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 March 31, 2021 2020 Net Production Data: (In thousands except per unit amounts) Natural gas (MMcf) 113,293 122,786 Oil (MBbls) 326 454 Natural gas equivalent (MMcfe) 115,246 125,513 Revenues: Natural gas sales $ 323,960 $ 207,239 Oil sales 16,525 18,639 Total oil and gas sales $ 340,485 $ 225,878 Expenses: Production and ad valorem taxes $ 9,652 $ 8,401 Gathering and transportation $ 29,458 $ 28,411 Lease operating $ 24,563 $ 25,878 Depreciation, depletion and amortization $ 109,128 $ 110,425 Exploration $ — $ 27 Average Sales Price: Natural gas (per Mcf) $ 2.86 $ 1.69 Oil (per Bbl) $ 50.69 $ 41.01 Average equivalent (Mcfe) $ 2.95 $ 1.80 Expenses ($ per Mcfe): Production and ad valorem taxes $ 0.08 $ 0.06 Gathering and transportation $ 0.26 $ 0.23 Lease operating $ 0.21 $ 0.21 Depreciation, depletion and amortization $ 0.95 $ 0.88 Revenues – Oil and natural gas sales of $340.5 million increased by $114.6 million (51%) in the first quarter of 2021 as compared to $225.9 million for the first quarter of 2020, which increase was primarily due to higher prices received for our oil and natural gas production. Our natural gas production for the first quarter of 2021 was 113.3 billion cubic feet ("Bcf") (1.3 Bcf per day), which was sold at an average price of $2.86 per Mcf as compared to 122.8 Bcf (1.3 Bcf per day) sold at an average price of $1.69 per Mcf in the first quarter of 2020. Oil production of 326 MBbls (3,617 Bbls per day) was sold at an average price of $50.69 per Bbl in the first quarter of 2021 as compared to 454 MBbls (4,994 Bbls per day) sold at an average price of $41.01 per Bbl in the first quarter of 2020. We utilize natural gas and oil price derivative financial instruments to manage our exposure to changes in natural gas and oil prices and to protect returns on investment from our drilling activities. 19 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 March 31, 2021 2020 Average Realized Natural Gas Price: Natural gas, per Mcf $ 2.86 $ 1.69 Cash settlements on derivative financial instruments, per Mcf $ (0.07) $ 0.35 Price per Mcf, including cash settlements on derivative financial instruments $ 2.79 $ 2.04 Average Realized Oil Price: Oil, per Bbl $ 50.69 $ 41.01 Cash settlements on derivative financial instruments, per Bbl $ (2.82) $ 5.30 Price per Bbl, including cash settlements on derivative financial instruments $ 47.87 $ 46.31 Costs and Expenses – Our production and ad valorem taxes in creased $1.3 million (15%) to $9.7 million for the first quarter of 2021 from $8.4 million in the first quarter of 2020. The increase was primarily due to higher oil and natural gas prices in 2021. Gathering and transportation costs for the first quarter of 2021 increased $1.0 million (4%) to $29.5 million as compared to $28.4 million in the first quarter of 2020 due primarily to higher gathering and transportation rates on our natural gas production. Our lease operating expense of $24.6 million for the first quarter of 2021 decreased $1.3 million (5%) from lease operating expense of $25.9 million for the first quarter of 2020. This decrease relates to lower oil and natural gas production in the first quarter of 2021. Depreciation, depletion and amortization ("DD&A") decreased $1.3 million (1%) to $109.1 million in the first quarter of 2021 from $110.4 million in the first quarter of 2020. Our DD&A per equivalent Mcf produced increased $0.07 (8%) to $0.95 per Mcfe for the three months ended March 31, 2021 from $0.88 per Mcfe for the three months ended March 31, 2020. General and administrative expenses, which are reported net of overhead reimbursements, decreased to $8.0 million for the first quarter of 2021 from $8.7 million in the first quarter of 2020. We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the three months ended March 31, 2021, we had net losses on derivative financial instruments of $21.7 million, as compared to net gains on derivative financial instruments of $61.9 million during the three months ended March 31, 2020. Realized net losses from our oil and natural gas price risk management program were $8.4 million for the three months ended March 31, 2021 as compared to realized net gains of $45.4 million for the three months ended March 31, 2020. Realized losses from our interest rate risk management program were $269 thousand for the three months ended March 31, 2021. Interest expense was $63.8 million and $52.8 million for the three ended March 31, 2021 and 2020, respectively. The increase in interest expense is due to the issuance of $800.0 million principal amount of 9.75% senior notes in the second and third quarters of 2020. Income taxes for the three months ended March 31, 2021 and 2020 were a benefit of $30.0 million and a provision of $11.4 million, respectively. The benefit and provision for income taxes for the three months ended March 31, 2021 and 2020 reflect an effective tax rate of 18.3% and 21.3%, respectively. The difference between the federal statutory rate of 21% and our effective rate is primarily due to the impact of state income taxes. We reported net loss available to common stockholders of $138.4 million or $0.60 per share, for the three months ended March 31, 2021 primarily due to the $238.5 million pre-tax loss on early retirement of our 7.50% senior notes and 9.75% senior notes. Income from operations was $159.7 million and we had $21.7 million in losses from derivative financial instruments, interest expense of $63.8 million and $4.3 million in preferred stock dividends. We reported net income available to common stockholders of $30.0 million or $0.15 per diluted share for the three months ended March 31, 2020. 20 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 three months ended March 31, 2021, we generated $193.3 million in cash flow from operating activities as compared to $150.1 million in cash flow from operating activities for the three months ended March 31, 2020. The following table summarizes our capital expenditure activity: Three Months Ended March 31, 2021 2020 (In thousands) Exploration and development: Exploratory leasehold costs $ 5,776 $ — Development leasehold costs 4,056 3,881 Development drilling and completion costs 155,239 122,058 Other development costs 3,780 4,561 Total capital expenditures $ 168,851 $ 130,500 We drilled 25 (19.6 net) wells and completed 14 (9.5 net) Haynesville shale wells during the first three months of 2021. We expect to spend an additional $350 million to $390 million in the remaining nine months of 2021 to drill 46 (37 net) additional wells, to complete 45 (40 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. On March 4, 2021, we issued $1.25 billion principal amount of 6.75% senior notes due 2029 in a private placement and received net proceeds after offering costs of $1.24 billion, which were used to repurchase a portion of our 7.50% senior notes due 2025 and 9.75% senior notes due 2026 pursuant to a tender offer. The new senior 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. Under the tender offer, we repurchased $375 million principal amount of our 7.50% senior notes and $777.1 million principal amount of our 9.75% senior 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. As a result of the early retirement of the senior notes repurchased in the tender offer, we recognized a $238.5 million loss on early retirement of debt in the three months ended March 31, 2021. At March 31, 2021, we had $550.0 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 March 31, 2021. 21 Federal Taxation At March 31, 2021, we had $1.0 billion 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. 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 $822.3 million of the U.S. federal NOL carryforwards and $1.4 billion of the estimated state NOL carrforwards will expire unused.