 30, 2021, we had total net losses on derivative financial instruments of $756.0 million, as compared to net losses on derivative financial instruments of $72.0 million during the the first nine months of 2020. Realized net losses from our oil and natural gas price risk management program were $144.4 million and net gains of $132.9 million for the nine months ended September 30, 2021 and 2020, respectively. Interest expense was $50.0 million and $63.9 million for the quarter ended September 30, 2021 and 2020, respectively. The 22% decrease in interest expense is due primarily to the retirement of our 9.75% and 7.50% senior notes 21 during the first six months of 2021. Interest expense was $170.6 million and $168.8 million for the nine months ended September 30, 2021 and 2020, respectively. Income taxes for the quarter ended September 30, 2021 and 2020 were a provision of $24.0 million and a benefit of $46.1 million, respectively. Income taxes for the nine months ended September 30, 2021 and 2020 were a benefit of $74.2 million and $46.2 million, respectively. The provision and benefit for income taxes for the three months and nine months ended September 30, 2021 reflect an effective tax rate of (9.1)% and 11.0%, respectively. The income tax provision for the three months ended September 30, 2021 is attributable to revisions to the estimated future utilization of federal and state net operating loss carryforwards resulting from the loss from derivative financial instruments that was recognized in the period. The benefit for income taxes for the three months and nine months ended September 30, 2020 reflect an effective tax rate of 26.7% and 25.6%, respectively. The difference between the federal statutory rate of 21% and our effective rate is primarily due to the increased valuation allowances discussed above and the impact of state income taxes. We reported net loss available to common stockholders of $292.7 million or $1.26 per share, for the quarter ended September 30, 2021 which was caused by the $510.3 million net loss from derivative financial instruments. Income from operations for the third quarter of 2021 was $295.7 million and we had interest expense of $50.0 million and $4.4 million in preferred stock dividends. We reported net loss available to common stockholders of $130.9 million or $0.57 per share for the three months ended September 30, 2020. In the first nine months of 2021, we reported net loss available to common stockholders of $615.2 million or $2.66 per share. Our income from operations for the first nine months of 2021 was $602.0 million, which was offset by losses on derivative financial instruments of $756.0 million, $352.6 million in losses on early retirement of debt and interest expense of $170.6 million. We reported net loss of $160.9 million or $0.77 per share for the nine months ended September 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 nine months ended September 30, 2021, we generated $618.6 million in cash flow from operating activities as compared to $390.0 million in cash flow from operating activities for the nine months ended September 30, 2020. The following table summarizes our capital expenditure activity: Nine Months Ended September 30, 2021 2020 (In thousands) Exploration and development: Exploratory leasehold costs $ 18,649 $ 1,457 Development leasehold costs 6,794 7,363 Development drilling and completion costs 454,524 280,383 Other development costs 28,455 26,463 Total capital expenditures $ 508,422 $ 315,666 We drilled 81 (46.9 net) wells and completed 68 (47.2 net) Haynesville shale wells during the first nine months of 2021. We expect to spend an additional $115 million to $135 million in the remaining three months of 2021 to drill 9 (7.4 net) additional wells, to complete 10 (8.8 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 22 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. 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 $352.6 million on early retirement of debt for the nine months ended September 30, 2021. At September 30, 2021, we had $425.0 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 October 22, 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 September 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. On October 6, 2021, we entered into an agreement to sell certain wells producing from the Bakken shale for $154 million in cash, subject to adjustment and customary closing conditions. The sale is expected to close in the fourth quarter of 2021 and has an effective date of October 1, 2021. Income Taxes At September 30, 2021, we had $960.3 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 $117.0 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 23 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 $775.2 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused.