UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended September 30, 2017
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 001-12719
GOODRICH PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) |
Delaware (State or other jurisdiction of incorporation or organization) | 76-0466193 (I.R.S. Employer Identification No.) |
801 Louisiana, Suite 700 Houston, Texas 77002 (Address of principal executive offices) (Zip Code) (Registrant’s telephone number, including area code): (713) 780-9494 Securities registered pursuant to Section 12(b) of the Act: | |
| Title of each class | Trading Symbol | Name of each exchange on which registered |
| Common stock, par value $0.01 per share | GDP | NYSE American |
Indicate by check mark whether the Registrantregistrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ☐ | Accelerated filer | ☐ | |
Non-accelerated filer | ☐ | Smaller reporting company | ☒ | |
Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☐Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
☐ No ☒Indicate by check mark whether the Registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes
☒ No ☐The RegistrantRegistrant had 10,538,513 shares14,389,191 shares of common stock outstandingoutstanding on November 8, 2017.
TABLE OF CONTENTS Page PART I ITEM 1 ITEM 2 ITEM 3 ITEM 4 PART II ITEM 1 ITEM 1A ITEM 6Page 6 ITEM 12ITEM 1A
Item 1—Financial Statements GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (In thousands, except share amounts) (Unaudited) September 30, 2021 December 31, 2020 ASSETS CURRENT ASSETS: Cash and cash equivalents Accounts receivable, trade and other, net of allowance Accrued oil and natural gas revenue Fair value of oil and natural gas derivatives Inventory Prepaid expenses and other Total current assets PROPERTY AND EQUIPMENT: Unevaluated properties Oil and natural gas properties (full cost method) Furniture, fixtures and equipment and other capital assets Less: Accumulated depletion, depreciation and amortization Net property and equipment Other TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY CURRENT LIABILITIES: Accounts payable Fair value of oil and natural gas derivatives Accrued liabilities Total current liabilities Long term debt, net Accrued abandonment cost Fair value of oil and natural gas derivatives Other non-current liabilities Total liabilities Commitments and contingencies (See Note 9) STOCKHOLDERS’ (DEFICIT) EQUITY: Preferred stock: 10,000,000 shares $1.00 par value authorized, and none issued and outstanding Common stock: $0.01 par value, 75,000,000 shares authorized, and 14,187,561 shares issued as of September 30, 2021 and 13,392,625 shares issued and outstanding as of December 31, 2020, respectively Treasury stock (4,035 and zero shares, respectively) Additional paid in capital Accumulated deficit Total stockholders’ (deficit) equity TOTAL LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts) (Unaudited) Three Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 REVENUES: Oil and natural gas revenues Other OPERATING EXPENSES: Lease operating expense Production and other taxes Transportation and processing Depreciation, depletion and amortization General and administrative Impairment of oil and natural gas properties Other Operating income (loss) OTHER INCOME (EXPENSE): Interest expense Interest income and other expense Loss on commodity derivatives not designated as hedges Loss on early extinguishment of debt Loss before income taxes Income tax expense Net loss PER COMMON SHARE Net loss per common share - basic Net loss per common share - diluted Weighted average shares of common stock outstanding - basic Weighted average shares of common stock outstanding - diluted See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited) Nine Months Ended September 30, Nine Months Ended September 30, 2021 2020 CASH FLOWS FROM OPERATING ACTIVITIES: Net loss Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation and amortization Impairment of oil and natural gas properties Right of use asset depreciation Loss on commodity derivatives not designated as hedges Net cash received (paid) for settlement of derivative instruments Share-based compensation (non-cash) Loss on early extinguishment of debt Amortization of finance cost, debt discount, paid in-kind interest and accretion Change in assets and liabilities: Accounts receivable, trade and other, net of allowance Accrued oil and natural gas revenue Prepaid expenses and other Accounts payable Accrued liabilities Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Principal payments of bank borrowings Proceeds from bank borrowings Proceeds from 2023 Second Lien Notes Debt issuance costs Purchase of treasury stock Net cash provided by financing activities Increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period Supplemental disclosures of cash flow information: Cash paid for interest Increase (decrease) in non-cash capital expenditures See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY (In thousands) (Unaudited) Preferred Stock Common Stock Additional Paid-in Treasury Stock Accumulated Earnings Total Stockholders’ Shares Value Shares Value Capital Shares Value (Deficit) (Deficit) Equity Balance at December 31, 2019 Net income Share-based compensation Balance at March 31, 2020 Net loss Share-based compensation Discount from 2021/2022 Second Lien Notes Modification (See Note 4) Balance at June 30, 2020 Net loss Share-based compensation Balance at September 30, 2020 Balance at December 31, 2020 Net income Share-based compensation UCC warrant exchange Discount from 2023 Second Lien Notes (See Note 4) Balance at March 31, 2021 Net loss Share-based compensation Balance at June 30, 2021 Net loss Share-based compensation Treasury stock activity UCC warrant exchange Balance at September 30, 2021 See accompanying notes to consolidated financial statements. GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE 1—Description of Business and Significant Accounting Policies Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the “Subsidiary”), “we,” “our,” the “Company,” or the Basis of Presentation The consolidated financial statements of the Company included in this Quarterly Report on Form During the The primary impact of COVID-19 experienced by the Company was a severe decline in the Principles of Consolidation Use of Estimates Cash and Cash Equivalents Accounts Payable (In thousands) September 30, 2021 December 31, 2020 Trade payables Revenue payables Prepayments from partners Miscellaneous payables Total Accounts payable GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Accrued Liabilities—Accrued liabilities consisted of the following amounts as of September 30, 2021 and December 31, 2020: (In thousands) September 30, 2021 December 31, 2020 Accrued capital expenditures Accrued lease operating expense Accrued production and other taxes Accrued transportation and gathering Accrued performance bonus Accrued interest Accrued office lease Accrued general and administrative expense and other Total Accrued liabilities Inventory Property and Equipment Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from three to five years. Full Cost Ceiling Test The Full Cost Ceiling Test GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Fair Value Measurement We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into three Each of these • Level 1 Inputs— unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments; • Level 2 Inputs— quotes that are derived principally from or corroborated by observable market data. Included in this level are our senior credit facilities, second lien notes and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counter-parties; and • Level 3 Inputs— unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this level would be our initial measurement of asset retirement obligations and the equity component determined as a result of fair valuing debt instruments that include a conversion feature. As of September 30, Asset Retirement Obligations The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy. Revenue Recognition Derivative Instruments GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Income Taxes—We account for income taxes during interim periods based on annual projections of our effective tax rate. We account for income taxes on an annual basis, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more Net Income or Net Loss Per Common Share— Commitments and Contingencies Share-Based Compensation Guarantee—As of Debt Issuance Cost—The Company records debt issuance costs associated with its 2023 Second Lien Notes (and previously with its 2021/2022 Second Lien Notes), (both as defined below) as a contra balance to long term debt, net in our Consolidated Balance Sheets, which is amortized straight-line over the life of the New Accounting Pronouncements In March 2020, the Financial Accounting Standards Board (“FASB”) issued In August 2020, the FASB issued ASU GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE 2—Revenue Recognition In accordance with Accounting Standards Codification (“ASC”) Topic 606, revenue is generally recognized upon delivery of our produced oil and natural gas volumes to our customers. Our customer sales contracts include oil and natural gas sales. Under Topic 606, each unit (Mcf or barrel) of commodity product represents a separate performance obligation which is sold at variable prices, determinable on a monthly basis. The pricing provisions of our contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, product quality and prevailing supply and demand conditions in the geographic areas in which we operate. We allocate the transaction price to each performance obligation and recognize revenue upon delivery of the commodity product when the customer obtains control. Control of our produced natural gas volumes passes to our customers at specific metered points indicated in our natural gas contracts. Similarly, control of our produced oil volumes passes to our customers when the oil is measured either by a trucking oil ticket or by a meter when entering an oil pipeline. The Company has no control over the commodities after those points and the measurement at those points dictates the amount on which the customer's payment is based. Our oil and natural gas revenue streams include volumes burdened by royalty and non-operated working interests. Our revenues are recorded and presented on our financial statements net of the royalty and non-operated working interests. Our revenue stream does not include any payments for services or ancillary items other than sale of oil and natural gas. We record revenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales may not be received for up to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. As of September 30, 2021 and December 31, 2020, receivables from contracts with customers were $24.6 million and $10.2 million, respectively. The following table presents our oil and natural gas revenues disaggregated by revenue source and by operated and non-operated properties for the three and nine months ended September 30, 2021 and 2020: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 (In thousands) Oil Revenue Gas Revenue NGL Revenue Total Oil and Natural Gas Revenues Oil Revenue Gas Revenue NGL Revenue Total Oil and Natural Gas Revenues Operated Non-operated Total oil and natural gas revenues Three Months Ended September 30, 2020 Nine Months Ended September 30, 2020 (In thousands) Oil Revenue Gas Revenue NGL Revenue Total Oil and Natural Gas Revenues Oil Revenue Gas Revenue NGL Revenue Total Oil and Natural Gas Revenues Operated Non-operated Total oil and natural gas revenues GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE 3—Asset Retirement Obligations The reconciliation of the beginning and ending asset retirement Nine Months Ended September 30, 2021 Beginning balance at December 31, 2020 Liabilities incurred Accretion expense Ending balance at September 30, 2021 Current liability Long term liability NOTE Debt consisted of the following balances as of September 30, 2021 December 31, 2020 Principal Carrying Amount Principal Carrying Amount 2019 Senior Credit Facility (1) 2021/2022 Second Lien Notes (2) 2023 Second Lien Notes (3) Total debt (1) The carrying amount for the 2019 Senior Credit Facility represents fair value as its variable interest rate approximates market rates. (2) The debt discount was being amortized using the effective interest rate method based upon a maturity date of May 31, 2022. The principal included $2.8 million of paid in-kind interest as of December 31, 2020. The carrying value included $0.9 million of unamortized debt discount and $0.2 million of unamortized issuance cost as of December 31, 2020. (3) The debt discount is being amortized using the effective interest rate method based upon a maturity date of GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The following table summarizes the total interest expense Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate 2019 Senior Credit Facility 2021/2022 Second Lien Notes (1) 2023 Second Lien Notes (2) Total interest expense (1) The 2021/2022 Second Lien Notes had a coupon interest rate of 13.50%; however, the discount recorded due to the convertibility of the notes increased the effective interest rate to 18.6% and 20.1%, respectively, for the three and nine months ended September 30, 2020 and 19.1% for the nine months ended September 30, 2021 until exchanged on March 9, 2021. Interest expense for the three months ended September 30, (2) The 2023 Second Lien Notes have a coupon interest rate of 13.50%; however, the GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 2019 Senior Credit Facility On The All amounts outstanding under the The 2019 Credit Agreement contains certain customary representations and warranties, affirmative and negative covenants and events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the 2019 Senior Credit Facility to be immediately due and payable. The 2019 Credit Agreement also contains certain financial covenants, including the maintenance of (i) a ratio of As of September 30, 2021, the Company had a borrowing base of $120.0 million with $90.4 million of borrowings outstanding and As of September 30, 2021, the Company was in GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Convertible Second Lien In October 2016, the Company The 2019 Second Lien Notes Upon issuance of the On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement with certain purchasers pursuant to which the Company issued to such purchasers $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “2021/2022 Second Lien Notes”). Proceeds from the sale of the 2021/2022 Second Lien Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. In May 2020, the maturity date of the 2021/2022 Second Lien Notes was extended to May 31, 2022. Upon issuance of the 2021/2022 Second Lien Notes on May 31, 2019, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $1.4 million, thereby reducing the $12.0 million carrying value upon issuance to $10.6 million and recorded an equity component of $1.4 million. The fair value of the debt instrument without the conversion feature and the resulting equity component was valued using a binomial lattice model. The debt discount was amortized using the effective interest rate method based upon an original term through May 31, 2021. Upon the maturity extension in May 2020, an additional $0.3 million of debt discount was recorded, and the debt discount began to be amortized using the effective interest rate method based upon the maturity date of May 31, 2022. On March 9, 2021, the Company and the Subsidiary entered into a note purchase and exchange agreement (“the Note Purchase and Exchange Agreement”) with certain purchasers (each such purchaser, together with its successors and assigns, a “2023 Second Lien Notes Purchaser”) pursuant to which the Company issued to the 2023 Second Lien Notes Purchasers (A) $15.2 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2023 (the “2023 Second Lien Notes”) in exchange for an equal amount of 2021/2022 Second Lien Notes and (B) $15.0 million of the 2023 Second Lien Notes in exchange for cash. Proceeds from the sale of the 2023 Second Lien Notes were used to pay down outstanding borrowings under the 2019 Senior Credit Facility. In connection with the Note Purchase and Exchange Agreement, we recorded a $0.9 million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs from the 2021/2022 Second Lien Notes. The 2023 Second Lien Notes, as set forth in the indenture governing the 2023 Second Lien Notes (the “2023 Second Lien Notes Indenture”), are scheduled to mature on May 31, 2023. The 2023 Second Lien Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the 2023 Second Lien Notes by increasing the principal amount of the outstanding 2023 Second Lien Notes. The 2023 Second Lien Notes Indenture contains certain covenants pertaining to us and our Subsidiary, including delivery of financial reports; environmental matters; conduct of business; use of proceeds; operation and maintenance of properties; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; limits on sales of assets and stock; business activities; transactions with affiliates; and changes of control. The 2023 Second Lien Notes Indenture also contains a financial covenant that requires the maintenance of a ratio of Total Proved PV-10 attributable to the Company's and Subsidiary's Proved Reserves (as defined in the 2023 Second Lien Notes Indenture) to Total Secured Debt (net of any Unrestricted Cash not to exceed $10.0 million) not to be less than 1.50 to 1.00. The 2023 Second Lien Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of 2023 Second Lien Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be $21.33, subject to certain adjustments as described in the 2023 Second Lien Notes Indenture. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the 2023 Second Lien Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash; however, the Company’s ability to redeem the 2023 Second Lien Notes with cash is subject to the terms of the 2019 Credit Agreement. Upon issuance of the 2023 Second Lien Notes on March 9,2021, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $1.2 million, thereby reducing the $30.2 million carrying value upon issuance to $29.0 million and recorded an equity component of $1.2 million. The fair value of the debt instrument without the conversion feature and the resulting equity component was valued using a binomial lattice model. The debt discount is amortized using the effective interest rate method based upon an original term through As of September 30, As of September 30, GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE During the three and nine months ended September 30, During the three and nine months ended September 30, 2021, certain holders of costless unsecured claim (“UCC”) warrants exercised such warrants into approximately 780,000 and 790,000 common stock shares, respectively. The UCC warrants, held by certain past unsecured creditors, became exercisable when the In connection with the NOTE Net (Amounts in thousands, except per share data) Basic net loss per common share: Net loss applicable to common stock Weighted average shares of common stock outstanding Basic net loss per common share Diluted net loss per common share: Net loss applicable to common stock Diluted weighted average shares of common stock outstanding Diluted net loss per common share (1) (2) (3) (1) Common shares issuable upon conversion of the 2023 Second Lien Notes and 2021/2022 Second Lien Notes, respectively, not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive for the three and nine months ended September 30, 2021 and September 30, 2020. (2) Common shares issuable upon conversion of the unsecured claims warrants not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive for the three and nine months ended September 30, 2021 and September 30, 2020. (3) Common shares issuable upon vesting of the restricted stock not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive for the three and nine months ended September 30, 2021 and September 30, 2020. ** ** Common shares issuable on assumed vesting of share-based compensation assumes a payout of the Company's performance share awards at 100% of the initial units granted (or a ratio of one unit to one common share). The range of common stock shares which may be earned ranges from zero to 200% of the initial performance units granted. GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE We recorded As of September 30, NOTE We use commodity and financial derivative contracts to manage fluctuations in commodity The following table summarizes gains and losses we recognized on our oil and natural gas derivatives for the three and nine months ended September 30, Oil and Natural Gas Derivatives (in thousands) Gain (loss) on commodity derivatives not designated as hedges, settled Loss on commodity derivatives not designated as hedges, not settled Total gain (loss) on commodity derivatives not designated as hedges Commodity Derivative Activity We enter into swap contracts, costless collars or other derivative agreements from time to time to manage commodity price risk for a portion of our production. Our policy is that all derivatives are approved by the Hedging Committee of Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Decreases in domestic crude oil and natural gas spot prices will have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS As of September 30, Contract Type Average Daily Volume Total Volume Weighted Average Fixed Price Natural Gas swaps (MMBtu) 2021 $ 2.90 2022 (through September 30, 2022) $ 2.91 Natural Gas collars (MMBtu) 2021 2.500 -3.5050 2022 2.688 -3.4040 2023 (through March 31, 2023) 2.655 -3.5151 Natural Gas basis swaps (MMBtu) 2021 NYMEX - $0.209 2022 NYMEX - $0.209 2023 NYMEX - $0.209 2024 NYMEX - $0.209 Total natural gas Contract Type Daily Volume Weighted Average Fixed Price Contract Start Date Contract Termination Natural gas swap (MMBtu) 20,000 $4.06 January 1, 2022 March 31, 2022 Natural gas swap (MMBtu) 30,000 $2.97 April 1, 2022 September 1, 2022 The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of September 30, Description Level 1 Level 2 Level 3 Total Fair value of oil and natural gas derivatives - Current Assets Fair value of oil and natural gas derivatives - Non-current Assets Fair value of oil and natural gas derivatives - Current Liabilities Fair value of oil and natural gas derivatives - Non-current Liabilities Total We enter into September 30, 2021 December 31, 2020 Fair Value of Oil and Natural Gas Derivatives Gross Amount As Gross Amount As (in thousands) Amount Offset Presented Amount Offset Presented Fair value of oil and natural gas derivatives - Current Assets Fair value of oil and natural gas derivatives - Non-current Assets Fair value of oil and natural gas derivatives - Current Liabilities Fair value of oil and natural gas derivatives - Non-current Liabilities Total GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE We are party to various lawsuits from time to time arising in the normal course of business, including, but not limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such Pursuant to a purchase and sale agreement related to acreage acquired in September 2021, the Company has an unrecorded commitment to drill and complete eight producing wells over a four year time period, no later than September 2025. In the event the Company fails to perform this obligation, each of the eight wells is subject to liquidated damages of $0.6 million, or $4.5 million in total as of September 30, 2021. The Company anticipates satisfying this drilling obligation within the required timeframe. NOTE 10—Leases We determine if an arrangement is or contains a lease at inception. Leases with an initial term of 12 months or less are not recorded on our Consolidated Balance Sheets. We lease our corporate office building in Houston, Texas. We recognize lease expense for this lease on a straight-line basis over the lease term. This operating lease is included in furniture, fixtures and equipment and other capital assets, accrued liabilities and other non-current liabilities on our Consolidated Balance Sheets. The operating lease asset and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term. As this lease did not provide an implicit rate, we used a collateralized incremental borrowing rate based on the information available at commencement date, including lease term, in determining the present value of future payments. The operating lease asset includes any lease payments made but excludes annual operating charges. Operating The lease cost components for the three and nine months ended September 30, 2021 and 2020 are classified as follows: (in thousands) Consolidated Statements of Operations Classification Building lease cost General and administrative expense Variable lease cost (1) General and administrative expense (1) Includes building operating expenses. The following are additional details related to our lease portfolio as of September 30, 2021 and December 31, 2020: (in thousands) September 30, 2021 December 31, 2020 Consolidated Balance Sheets Classification Lease asset, gross Furniture, fixtures and equipment and other capital assets Accumulated depreciation Accumulated depletion, depreciation and amortization Lease asset, net Current lease liability Accrued liabilities Non-current lease liability Other non-current liabilities Total lease liabilities GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The following table presents operating lease (in thousands) September 30, 2021 2021 2022 2023 2024 2025 Thereafter Total lease payments Less imputed interest Present value of lease liabilities As of September 30, 2021, our office building operating lease has a weighted-average remaining lease term of 5.6 years and a weighted-average discount rate of 8.8 percent. We have the option to terminate our building operating lease effective May 1, 2024 upon prior written notice and the payment of $0.1 million as an early termination fee. Cash paid for NOTE 11—Subsequent Events Subsequent to On CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with our management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), concerning our operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following: • the market prices of oil and natural gas; • volatility in the commodity-futures market; • financial market conditions and availability of capital; • future cash flows, credit availability and borrowings; • sources of funding for exploration and development; • our financial condition; • our ability to repay our debt; • the securities, capital or credit markets; • planned capital expenditures; • future drilling activity; • uncertainties about the estimated quantities of our oil and natural gas reserves and production from our wells; • the creditworthiness of our hedging counter-parties and the effect of our hedging arrangements; • litigation matters; • pursuit of potential future acquisition opportunities; • general economic conditions, either nationally or in the jurisdictions in which we are doing business; • legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations; • the creditworthiness of our financial counter-parties and operation partners; and • other factors discussed below and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings, press releases and discussions with our management. For additional information regarding known material factors that could cause our actual results to differ from projected results please read the rest of this Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the We seek to increase shareholder value by growing our oil and natural gas reserves, production, revenues and cash flow from operating activities (“operating cash flow”). In our opinion, on a long term basis, growth in oil and natural gas reserves, cash flow and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company. Management strives to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our Board of Directors (the “Board”) on a quarterly basis and revised throughout the year as circumstances warrant. Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the oil and gas industry. Throughout 2020, the effect of To mitigate the effects of the As a result of the steps we have taken to enhance our We remain committed to the • Ensuring the health and safety of our employees and the contractors that provide services to us; • Continuing to monitor the impact the COVID-19 pandemic has on demand for our products in addition to related commodity price impacts in order to adjust our business accordingly; and • Ensuring we emerge from the COVID-19 pandemic in as strong of a position as possible as we continue to move forward with our long-term strategies. While the COVID-19 pandemic may potentially adversely affect our operations or employees’ health in the future, as of the date of this filing, we have not experienced a significant disruption to our operations and Primary Operating Areas Haynesville Shale Trend We Tuscaloosa Marine Shale Trend As of September 30, 2021, we own approximately 48,000 gross Eagle Ford Shale Trend We Results of Operations The items that had the most material financial effect on our The items that had the most material financial effect on our The following table reflects our summary operating information for the periods presented Revenues from Operations Three Months Ended September 30, Nine Months Ended September 30, (In thousands, except for price and average daily production data) 2021 2020 Variance 2021 2020 Variance Revenues: Natural gas Oil and condensate Natural gas, oil and condensate Net Production: Natural gas (Mmcf) Oil and condensate (MBbls) Total (Mmcfe) Average daily production (Mcfe/d) Average realized sales price per unit: Natural gas (per Mcf) Natural gas (per Mcf) including the effect of realized gains/losses on derivatives Oil and condensate (per Bbl) Oil and condensate (per Bbl) including the effect of realized gains/losses on derivatives Average realized price (per Mcfe) Natural gas, oil and condensate revenues increased by Operating Expenses As described below, total operating expenses Three Months Ended September 30, Nine Months Ended September 30, Operating Expenses (in thousands) 2021 2020 Variance 2021 2020 Variance Lease operating expenses Production and other taxes Transportation and processing Operating Expenses per Mcfe Lease operating expenses Production and other taxes Transportation and processing Lease Operating Expense Lease operating expense (“LOE”) increased $0.4 million and $1.0 million, respectively, for the three and nine months ended September 30, 2021, compared to the same periods in 2020. The increase in LOE is Production and Other Taxes Production and other taxes includes severance and ad valorem taxes. Severance taxes were $1.0 million and $2.0 million for the three and nine months ended September 30, Severance taxes Ad valorem tax Transportation and Processing Our natural gas production incurs substantially all of our transportation and processing expense. Transportation and processing expense for the three and nine months ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Operating Expenses (in thousands): 2021 2020 Variance 2021 2020 Variance Depreciation, depletion and amortization General and administrative Impairment of oil and natural gas properties Other Operating Expenses per Mcfe Depreciation, depletion and amortization General and administrative Impairment of oil and natural gas properties Other Depreciation, Depletion and DD&A expense increased $3.0 million and $0.2 million for the three and nine months ended September 30, 2021, respectively, compared to the Impairment Expense The Full Cost Method ceiling test for the three and nine months ended September 30, 2021 resulted in no impairment of oil and natural gas General and Administrative (“G&A”) The The Company recorded $3.9 million and Other Operating Expenses Other operating expense credits of $0.2 million for the nine months ended September 30, 2021 were attributed primarily to the receipt of ad valorem tax credits from a vendor related to prior periods. Other Income (Expense) Three Months Ended September 30, Nine Months Ended September 30, Other income (expense) (in thousands): 2021 2020 Variance 2021 2020 Variance Interest expense Interest income and other Loss on commodity derivatives not designated as hedges Loss on early extinguishment of debt Average funded borrowings adjusted for debt discount Average funded borrowings Interest Expense Interest expense for the three months ended September 30, 2021 included $1.0 million incurred on the Interest expense for the three and nine months ended September 30, Gain (Loss) on Commodity Derivatives Not Designated as Hedges We produce and sell oil and natural gas into a market where prices are historically volatile. We enter into swap contracts, collars or other derivative agreements from time to time to manage our exposure to commodity price risk for a portion of our production. We do not designate our derivative contracts as hedges for accounting purposes. Consequently, the changes in our mark-to-market valuations are recorded directly to income or loss on our financial statements. The loss on commodity derivatives not designated as hedges of $77.4 million for the three months ended September 30, The loss on commodity derivatives not designated as hedges of $11.1 million for the three months ended September 30, 2020 was comprised of a $12.7 million mark-to-market loss, representing the change in fair value of our open natural gas and oil derivative contracts, offset by a $1.6 million net gain on cash settlement of natural gas and oil derivative contracts. The loss on commodity derivatives not designated as hedges of $3.6 million for the nine months ended September 30, 2020 was comprised of a $18.5 million mark-to-market loss, representing the change of the fair value of our open natural gas and oil derivative contracts, offset by Income Tax Benefit We recorded no income tax expense or benefit for the three and nine months ended September 30, The loss on early extinguishment of debt for the Adjusted Adjusted The following table presents a reconciliation of Three Months Ended September 30, Nine Months Ended September 30, (In thousands) 2021 2020 2021 2020 Net loss (US GAAP) Interest expense Depreciation, depletion and amortization Impairment of oil and natural gas properties Share-based compensation expense (non-cash) Loss on commodity derivatives not designated as hedges, not settled Loss on early extinguishment of debt Other items (1) Adjusted EBITDA (1) Other items Management believes that this non-US GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry. Liquidity and Capital Resources Overview Our primary sources of cash during the first nine months of On The On March 9, 2021, the Company and the Subsidiary entered into a purchase and exchange agreement with certain purchasers (each such purchaser, together with its successors and assigns, a “2023 Second Lien Notes Purchaser”) pursuant to which the Company issued to the 2023 Second Lien Notes Purchasers (A) $15.2 million aggregate principal amount of the 2023 Second Lien Notes in exchange for an equal amount of 2021/2022 Second Lien Notes and (B) $15.0 million of the 2023 Second Lien Notes in exchange for cash. Proceeds from the sale of the 2023 Second Lien Notes were used to pay down outstanding borrowings under the 2019 Senior Credit The 2023 Second Lien Notes, as set forth in the indenture governing the 2023 Second Lien Notes (the “2023 Second Lien Notes Indenture”), are The 2023 Second Lien Notes are convertible into the Company’s common stock at the conversion rate, which is the sum of the outstanding principal amount of 2023 Second Lien Notes to be converted, including any accrued and unpaid interest, divided by the conversion price, which shall initially be $21.33, subject to We exited the third quarter of Outlook We plan to focus all of our We believe the results of the capital investments we made in prior years and the nine months of 2021 will generate additional cash flows and additional value that will allow us to continue our capital development in the We continuously monitor our leverage position and coordinate our capital program with our expected cash flows and repayment of our projected debt. We will continue to evaluate funding alternatives as needed. Alternatives available to us include: • availability under the 2019 Senior Credit Facility; • issuance of debt securities; In addition, to support future cash flows We have had an on-going company-wide cost reduction program eliminating outside services that are not core to our business, which we continue to focus on, as well as a reduction in headcount year over year. As a result of the steps we have taken to enhance our liquidity in addition to the current natural gas pricing environment, we anticipate our cash on hand, cash from operations and our available borrowing capacity under our 2019 Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements over the next year. Cash Flows The following table Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Cash flow statement information: Net cash: Provided by operating activities Used in investing activities Provided by (used in) financing activities Increase (decrease) in cash and cash equivalents Operating activities: Investing activities: Financing activities: Net cash provided by (used in) financing activities for the three and nine months ended September 30, 2021 and 2020 primarily reflected net borrowings under our 2019 Senior Credit Facility and proceeds from the issuance of Debt consisted of the following balances as of the dates indicated (in thousands): September 30, 2021 December 31, 2020 Principal Carrying Amount Principal Carrying Amount 2019 Senior Credit Facility (1) 2021/2022 Second Lien Notes (2) 2023 Second Lien Notes (3) Total debt (1)The carrying amount for the 2019 Senior Credit Facility represents fair value as its variable interest rate approximates market rates. (2) The debt discount was being amortized using the effective interest rate method based upon a maturity date of May 31, 2022. The principal included $2.8 million of paid in-kind interest as of December 31, 2020. The carrying value included $0.9 million of unamortized debt discount and $0.2 million of unamortized issuance cost as of December 31, 2020. (3) The debt discount is being amortized using the effective interest rate method based upon a maturity date of For additional information on our financing activities, see Off-Balance Sheet Arrangements We do not currently have any off-balance sheet arrangements for any purpose. Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements, which were prepared in accordance with US GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We believe that certain accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year ended December 31, As a smaller reporting company, we are Evaluation of Disclosure Controls and Procedures In accordance with Exchange Act Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. A discussion of As of September 30, In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of natural gas and oil exploration and development companies and may adversely affect our operations on cash flows. In past years, federal legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal income tax provisions currently available to natural gas and oil exploration and development companies. For example, President Biden has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in the U.S. income tax rate applicable to corporations and (ii) the elimination of tax subsidies for fossil fuels. Congress could consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes on natural gas and oil extraction could adversely affect our operations and cash flows. Item 2—Unregistered Sales of Equity Securities and Use of Proceeds During the three and nine months ended September 30, 2021, we issued to certain holders of unsecured claim warrants approximately 780,000 and 790,000 shares of our common stock, respectively, upon exercise of such warrants. In issuing these shares, we relied on an exemption from the registration requirements provided by Section 1145(a)(1) of the Bankruptcy Code. 3.1 3.2 31.1* 31.2* 32.1** 32.2** 101.INS* Inline XBRL Instance Document 101.SCH* Inline XBRL Schema Document 101.CAL* Inline XBRL Calculation Linkbase Document 101.LAB* Inline XBRL Labels Linkbase Document 101.PRE* Inline XBRL Presentation Linkbase Document 101.DEF* Inline XBRL Definition Linkbase Document * Filed herewith ** Furnished herewith SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. GOODRICH PETROLEUM CORPORATION (Registrant) Date: November 8, By: /S/ Walter G. Goodrich Walter G. Goodrich Chairman & Chief Executive Officer Date: November 8, By: /S/ Kristen McWatters Senior Vice President, $ 5,511 $ 1,360 1,738 920 24,568 10,179 1,637 143 130 130 461 1,292 34,045 14,024 265 240 435,932 359,112 7,660 7,535 443,857 366,887 (213,486 ) (177,669 ) 230,371 189,218 1,536 1,835 $ 265,952 $ 205,077 $ 32,696 $ 27,811 88,138 1,274 19,185 12,866 140,019 41,951 121,749 110,159 5,448 4,716 7,098 3,871 2,510 2,810 276,824 163,507 0 0 142 134 (49 ) 0 85,466 82,842 (96,431 ) (41,406 ) (10,872 ) 41,570 $ 265,952 $ 205,077 (Unaudited) September 30, 2017 December 31, 2016 ASSETS CURRENT ASSETS: Cash and cash equivalents $ 31,086 $ 36,850 Restricted cash 600 — Accounts receivable, trade and other, net of allowance 1,717 1,998 Accrued oil and natural gas revenue 4,662 3,142 Inventory 3,250 4,125 Prepaid expenses and other 483 755 Total current assets 41,798 46,870 PROPERTY AND EQUIPMENT: Unevaluated properties 5,979 24,206 Oil and natural gas properties (full cost method) 104,467 60,936 Furniture, fixtures and equipment 1,014 984 111,460 86,126 Less: Accumulated depletion, depreciation and amortization (12,728 ) (4,006 ) Net property and equipment 98,732 82,120 Other 84 322 TOTAL ASSETS $ 140,614 $ 129,312 LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable $ 17,696 $ 14,392 Accrued liabilities 8,799 3,882 Fair value of commodity derivatives 71 — Total current liabilities 26,566 18,274 Long term debt, net 53,339 47,205 Accrued abandonment cost 3,197 2,933 Fair value of commodity derivatives 49 — Total liabilities 83,151 68,412 Commitments and contingencies (See Note 8) STOCKHOLDERS’ EQUITY: Common stock: $0.01 par value, 75,000,000 shares authorized, and 10,538,513 shares issued and outstanding at September 30, 2017 and $0.01 par value, 75,000,000 shares authorized, and 9,108,826 shares issued and outstanding at December 31, 2016 106 91 Treasury stock (564 and zero shares, respectively) (7 ) — Additional paid in capital 67,890 65,116 Accumulated deficit (10,526 ) (4,307 ) Total stockholders’ equity 57,463 60,900 TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 140,614 $ 129,312 $ 58,733 $ 21,463 $ 128,708 $ 64,917 0 3 0 9 58,733 21,466 128,708 64,926 3,277 2,831 10,429 9,384 1,291 591 2,756 2,361 4,811 4,336 13,457 14,586 13,389 10,341 35,671 35,484 4,329 3,891 11,302 13,327 0 3,040 0 17,170 4 (11 ) (183 ) (13 ) 27,101 25,019 73,432 92,299 31,632 (3,553 ) 55,276 (27,373 ) (2,232 ) (1,733 ) (6,255 ) (5,410 ) 0 5 0 147 (77,369 ) (11,079 ) (103,111 ) (3,629 ) 0 0 (935 ) 0 (79,601 ) (12,807 ) (110,301 ) (8,892 ) (47,969 ) (16,360 ) (55,025 ) (36,265 ) 0 0 0 0 $ (47,969 ) $ (16,360 ) $ (55,025 ) $ (36,265 ) $ (3.52 ) $ (1.30 ) $ (4.08 ) $ (2.89 ) $ (3.52 ) $ (1.30 ) $ (4.08 ) $ (2.89 ) 13,641 12,618 13,481 12,564 13,641 12,618 13,481 12,564 (Unaudited) Successor Predecessor Successor Predecessor Three Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 REVENUES: Oil and natural gas revenues $ 12,964 $ 7,251 $ 34,490 $ 20,132 Other 255 (8 ) 607 (305 ) 13,219 7,243 35,097 19,827 OPERATING EXPENSES: Lease operating expense 2,184 2,009 9,445 6,302 Production and other taxes (15 ) 944 1,068 2,360 Transportation and processing 1,624 360 4,668 1,239 Depreciation, depletion and amortization 3,516 2,312 8,893 7,998 Exploration — 78 — 564 General and administrative 3,749 3,790 11,984 13,874 Gain on sale of assets — (3 ) — (838 ) Other (43 ) — (43 ) — 11,015 9,490 36,015 31,499 Operating income (loss) 2,204 (2,247 ) (918 ) (11,672 ) OTHER INCOME (EXPENSE): Interest expense (2,529 ) (1,251 ) (7,068 ) (11,190 ) Interest income and other 1,250 — 1,271 58 Gain (loss) on commodity derivatives not designated as hedges (313 ) — 193 30 (1,592 ) (1,251 ) (5,604 ) (11,102 ) Restructuring — — — (5,128 ) Reorganization gain (loss), net 108 (10,488 ) 303 (10,046 ) Income (loss) before income taxes 720 (13,986 ) (6,219 ) (37,948 ) Income tax benefit — — — — Net income (loss) 720 (13,986 ) (6,219 ) (37,948 ) Preferred stock, net — 5,116 — 11,237 Net income (loss) applicable to common stock $ 720 $ (19,102 ) $ (6,219 ) $ (49,185 ) PER COMMON SHARE Net income (loss) applicable to common stock - basic $ 0.07 $ (0.24 ) $ (0.64 ) $ (0.64 ) Net income (loss) applicable to common stock - diluted $ 0.05 $ (0.24 ) $ (0.64 ) $ (0.64 ) Weighted average common shares outstanding - basic 10,522 78,854 9,765 77,125 Weighted average common shares outstanding - diluted 13,274 78,854 9,765 77,125 $ (55,025 ) $ (36,265 ) 35,671 35,484 0 17,170 406 939 103,111 3,629 (14,515 ) 14,905 1,208 3,564 935 0 3,643 2,261 (818 ) (583 ) (14,389 ) 3,708 204 65 4,885 2,505 1,288 (2,790 ) 66,604 44,592 (71,065 ) (48,012 ) (71,065 ) (48,012 ) (23,000 ) (1,000 ) 17,000 4,500 15,000 0 (339 ) 0 (49 ) (281 ) 8,612 3,219 4,151 (201 ) 1,360 1,452 $ 5,511 $ 1,251 $ 2,631 $ 3,182 $ 4,599 $ (2,367 ) (Unaudited) Successor Predecessor Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 CASH FLOWS FROM OPERATING ACTIVITIES: Net loss $ (6,219 ) $ (37,948 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depletion, depreciation and amortization 8,893 7,998 Gain on commodity derivatives not designated as hedges (193 ) (30 ) Net cash received in settlement of commodity derivative instruments 313 — Amortization of leasehold costs — 65 Share based compensation (non-cash) 5,093 3,307 Gain on sale of assets — (838 ) Embedded derivative — (5,538 ) Amortization of finance cost, debt discount, paid in-kind interest and accretion 6,134 7,727 Materials inventory write-down — 156 Gain from material transfers (214 ) — Reorganization items, net (186 ) 1,180 Change in assets and liabilities: Accounts receivable, trade and other, net of allowance 281 813 Accrued oil and natural gas revenue (1,520 ) (291 ) Inventory — (458 ) Prepaid expenses and other 250 1,076 Restricted cash (600 ) — Accounts payable 3,304 (3,899 ) Accrued liabilities 477 12,528 Net cash provided by (used in) operating activities 15,813 (14,152 ) CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (21,698 ) (3,498 ) Proceeds from sale of assets 463 292 Net cash used in investing activities (21,235 ) (3,206 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from bank borrowings — 13,000 Net payments related to Convertible Second Lien Notes (168 ) — Note conversions — (804 ) Registration costs (174 ) (116 ) Other — (5 ) Net cash (used in) provided by financing activities (342 ) 12,075 DECREASE IN CASH AND CASH EQUIVALENTS (5,764 ) (5,283 ) CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 36,850 11,782 CASH AND CASH EQUIVALENTS, END OF PERIOD $ 31,086 $ 6,499 Supplemental disclosures of cash flow information: Cash paid for Reorganization items, net $ 986 $ 2,158 Cash paid for Interest $ 1,153 $ 1,606 $ 2,121 $ (837 ) 0 $ 0 12,533 $ 125 $ 81,305 0 $ 0 $ 2,735 $ 84,165 - 0 - 0 0 - 0 3,036 3,036 0 0 1 0 1,309 0 0 0 1,309 Treasury stock activity - 0 - 0 0 - (2 ) 0 (2 ) 0 $ 0 12,534 $ 125 $ 82,614 0 $ (2 ) $ 5,771 $ 88,508 - 0 - 0 0 - 0 (22,941 ) (22,941 ) - 0 130 2 1,533 - 0 0 1,535 - 0 - 0 282 - 0 0 282 Treasury stock activity 0 0 0 0 0 (38 ) (270 ) 0 (270 ) 0 $ 0 12,664 $ 127 $ 84,429 (38 ) $ (272 ) $ (17,170 ) $ 67,114 - 0 - 0 0 - 0 (16,360 ) (16,360 ) 0 0 (8 ) 0 1,193 0 0 0 1,193 Treasury stock activity 0 0 0 0 0 (1 ) (9 ) 0 (9 ) 0 $ 0 12,656 $ 127 $ 85,622 (39 ) $ (281 ) $ (33,530 ) $ 51,938 0 $ 0 13,393 $ 134 $ 82,842 0 $ 0 $ (41,406 ) $ 41,570 - 0 - 0 0 - 0 4,503 4,503 0 0 (1 ) 0 409 - 0 0 409 0 - 10 - - 0 - - - - 0 - 0 1,207 - 0 0 1,207 Treasury stock activity 0 0 0 0 0 (3 ) (28 ) 0 (28 ) 0 $ 0 13,402 $ 134 $ 84,458 (3 ) $ (28 ) $ (36,903 ) $ 47,661 - 0 - 0 0 - 0 (11,559 ) (11,559 ) - 0 - 0 425 - 0 0 425 0 $ 0 13,402 $ 134 $ 84,883 (3 ) $ (28 ) $ (48,462 ) $ 36,527 - 0 - 0 0 - 0 (47,969 ) (47,969 ) - 0 6 0 591 - 0 0 591 0 0 0 0 0 (1 ) (21 ) 0 (21 ) 0 - 780 8 (8 ) 0 - - - 0 $ 0 14,188 $ 142 $ 85,466 (4 ) $ (49 ) $ (96,431 ) $ (10,872 ) “Company”“Registrant”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.10-Q10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”(“the SEC”) and accordingly, certain information normally included in financial statements prepared in accordance with United States Generally Accepted Accounting Principles (“US GAAP”) has been condensed or omitted. This information should be read in conjunction with our consolidated financial statements and notes contained in our annual reportAnnual Report on Form 10-K10-K for the year ended December 31, 2016.2020. Operating results for the three and nine months ended September 30, 20172021 are not necessarily indicative of the results that may be expected for the full year or for any interim period. Certain data in prior periods’ financial statements have been adjusted to conform topresentationfirstnine months of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded, although the impact of the current period.Fresh Start Accounting—We applied fresh start accounting upon emergence from bankruptcy on October 12, 2016 (the “Effective Date”). This resultedCOVID-19 pandemic and related economic, business and market disruptions remain uncertain. Company becoming a new entity for financial reporting purposes. Upon adoptiondemand and price of fresh start accounting,crude oil. Because we predominately produce natural gas and natural gas demand and prices were not impacted by the same market forces as crude oil, we have experienced less of an impact from COVID-19 than many of our assetspeers. However, the scope and liabilities were recorded at their fair values aslength of the Effective Date. As a result, our consolidated statementsCOVID-19 pandemic and the ultimate effect on the price of natural gas and oil cannot be determined, and we could be adversely affected in future periods. Management is actively monitoring the impact on the Company’s results of operations, subsequent to the Effective Date are not comparable to our consolidated statement of operations prior to the Effective Date. Our consolidated financial statementsposition, and related footnotes are presentedliquidity in a format that illustrates the lack of comparability between amounts presented on or after the Effective Datefiscal year 2021 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.All references made to “Successor” or "Successor Company” relate to the Company on and subsequent to the Effective Date. References to the “Successor” in this quarterly report relate to the periods after the Effective Date, which includes the first three quarters of 2017. References to "Predecessor" or “Predecessor Company” in this quarterly report refer to the Company prior to the Effective Date, which includes the first three quarters of 2016.Restricted Cash—As of September 30, 2017, the Company had $0.6 million in restricted cash held as collateral for the issuance of a letter of credit in connection with a natural gas gathering agreement.20172021 and December 31, 2016:2020: $ 9,104 $ 12,190 22,842 14,413 400 664 350 544 $ 32,696 $ 27,811 (In thousands) September 30, 2017 December 31, 2016 Trade payables $ 4,108 $ 2,004 Revenue payable 10,456 11,296 Prepayments from partners 2,838 965 Miscellaneous payables 294 127 Total accounts payable $ 17,696 $ 14,392 $ 8,737 $ 4,138 1,151 971 1,058 509 2,114 1,722 5,023 3,947 146 166 397 962 559 451 $ 19,185 $ 12,866 principalprinciple differences between the two methods are in the treatment of exploration costs, the computation of Depreciation, Depletiondepreciation, depletion and Amortizationamortization (“DD&A”) expense and the assessment of impairment of oil and natural gas properties. Upon emergence from bankruptcy, weWe have elected to adopt the Full Cost Method.costs.costs into a single full cost pool. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, but do not include any costs related to production, general corporate overhead or similar activities. Unevaluated property costs are excluded from the amortization base until we make a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and natural gas properties and thereby subject to DD&A and the full cost ceiling test. For the three and nine months ended September 30, 2017,2021 and 2020, we transferred $5.8less than $0.1 million from unevaluated properties to proved oil and natural gas properties. For the nine months ended September 30, 2021 and 2020, we transferred $0.3 million and $18.6less than $0.1 million, respectively, from unevaluated properties to proved oil and natural gas properties. Our sales of oil and natural gas properties are accounted for as adjustments to net proved oil and natural gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.We(the “UOP”) method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet equivalent of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and natural gas asset together with the estimated future development cost of the proved undeveloped reserves as the numerator. The rate calculated per Mcfe is applied against the periods'period's production also converted to Mcfe to arrive at the periods'period's DD&A expense.presentpresent value of estimated future net cash flows from proved reserves (adjusted for hedges anddiscounted at 10%, excluding cash flows related to estimated abandonment costs)costs already recorded, net of deferred taxes (the “Ceiling”), be compared to the net capitalized costs of proved oil and natural gas properties, net of related deferred taxes. This comparison is referred to as a "ceiling test".“ceiling test.” If the net capitalized costs of proved oil and natural gas properties net of deferred taxes exceed the estimated discounted future net cash flows from proved reserves,Ceiling, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows.Ceiling. Estimated future net cash flows from proved reserves are calculated based on a 12-monthtrailing 12-month average pricing assumption.There were nowrite-downs for the three or nine months ended September 30, 2017.Impairment—Prior to2021 and 2020 resulted in a zero and $3.0 million impairment of the Effective Date, under the Successful Efforts Method of Accounting, we periodically assessed our long-lived assets recorded in oil and natural gas properties, onrespectively. For the Consolidated Balance Sheets to ensure that they were not overstated or carried in excessnine months ended September 30, 2021 and 2020, we recorded 0 impairment and $17.2 million, respectively.To determine if a field was impaired, we compared the carrying value of the field to the undiscounted future net cash flows by applying management’s estimates of proved reserves, future oil and natural gas prices, future production of oil and natural gas reserves and future operating costs over the economic life of the property. In addition, other factors such as probable and possible reserves were taken into consideration when justified by economic conditions and the availability of capital to develop proved undeveloped reserves. For each property determined to be impaired, we recognized an impairment loss equal to the difference between the estimated fair value and the carrying value of the field.Fair value was estimated to be the present value of expected future net cash flows. Any impairment charge incurred was recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of thiscalculation was subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cashflows and fair value.We had no impairment for the three or nine months ended September 30, 2016. Levels (Levels levels (levels 1,2 and 3)3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between Levels.Levelslevels and our corresponding instruments classified by Levellevel are further described below:Level 1 Inputs— unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments;Level 2 Inputs— quotes that are derived principally from or corroborated by observable market data. Included in this Level are our Exit Credit Facility and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties; andLevel 3 Inputs— unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this Level would be acquisitions and impairments of oil and natural gas properties, if any, and our asset retirement obligations.20172021 and December 31, 2016,2020, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.Depreciation and Depletion—Depreciation and depletion of producing oil and natural gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs.Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements, is computed using the straight-line method over their estimated useful lives, which vary from three to five years.23.when production is sold to a purchaser at a fixed or determinable price, whenupon delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crudeour produced oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method.volumes to our customers. We record a liability or an assetrevenue in the month our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas balancing whensales may not be received for up to 60 days after the date production is delivered, and as a result, we have sold more or less than our working interest shareare required to estimate the amount of natural gas production respectively. Atdelivered to the purchaser and the price that will be received for the sale of the product. As ofSeptember 30, 20172021and December 31, 2016,2020, theGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSDifferencesDifferences between actual production and net working interest volumes are routinely adjusted.options,swaps, collars, and swapsoptions for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedgehedging our exposure to changing interest rates. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. We offset the fair value of our asset and liability positions with the same counterpartycounter-party for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. All of our realized gain or losses on our derivative contracts are the result of cash settlements. We have not designated any of our derivative contracts as hedges;hedges for accounting purposes; accordingly, changes in fair value are reflected in earnings. See Note 78.basesbasis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.likely-than-notlikely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See 67.stockholdersstock for each reporting period by the weighted-average numbershares of common sharesstock outstanding during the period. Diluted net income (loss) per common share is computed by dividing net income (loss) applicable to common stockholdersstock for each reporting period by the weighted average numbershares of common sharesstock outstanding during the period, plus the effects of potentially dilutive restricted stock calculated using the treasury stock method and the potential dilutive effect of the conversion or exercise of convertibleother securities, such as warrants and convertible notes, into shares of our common stock. See Note 56.89. The fair valueeach restricted stock award is measured usingSeptember 30, 2021, our Subsidiary was the closing priceSubsidiary Guarantor of our common stock on2023 Second Lien Notes (as defined below). Goodrich has no independent assets or operations, the dayguarantee is full and unconditional and Goodrich has no subsidiaries other than the Subsidiary.award.On August 28, 2017, Accounting Standards UpdateASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU”ASU 2020-04”) 2017-12, Derivatives. The amendments in ASU 2020-04 provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and Hedging (Topic 815): Targeted Improvementsexceptions for applying U.S. GAAP to Accounting for Hedging Activities. This ASU is intended to improve the financial reporting ofcontracts, hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, theand other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU make2020-04 apply only to contracts, hedging relationships and other transactions that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued because of reference rate reform. The expedients and exceptions provided by ASU 2020-04 do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, that an entity has elected certain targeted improvements to simplifyoptional expedients for and that are retained through the applicationend of the hedge accounting guidance in current GAAP based onhedging relationship. Currently, the feedback receivedCompany's only existing contract with potential impact from preparers, auditors, users,reference rate reform is the 2019 Senior Credit Facility, which utilizes LIBOR as a benchmark rate. In October 2020, the Third Amendment of the 2019 Senior Credit Facility included provisions for alternate benchmark rates should LIBOR be discontinued due to reference rate reform. We will continue to evaluate the expected impact these amendments and other stakeholders. For public entities, the amendments in this ASU are effective for annual periods beginning after December 15, 2018. We do not expect this ASU toreference rate reform will have a material impact on our consolidated financial statements as we currently mark to market all of our derivative positions; however, we are evaluating the impact of this ASU should we choose to utilize hedge accounting in the future.On May 10, 2017, and various contracts.2017-09, Compensation 2020- Stock Compensation (Topic 718)06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Scope of Modification Accounting. This Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (“ASU amends2020-06”). The amendments in ASU 2020-06 primarily affect convertible instruments issued with beneficial conversion features or cash conversion features because the scope of modification accounting models for share-based payment arrangements and provides guidance onthose specific features are removed. However, all entities that issue convertible instruments are affected by the types of changesamendments to the terms ordisclosure requirements of ASU 2020-06. For contracts in an entity’s own equity, the contracts primarily affected are freestanding instruments and embedded features that are accounted for as derivatives under the current guidance because of failure to meet the settlement conditions of share-based payment awardsthe derivatives scope exception related to whichcertain requirements of the settlement assessment. Also affected is the assessment of whether an entity wouldGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSbe required to apply modification accounting under ASC 718. For public entities,embedded conversion feature in a convertible instrument qualifies for the derivatives scope exception. Additionally, the amendments in this ASU2020-06 affect the diluted EPS calculation for instruments that may be settled in cash or shares and for convertible instruments. The amendments in ASU 2020-06 are effective for annual periodspublic business entities, excluding entities eligible to be smaller reporting companies, for fiscal years beginning after December 15, 2017. We plan to adopt this ASU on January 1, 2018 and believe the provisions of this ASU will be immaterial to our consolidated financial statements.On November 17, 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU is intended to reduce diversity in the presentation of restricted cash and restricted cash equivalents in the statement of cash flows and requires that restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this ASU should be applied using a retrospective transition method to each period presented.2021, including interim periods within those fiscal years. For publicall other entities, the amendments are effective for annual periods beginning after December 15, 2017. We are currently evaluating the provisions of this ASU and plan to adopt this standard when required for public companies.On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public entities, the amendments are effective for annual periods beginning after December 15, 2016. We adopted this standard in 2017 and anticipate no material impact on our consolidated financial statements until the fourth quarter of 2017, when the initial vestings of restricted stock issued under our Management Incentive Plan occur.On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The key difference between the existing standards and ASU 2016-02 is the requirement for lessees to recognize on their balance sheet all lease contracts with lease terms greater than 12 months, including operating leases. Specifically, lessees are required to recognize on the balance sheet at lease commencement, both (i) a right-of-use asset, representing the lessee’s right to use the leased asset over the term of the lease, and (ii) a lease liability, representing the lessee’s contractual obligation to make lease payments over the term of the lease. For lessees, ASU 2016-02 requires classification of leases as either operating or finance leases, which are similar to the current operating and capital lease classifications. However, the distinction between these two classifications under the ASU does not relate to balance sheet treatment, but relates to treatment and recognition in the statements of income and cash flows. Lessor accounting is largely unchanged from current US GAAP. The amendments are effective for fiscal years beginning after December 15, 2018, 2023, including interim periods within those fiscal years, for public entities. Early application is permitted. We are currently evaluatingyears. The FASB specified that an entity should adopt the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 will supersede mostguidance as of the existing revenue recognition requirements in US GAAP and will requirebeginning of its annual fiscal year. The FASB has also decided to allow entities to recognize revenue at an amount that reflectsadopt the consideration to which it expects to be entitled in exchange for transferring goodsguidance through either a modified retrospective method of transition or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertaintyfully retrospective method of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In May 2016, the FASB issued ASU 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This update rescinds certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. These ASUs are effective for annual and interim periods beginning after December 15, 2017. The Company has not yet selected a transition method.transition. The Company is currently analyzingevaluating the impact of Update 2014-09, and the related ASU's, to evaluate the impact of the new standardthese amendments on its revenue contracts. The Company is considering its revenue contracts, reviewingour accounting for, potential changes that may be needed to its accounting policies and evaluating the new disclosure requirements. The Company expects to complete its evaluations of the impacts of the accounting and disclosure requirements in the fourth quarter of, 2017.our convertible notes. $ 1,771 $ 46,782 $ 0 $ 48,553 $ 5,529 $ 101,334 $ 0 $ 106,863 74 10,100 6 10,180 198 21,635 12 21,845 $ 1,845 $ 56,882 $ 6 $ 58,733 $ 5,727 $ 122,969 $ 12 $ 128,708 $ 1,257 $ 17,665 $ 0 $ 18,922 $ 4,007 $ 52,156 $ 0 $ 56,163 39 2,499 3 2,541 540 8,207 7 8,754 $ 1,296 $ 20,164 $ 3 $ 21,463 $ 4,547 $ 60,363 $ 7 $ 64,917 obligationobligations for the period ending nine months ended September 30, 20172021 is as follows (in thousands): September 30, 2017 Beginning balance at December 31, 2016 $ 2,933 Liabilities incurred 93 Accretion expense 171 Ending balance at September 30, 2017 $ 3,197 Current liability $ — Long term liability $ 3,197 $ 4,716 472 260 $ 5,448 0 $ 5,448 3—4—Debtthe dates indicatedSeptember 30, 2021 and December 31, 2020 (in thousands): September 30, 2017 December 31, 2016 Principal Carrying
Amount Principal Carrying
AmountExit Credit Facility $ 16,651 $ 16,651 $ 16,651 $ 16,651 13.50% Convertible Second Lien Senior Secured Notes due 2019 (1) 45,480 36,688 41,170 30,554 Total debt $ 62,131 $ 53,339 $ 57,821 $ 47,205 (1) �� $ 90,400 $ 90,400 $ 96,400 $ 96,400 0 0 14,811 13,759 32,535 31,349 0 0 $ 122,935 $ 121,749 $ 111,211 $ 110,159 August 30, 2019. May 31, 2023. The principal includes $5.5 million and $1.2$2.3 million of paid in-kind interest at as of September 30, 2017 and December 31, 2016, respectively.2021. The carrying value includes $8.8 million and $10.6$0.9 million of unamortized debt discount at and $0.3 million of unamortized issuance cost as of September 30, 2017 and December 31, 2016, respectively.2021.for the periods shown including contractual(contractual interest expense, amortization of debt discount, accretion and financing costscosts) and the effective interest rate on the liability component of debt for the debtthree and nine months ended September 30, 2021 and 2020 (amounts in thousands, except effective interest rates):GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Successor Predecessor Successor Predecessor Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016 Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate Interest Expense Effective Interest Rate Successor Exit Credit Facility $ 352 8.3 % $ — * $ 883 7.0 % $ — * 13.50% Convertible Second Lien Senior Secured Notes due 2019 (1) 2,177 23.7 % — * 6,185 24.1 % — * Predecessor Senior Credit Facility — — 1,221 * — — 3,134 * 8.0% Second Lien Senior Secured Notes due 2018 — — 23 * — — 936 * 8.875% Senior Notes due 2019 — — — * — — 3,107 * 3.25% Convertible Senior Notes due 2026 — — — * — — 4 * 5.0% Convertible Senior Notes due 2029 — — — * — — 97 * 5.0% Convertible Senior Notes due 2032 — — — * — — 2,382 * 5.0% Convertible Exchange Senior Notes due 2032 — — — * — — 1,484 * Other — — 7 * — — 46 * Total interest expense $ 2,529 $ 1,251 $ 7,068 $ 11,190 (1) $ 1,020 4.2 % $ 1,129 4.6 % $ 3,011 4.2 % $ 3,534 4.9 % 0 0 % 604 18.6 % 500 19.1 % 1,876 20.1 % 1,212 15.7 % 0 0 % 2,744 16.1 % 0 0 % $ 2,232 0 $ 1,733 0 $ 6,255 0 $ 5,410 0 2017 includes $0.72020 included $0.1 million of debt discount amortization and $0.5 million of accrued interest to be paid in-kind, and interest expense for the nine months ended September 30, 2020 included $0.4 million of debt discount amortization and $1.4 million of paid in-kind interest, and interestinterest. Interest expense for the nine months ended September 30, 2017 includes $1.82021 until exchanged on March 9, 2021 included $0.1 million of debt discount amortization and $4.3$0.4 million of paid in-kind interest.* - Not comparative asCompany was in bankruptcy during portionsdiscount recorded due to the convertibility of the 2016 periods shownnotes increased the effective interest rate to 15.7% and did not pay interest on its debt while in bankruptcy.Exit Credit FacilityOn16.1% for the Effective Date, upon consummation of the plan of reorganization, the Company entered into an Exit Credit Agreement (the “Exit Credit Agreement”) with the Subsidiary, as borrower (the “Borrower”),three and Wells Fargo Bank, National Association, as administrative agent (“the Administrative Agent”), and certain other lenders party thereto. Pursuant to the Exit Credit Agreement, the lenders party thereto agreed to provide the Borrower with a $20.0 million senior secured term loan credit facility (the “Exit Credit Facility”). As of nine months ended September 30, 2017, we had $16.7 million outstanding on2021, respectively. Interest expense for the Exit Credit Facility. On October 17, 2017, the Exit Credit Facility was paid off in full and replaced with a $250.0 million senior secured revolving facility with an initial borrowing base of $40.0 million with $16.7 million outstanding.The maturity date of the Exit Credit Agreement was three months ended September 30, 2018, unless2021 included $0.1 million of debt discount and issuance cost amortization and $1.1 million of accrued interest to be paid in-kind, and interest expense for the Borrower notified the Administrative Agent that it intended to extend the maturity date to nine months ended September 30, 2019, subject2021 included $0.4 million of debt discount and issuance cost amortization and $2.3 million of accrued interest to certain conditions and the paymentbe paid in-kind.Until such maturity date, the Loans (as defined in the Exit Credit Agreement) under the Exit Credit Agreement beared interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 4.50% or (ii) adjusted LIBOR plus an applicable margin of 5.50%. As of September 30, 2017, the interest rate on the Exit Credit Facility was 8.75%.The Borrower could have elected, at its option, to prepay any borrowing outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments, which may have been payable pursuant to the terms of the Exit Credit Agreement).The Borrower may have been required to make mandatory prepayments of the Loans under the Exit Credit Agreement if the total borrowings exceeded the aggregate credit amounts, and if the Borrower was not in compliance with the Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) or the Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement).Additionally, if the Borrower had outstanding borrowings and the Consolidated Cash Balance (as defined in the Exit Credit Agreement and the First Amendment and Consent to Exit Credit Agreement dated December 22, 2016) exceeded (i) the sum of $27.5 million plus $21.3 million, which was calculated as the Equity Issuance Net Proceeds from the December 19, 2016 private placement less $2.5 million, as of the close of business on the most recently ended business day on or before March 31, 2018 or (ii) $7.5 million as of the close of business on the most recently ended business day on or after April 1, 2018, the Borrower may have also been required to make mandatory prepayments in an aggregate principal amount equal to such excess.Furthermore, the Borrower was required to make certain mandatory prepayments within one business day of (i) the issuance of any Equity Interests (as defined in the Exit Credit Agreement) of the Company, (ii) the consummation of any sale or other disposition of Property (as defined in the Exit Credit Agreement) and (iii) the assignment, termination or unwinding of any Swap Agreements (as defined in the Exit Credit Agreement).Amounts outstanding under the Exit Credit Agreement were guaranteed by the Company and secured by a security interest in substantially all of the assets of the Company and the Borrower.The Exit Credit Agreement contained certain customary representations and warranties, including as to organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; Investment Company Act; taxes; ERISA; disclosure; no material misstatements; insurance; restrictions on liens; subsidiaries; location of business and offices; properties; titles, etc.; maintenance of properties; gas imbalances, prepayments; marketing of production; swap agreements; use of loans; solvency; sanctions laws and regulations; foreign corrupt practices; money laundering laws; and embargoed persons.The Exit Credit Agreement also contained certain affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments; and swap agreements.The Exit Credit Agreement also contained certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.5 to 1.0 initially, and increasing to 2.0 to 1.0 or after December 31, 2018, (ii) Secured Debt Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.35 to 1.00 for any test date on or before September 30, 2017 and 1.50 to 1.00 after September 30, 2017, in the case of clauses (i) and (ii), to be determined as of January 1 and July 1 each year and as of the date of any Material Acquisition (as defined in the Exit Credit Agreement) or Material Disposition (as defined in the Exit Credit Agreement), (iii) commencing with the fiscal quarter ending March 31, 2018, a ratio of Debt (as defined in the Exit Credit Agreement) as of the end of each fiscal quarter to EBITDAX for the twelve months ending on the last day of such fiscal quarter, not to exceed 4.00 to 1.00, (iv) limitations on Consolidated Cash Balance, (v) limitations on general and administrative expenses and (vi) minimum liquidity requirements.The Exit Credit Agreement also contained certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; voluntary and involuntary bankruptcy; judgments; and change of control.As of September 30, 2017, we were in compliance with all covenants within the Exit Credit Agreement.2017October 17, 2017, May 14, 2019, the Company entered into thea Second Amended and Restated Senior Secured Revolving Credit Agreement (the “Credit“2019 Credit Agreement”) withamong the Company, the Subsidiary, as borrower JP Morgan Chase(in such capacity, the “Borrower”), Truist Bank, N.A. as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2017“2019 Senior Credit Facility”).2017 Senior Credit Facility amends, restates and refinances the obligations under the Exit Credit Facility. The 20172019 Senior Credit Facility matures on the earlier of (a) October 17, 2021 May 14, 2024 or (b) December 2, 2022, if the Convertible2023 Second Lien Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by September 30, December 2, 2022, which is the date that is 180 days prior to the May 31, 2023 “Maturity Date” of the 2023 Second Lien Notes. The 2019 September 30, 2019. The Senior Credit Facility provides for a maximum credit amount under the 2017 Senior Credit Facility is currently $250.0of $500 million with an initialsubject to a borrowing base limitation, which was $120.0 million as of $40.0 million.September 30, 2021 and was increased to $150.0 million during the Fall 2021 borrowing base redetermination. The borrowing base is scheduled to be redetermined in March and September of each calendar year, commencing on or about March 1, 2018, and is subject to additional adjustments from time to time, including, without limitation, for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and theGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSadministrative agent Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. Under the Fifth Amendment to 2019 Credit Agreement entered into on November 5, 2021, the Company is permitted to make restricted payments under the 2019 Credit Agreement so long as (i) no borrowing base deficiency, default or event of default exists or would result therefrom, (ii) after giving pro forma effect to such restricted payment, availability is no less than 20% of the aggregate amount of the available commitments under the 2019 Credit Agreement and (iii) after giving pro forma effect to such restricted payment, the ratio of net funded debt of the Company to EBITDAX shall not be greater than 1.50 to 1.00.The Fifth Amendment to 2019 Credit Agreement also permits the Company to make redemptions of the Second Lien Debt (as defined in the 2019 Credit Agreement) and payments of interest on the 2023 Second Lien Notes so long as each such redemption and interest payment would be permitted as a restricted payment. The Borrower may also request the issuance of letters of credit under the 2019Credit Agreement in an aggregate amount up to $10.0$10 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.20172019 Senior Credit Facility shall bear interest at a rate per annum equal to, at the Company'sCompany’s option, either (i) the alternative base rate plus an applicable margin ranging from 1.75%1.50% to 2.75%2.50%, depending on the percentage of the borrowing base that is utilized, or (ii) adjusted LIBOR plus an applicable margin from 2.75%2.50% to 3.75%3.50%, depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the 20172019 Senior Credit Facility are subject to a 0.50% commitment fee.fee ranging from 0.375% to 0.50%, depending on the percentage of the borrowing base that is utilized. To the extent that a payment default exists and is continuing, all amounts outstanding under the 20172019 Senior Credit Facility will bear interest at 2.00%2.0% per annum above the rate and margin otherwise applicable thereto.The 2017 As of September 30, 2021, the weighted average interest rate on the borrowings from the 2019 Senior Credit Facility was 3.4%. The obligations under the 2019 Credit Agreement are guaranteed by the Company and secured by a first lien security interest in substantially all of the assets of the Company and the Borrower.Total Debt (as defined in the Credit Agreement)net funded debt to EBITDAX not to exceed 4.003.50 to 1.00 as of the last day of any fiscal quarter, (ii) a current ratio (based on the ratio of current assets to current liabilities) liabilities as defined in the 2019 Credit Agreement) not to be less than 1.00 to 1.00 and (iii) until no Convertible2023 Second Lien Notes remain outstanding, a ratio of Total Proved PV10%total proved PV-10 attributable to the Company’s and the Borrower’s Proved Reserves (as defined in the Credit Agreement)proved reserves to Total Secured Debttotal secured debt (net of any Unrestricted Cash unrestricted cash not to exceed $10.0$10 million) not to be less than 1.50 to 1.00 and minimum liquidity requirements.The obligations under the On November 5, 2021, we entered into a Fifth Amendment to 2019 Credit Agreement are guaranteed bywith Subsidiary, the Administrative Agent and the lenders party thereto, pursuant to which, among other things, the lenders made certain changes to the restricted payments and redemption covenants.secured by a first lien security interestno outstanding letters of credit. The Company also had $1.4 million of unamortized debt issuance costs recorded as of September 30, 2021 related to the 2019 Senior Credit Facility.substantiallycompliance with all covenants within the 2019 Senior Credit Facility.13.50% Senior Secured Notes Due 2019On the Effective Date, and the Subsidiary, entered into a purchase agreement (the “Purchase Agreement”) with each entity identified as a Shenkman Purchaser on Appendix A to the Purchase Agreement (collectively, the “Shenkman Purchasers”), CVC Capital Partners (acting through such of its affiliates to managed funds as it deems appropriate), J.P. Morgan Securities LLC (acting through such of its affiliates or managed funds as it deems appropriate), Franklin Advisers, Inc. (as investment manager on behalf of certain funds and accounts), O’Connor Global Multi-Strategy Alpha Master Limited and Nineteen 77 Global Multi-Strategy Alpha (Levered) Master Limited (collectively, and together with each of their successors and assigns, the “Purchasers”), in connection with the issuance ofissued $40.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2019 (the “Convertible“2019 Second Lien Notes”).The aggregate principal amount of the Convertible Second Lien Notes is convertible at the option of the Purchasers at any time prior to the scheduled maturity date at $21.33 per share, subject to adjustments. At closing, the Purchasers were issued along with 10-year costless warrants equal to acquire 2.5 million shares of common stock. Holders of the Convertible2019 Second Lien Notes havehad a second priority lien on all assets of the Company, and haveholders of such warrants had a continuing right to appoint two members to our Board of Directors (the “Board”) as long as the Convertiblesuch warrants were outstanding.are outstanding.Convertible2019 Second Lien Notes will mature on August 30, 2019, or such later date as set forth in the Convertible Second Lien Notes, but in no event later than March 30, 2020. The Convertible Second Lien Notes bearbore interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may electalso had the option under certain circumstances to pay all or any portion of interest in-kind on the then outstanding principal amount of the Convertible2019 Second Lien Notes by increasing the principal amount of the outstanding Convertible2019 Second Lien Notes or by issuing additional Second Lien Notes (“PIK Interest Notes”). The PIK Interest Notes are not convertible. During such time assecond lien notes.Exit Credit Agreement (but not any refinancing or replacement thereof) was in effect, interest on the Convertible Second Lien Notes had to be paid in-kind. As to the new 2017 Senior Credit Facility, interest on the Convertible Second Lien Notes must be paid in-kind; provided however, that after the quarter ending March 31, 2018, if (i) there is no default, event of default or borrowing base deficiency that has occurred and is continuing, (ii) the ratio of total debt to EBITDAX as defined under the 2017 Senior Credit Facility is less than 1.75 to 1.0 and (iii) the unused borrowing base is at least 25%, then the Company can pay the interest on the Convertible2019 Second Lien Notes in cash, at its election.The indenture governing the Convertible Second Lien Notes (the “Indenture”) contains certain covenants pertaining to us and our subsidiary, including delivery of financial reports; environmental matters; conduct of business; use of proceeds; operation and maintenance of properties; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; limits on sale of assets and stock; business activities; transactions with affiliates; and changes of control.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSThe Indenture also contains certain financial covenants, including the maintenance of (i) a Total Proved Asset Coverage Ratio (as defined in the Exit Credit Agreement) not to be less than 1.35 to 1.00 for any test date on or before September 30, 2017 and 1.50 to 1.00 after September 30, 2017, to be determined as of January 1 and July 1 of each year, (ii) limitations on cash general and administrative expenses through 2017 and (iii) minimum liquidity requirements.Upon issuance of the Convertible Second Lien Notes in October 2016, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion as well as warrants on the debt instrument, we recorded a debt discount of $11.0 million, thereby reducing the $40.0 million carrying value upon issuance to $29.0 million and recorded an equity component of $11.0 million. The debt discount was amortized using the effective interest rate method based upon an original term through August 30, 2019. The 2019 Second Lien Notes were redeemed in full on May 29, 2019 for $56.7 million, using borrowings under the 2019 Senior Credit Facility. In connection with the redemption of the 2019 Second Lien Notes, we recorded a $1.6 million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs.AugustMay 31, 2023. In connection with the extinguishment of the 2021/2022 Second Lien Notes, we recorded a loss on early extinguishment of debt of $0.9 million consisting of $0.8 million of remaining unamortized debt discount and $0.1 million of remaining unamortized debt issuance costs on the 2021/2022 Second Lien Notes.2019. $8.82021, $0.9 million of debt discount remainsand $0.3 million of debt issuance costs remained to be amortized on the Convertible2023 Second Lien Notes asNotes.2017.As of September 30, 2017, we were2021, the Company was in compliance with all covenants withinwith respect to the Indenture governing the Convertible2023 Second Lien Notes.Notes Indenture.4—5—Equity2017,2021, the Company had vestings of its share-based compensation units representing a total fair value of less than $0.1 million, which resulted in the issuance of approximately 6,000 common stock shares. The Company withheld shares for payment of taxes due upon vesting and unrestriction of share-based compensation, which resulted in 4,035 shares held in treasury as of September 30, 2021. During the three and nine months ended September 30, 2020, the Company had vestings of its share-based compensation units upon the retirement of certain employees representing a total fair value of less than $0.1 million and $1.0 million, respectively, which resulted in the issuance of approximately 6,000 and 136,000 common stock shares, respectively. The Company withheld shares for payment of $0.3 million in taxes due upon vesting resulting in 39,700 shares held in treasury as of September 30, 2020.10 year costless warrants associatedrequired equity strike price (as defined per the warrant agreement) of $230.0 million was achieved on July 14, 2021.Convertibleissuance of the 2023 Second Lien Notes, exercised 54,687 warrantswe recorded an equity component of $1.2 million in March 2021. The equity component recorded for the issuance of an equal amount of our one cent par value common stock. The Company received cash for the one cent par value for issuance of 54,687 common shares. During the nine months ended September 30, 2017, certain holders of the 10 year costless warrants associated with the Convertible2023 Second Lien Notes exercised 1,429,687 warrantsis not remeasured as long as it continues to meet the condition for the issuance of an equal amount of our one cent par value common stock. The Company received cash for the one cent par value for issuance of 679,687 common shares and the remaining common shares were issued cashless, which resulted in 564 shares repurchased by the Company and held in treasury stock. As of September 30, 2017, 1,070,312 of such warrants remain un-exercised.equity classification. For further details, see Note 4.5—6—Net Income (Loss) Per Common ShareUpon our emergence from bankruptcy on the Effective Date, as discussed in Note 1—“Description of Business and Significant Accounting Policies”, the Predecessor Company's outstanding common stock and preferred stock were canceled, and new common stock and warrants were then issued.income (loss)loss applicable to common stock was used as the numerator in computing basic and diluted income (loss)net loss per common share for the three and nine months ended September 30, 20172021 and 2016.2020. The Company used the treasury stock method in determining the effects of potentially dilutive restricted stock. The following table sets forth information related to the computations of basic and diluted income (loss)net loss per common share: Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 $ (47,969 ) $ (16,360 ) $ (55,025 ) $ (36,265 ) 13,641 12,618 13,481 12,564 $ (3.52 ) $ (1.30 ) $ (4.08 ) $ (2.89 ) $ (47,969 ) $ (16,360 ) $ (55,025 ) $ (36,265 ) 13,641 12,618 13,481 12,564 $ (3.52 ) $ (1.30 ) $ (4.08 ) $ (2.89 ) 1,525 672 1,525 672 715 1,329 715 1,329 251 420 150 231 Successor Predecessor Successor Predecessor Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016 (Amounts in thousands, except per share data) (Amounts in thousands, except per share data) Basic net income (loss) per share: Net income (loss) applicable to common stock $ 720 $ (19,102 ) $ (6,219 ) $ (49,185 ) Weighted average shares of common stock outstanding 10,522 78,854 9,765 77,125 Basic net income (loss) per share $ 0.07 $ (0.24 ) $ (0.64 ) $ (0.64 ) Diluted net income (loss) per share: Net income (loss) applicable to common stock 720 (19,102 ) (6,219 ) (49,185 ) Weighted average shares of common stock outstanding 10,522 78,854 9,765 77,125 Diluted loss per share: Common shares issuable upon conversion of the Convertible Second Lien Notes associated warrants 1,070 * * * Common shares issuable upon conversion of warrants of unsecured claim holders 1,350 * * * Common shares issuable to unsecured claim holders 39 * * * Common shares issuable on assumed conversion of restricted stock 293 * * * Diluted weighted average shares of common stock outstanding 13,274 78,854 9,765 77,125 Diluted net income (loss) per share (1) (2) (3) (4) (5) $ 0.05 $ (0.24 ) $ (0.64 ) $ (0.64 ) (1) Common shares issuable upon assumed conversion of convertible preferred stock or dividends paid were not presented as they would have been anti-dilutive. — 14,966 — 14,966 (2) Common shares issuable upon assumed conversion of the 2026 Notes, 2029 Notes, 2032 Exchange Notes and 2032 Notes or interest paid were not presented as they would have been anti-dilutive. — 5,910 — 5,910 (3) Common shares issuable on assumed conversion of restricted stock, stock warrants and employee stock options were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. — 13,062 291 13,062 (4) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. 1,875 — 1,875 — (5) Common shares issuable upon conversion of the Convertible Second Lien Notes associated warrants and unsecured claim holders were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. — — 2,459 — * Adjustments to weighted average shares of common stock is not applicable due to a net loss for the period.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS6—7—Income Taxesno0 income tax expense or benefit for the three and nine months ended September 30, 2017.2021 and 2020. We recordedmaintained a valuation allowance at December 31, 2016,September 30, 2021, which resulted in no net deferred tax asset or liability appearing on our statement of financial position.consolidated balance sheets. We recordedcontinued to maintain this valuation allowance after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years) that led to a conclusion that based upon the more-likely-than-notmore-likely-than-not standard of the accounting literature our deferred tax assets wereare unrecoverable. Considering the Company’s taxable income forecasts, our assessment of the realization of our deferred tax assets has not changed, and we continue to maintain a fullThe valuation allowance forwas $86.7 million as of December 31, 2020. The valuation allowance has no impact on our ability to utilize our net deferredoperating losses for tax assets aspurposes. However, we are subject to IRC Section 382, which may limit our ability to utilize net operating losses to offset future taxable income.2017.As of September 30, 2017,2021, we have no unrecognized tax benefits. There were no0 significant changes to the calculationour tax position since December 31, 2016.2020.7—8—Commodity Derivative Activitiesprices and interest rates.prices. We are currently not designating our derivative contracts for hedge accounting. All derivative gains and losses are from our oil and natural gas derivative contracts and have been recognized in “Other income (expense)” on our Consolidated Statements of Operations.20172021 and 2016: Successor Predecessor Successor Predecessor Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016 Oil and Natural Gas Derivatives (in thousands) Gain on commodity derivatives not designated as hedges, settled $ 166 $ — $ 313 $ — Loss on commodity derivatives not designated as hedges, not settled (479 ) — (120 ) 30 Total gain/(loss) on commodity derivatives not designated as hedges $ (313 ) $ — $ 193 $ 30 Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 $ (12,498 ) $ 1,597 $ (14,515 ) $ 14,905 (64,871 ) (12,676 ) (88,596 ) (18,534 ) $ (77,369 ) $ (11,079 ) $ (103,111 ) $ (3,629 ) theour Board, and reviewed periodically by the Board.counterparties.counter-parties. Neither our counterpartiescounter-parties nor we require any collateral upon entering into derivative contracts. We were notwould have been at risk of losing any fair value amountsloss of $0.9 million had our counterpartiesARM Energy been unable to fulfill their obligations as of September 30, 2017.2021.2017,2021, the open positions on our outstanding commodity derivative contracts, all of which were natural gas contracts with BP,Truist Bank, RBC Capital Markets, ARM Energy and Citizens Commercial Banking were as follows: Fair Value at September 30, 2021 (In thousands) 120,000 11,040,000 $ (32,777 ) 49,780 13,590,000 (27,974 ) 30,000 2,760,000 (6,608 ) 60,000 21,900,000 (24,907 ) 30,000 2,700,000 (2,199 ) 50,000 4,600,000 1,362 50,000 18,250,000 427 50,000 18,250,000 (346 ) 50,000 18,300,000 (577 ) $ (93,599 ) GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSContract Type Daily Volume (MMBtu) Total Volume (MMBtu) Fixed Price Fair Value at September 30, 2017 (In thousands) Natural Gas Swaps 2017 6,000 552,000 $ 3.20 $ 80 2018 20,000 7,300,000 $2.985 - $3.015 $ (282 ) Natural Gas Costless Collars 2017 12,000 1,104,000 $3.00 - $3.60 $ 82 Subsequent toDuring the third quarter of 2017,2021, we entered into the following new derivative contracts with JP Morgan: Truist Bank, RBC Capital Markets, and Citizens Commercial Banking:Contract Type Daily Volume (MMBtu or Barrels) Total Volume (MMBtu or Barrels) Fixed Price Contract Start Date Contract Termination Natural Gas Swaps 2018 16,000 480,000 $ 3.03 6/1/2018 6/30/2018 2018 18,000 1,656,000 $ 3.03 7/1/2018 9/30/2018 2018 19,000 1,748,000 $ 3.03 10/1/2018 12/31/2018 2019 34,000 3,060,000 $ 3.03 1/1/2019 3/31/2019 2019 7,500 2,062,500 $ 3.03 4/1/2019 12/31/2019 Oil Swaps 2017-2018 400 84,800 $ 51.08 12/1/2017 6/30/2018 2018 350 64,400 $ 51.08 7/1/2018 12/31/2018 2019 325 58,825 $ 51.08 1/1/2019 6/30/2019 2019 300 55,200 $ 51.08 7/1/2019 12/31/2019 Natural gas swap (MMBtu) 20,000 $3.75 August 1, 2021 December 31, 2021 20172021 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Description Level 1 Level 2 Level 3 Total Current Assets Commodity Derivatives $ — $ — $ — $ — Non-current Assets Commodity Derivatives — — — — Current Liabilities Commodity Derivatives — (71 ) — (71 ) Non-current Liabilities Commodity Derivatives — (49 ) — (49 ) Total $ — $ (120 ) $ — $ (120 ) $ 0 $ 1,637 $ 0 $ 1,637 0 0 0 0 0 (88,138 ) 0 (88,138 ) 0 (7,098 ) 0 (7,098 ) $ 0 $ (93,599 ) $ 0 $ (93,599 ) oil and natural gascommodity derivative contracts under which we have netting arrangements with each counter party.counter-party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Consolidated Balance Sheets for the periods ending as of September 30, 20172021 and December 31, 2016:2020: $ 3,087 $ (1,450 ) $ 1,637 $ 3,193 $ (3,050 ) $ 143 1,648 (1,648 ) 0 537 (537 ) 0 (89,588 ) 1,450 (88,138 ) (4,324 ) 3,050 (1,274 ) (8,746 ) 1,648 (7,098 ) (4,408 ) 537 (3,871 ) $ (93,599 ) $ 0 $ (93,599 ) $ (5,002 ) $ 0 $ (5,002 ) September 30, 2017 December 31, 2016 Gross
Amount Amount
Offset As
Presented Gross
Amount Amount
Offset As
PresentedCurrent Assets Commodity Derivatives $ 436 $ (436 ) $ — $ — $ — $ — Non-current Assets Commodity Derivatives 30 (30 ) — — — — Current Fair Value of Commodity Derivatives (507 ) 436 (71 ) — — — Non-current Fair Value of Commodity Derivatives (79 ) 30 (49 ) — — — Total $ (120 ) $ — $ (120 ) $ — $ — $ — 8—9—Commitments and Contingencieswill would not be have been material to our consolidated financial position, results of operations or liquidity.liquidity for the three and nine months ended September 30, 2021 and 2020.Leases—lease expense is recognized on a straight-line basis over the lease term and reported in general and administrative operating expense on our Consolidated Statements of Operations. We have commitments underalso entered into leases for other equipment which are immaterial to our financial statements and/or have lease terms less than 12 months and have therefore not been recorded on our Consolidated Balance Sheets. Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 $ 201 $ 385 $ 236 $ 1,155 12 (3 ) 86 20 $ 213 $ 382 $ 322 $ 1,175 $ 5,871 $ 5,871 (2,850 ) (2,445 ) $ 3,021 $ 3,426 $ 397 $ 962 2,510 2,810 $ 2,907 $ 3,772 agreementsliability maturities as of September 30, 2021: 159 637 653 661 678 914 $ 3,702 795 $ 2,907 office spaceamounts included in the measurement of operating lease liabilities was $0.2 million and office equipment. Total rent expense$0.8 million for the three and nine months ended September 30, 2017 and 20162021, respectively. Cash paid for amounts included in the measurement of operating lease liabilities was approximately $0.4 million and $0.4 million, respectively, and total rent expense for the nine months ended September 30, 2017 and 2016 was approximately $1.3$0.4 million and $1.2 million for the three and nine months ended September 30, 2020, respectively.Defined Contribution Plan – We have a defined contribution plan (“DCP”) that has a Company matching optionemployees' contributions. Participation in the DCP is voluntary and all employeesSeptember 30, 2021, certain holders of unsecured claims warrants of the Company are eligible to participate. We suspendedexercised such warrants, which resulted in the Company's match in April 2016. We charged to expense plan contributionsissuance of zero for the three months ended September 30, 2017 and 2016, and zero and $0.1 million for the nine months ended September 30, 2017 and 2016, respectively.NOTE 9—Subsequent EventsOctober 17, 2017, November 5, 2021, we entered into a Fifth Amendment to Credit Agreement with Subsidiary, the 2017 Senior Credit FacilityAdministrative Agent and the lenders party thereto, pursuant to which, amends, restatesamong other things, the lenders made certain changes to the restricted payments and refinances the obligations under the Exit Credit Facility. For further discussion, see 3—“2017 Senior Credit Facility”. As4—Debt.The Company entered into new natural gas swaps and oil swaps with JP Morgan on October 23, 2017 for a total of 9,006,500 MMbtu of natural gas and 263,225 barrels of oil through 2019. See Note 7—“Commodity Derivative Activity” for further details.the market prices of oil and natural gas;volatility in the commodity-futures market;financial market conditions and availability of capital;future cash flows, credit availability and borrowings;sources of funding for exploration and development;our financial condition;our ability to repay our debt;the securities, capital or credit markets;planned capital expenditures;future drilling activity;uncertainties about the estimated quantities of our oil and natural gas reserves;production;hedging arrangements;litigation matters;pursuit of potential future acquisition opportunities;general economic conditions, either nationally or in the jurisdictions in which we are doing business;legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, risks and liability under federal, state and local environmental laws and regulations;the impact of restrictive covenants in our debt agreements;the creditworthiness of our financial counterparties and operation partners;failure to satisfy our short- or long-term liquidity needs, including our inability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; andother factors discussed below and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings, press releases and discussions with our management.• public health crises, such as the Coronavirus Disease 2019 (“COVID-19”) outbreak in 2020 and 2021; reportQuarterly Report on Form 10-Q and Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016.2020."Subsidiary”“Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.We striveWeWhen establishing our capital expenditure budget, we take into consideration our projected operating cash flow, commodity prices for oil and natural gas and externally available sources of financing, such as bank debt, asset divestitures, issuance of debt and equity securities and strategic joint ventures, when establishing our capital expenditure budget.We place primary emphasis on our operating cash flow in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains (losses), non-cash general and administrative expenses and impairments.Such pricing factorsThe prices we receive for our production are largely beyond our control; however, wecontrol. We have historically employed commodity hedging techniquesbeen able to hedge our natural gas production at prices that are higher than current strip prices in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.Emergence from Bankruptcy On April 15, 2016 (the “Petition Date”), we filed voluntary bankruptcy petitions seeking relief under Chapter 11 However, depending on volatility in the commodity price environment, our ability to enter into comparable derivative arrangements may be more limited.Title 11COVID-19 significantly lowered the demand for and prices of crude oil which resulted in an oversupply of crude oil with significant downward pressure on commodity prices for much of the United States Bankruptcy Codeyear. During the first half of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, the effect of the COVID-19 pandemic and related economic, business and market disruptions remain uncertain. The most direct and immediate impact that the Company experienced from the COVID-19 pandemic was decreased demand for and prices of crude oil. While the prices of and demand for crude oil have recovered from the lows seen in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”), to pursue a Chapter 11 plan of reorganization (the “Chapter 11 Cases”). We filed a motion with the Bankruptcy Court seeking joint administrationinitial stages of the Chapter 11 Cases underpandemic, further outbreaks or the caption In re Goodrich Petroleum Corporation, et al. (Case No. 16-31975). Our joint planemergence of reorganization (the “Plannew strains of Reorganization”) was confirmedthe virus could result in the reimposition of federal, state and local regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing similar measures. Widespread reimposition of these or similar restrictions could result in reductions in the prices of and demand for crude oil, as well as logistic constraints, increases in our costs, workforce shortages and unavailability of raw materials. Because we predominately produce natural gas, and natural gas has not been impacted by the Bankruptcy Courtsame market forces as crude oil, we have experienced less of an impact from COVID-19 than many of our peers. However, the scope and length of the COVID-19 pandemic and the ultimate effect on September 28, 2016,the price of natural gas cannot be determined, and we emerged from bankruptcy on October 12, 2016 (the “Effective Date”).Upon our emergence from bankruptcy, we adopted Fresh Start Accountingcould be adversely affected in accordance with the requirements of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification 852, “Reorganizations”. This resulted in our becoming a new entity for financial reporting purposes. At that time, our assets and liabilities were recorded at their fair values as of the Effective Date. The effects of the Plan of Reorganization and our application of fresh start accounting are reflected in our consolidated financial statements as of December 31, 2016. The related adjustments were recorded in our consolidated statement of operations as reorganization items for the year to date period ending on the Effective Date.The application of fresh start accounting andfuture periods.implementationdownturn in commodity prices due to the effects of COVID-19, we initiated a company-wide cost reduction program eliminating outside services that are not core to our business, on which we continue to focus, as well as a reduction in headcount year over year. Additionally, we have substantial volumes of our Planproduction hedged through the first quarter of Reorganization resulted in2022, and to a lesser extent, volumes hedged from April 2022 to March 2023.Consolidated Financial Statementsliquidity, we anticipate our cash on or after the Effective Date not being comparable with the Consolidated Financial Statements prior to that date. Our financial results for periods followinghand, cash from operations and our application of fresh start accountingavailable borrowing capacity under our 2019 Senior Credit Facility will be different from historical trends,sufficient to meet our investing, financing, and the differences may be material.All references made to “Successor” or “Successor Company” relateworking capital requirements into 2022.Companyfollowing priorities while navigating through the COVID-19 pandemic:subsequent to the Effective Date. References to the “Successor”we have implemented a contingency plan, with employees working remotely where possible and in this quarterly report relate to the periods after the Effective Date, which includes the first three quarters of 2017. References to “Predecessor” or “Predecessor Company” in this quarterly report refer to the Company prior to the Effective Date, which includes the first three quarters of 2016.On the Effective Date, to better reflect the true economics of our explorationcompliance with governmental orders and development of oilCenters for Disease Control and natural gas reserves, we transitioned from the Successful Efforts Method of Accounting for oil and gas activities to the Full Cost Method of Accounting.Our development acreage in this trend is primarily centered in DeSoto and Caddo parishes, Louisiana and Angelina and Nacogdoches counties, Texas. held approximately 50,000have acquired or farmed-in leases totaling approximately 56,000 gross (26,000(32,000 net) acresacres as of September 30, 2017 producing from and prospective for2021 in the Haynesville Shale Trend. DuringWe completed and produced 4 gross (2.2 net) new wells in the third quarter of 2017, we entered into acreage swap transactions which increased our contiguous acreage position2021 and will allow us to drill longer lateral wells.had 8 gross (2.3 net) wells in the drilling or completions phase as of September 30, 2021. Our Haynesville Shale Trend drilling activities are currently located in leasehold areas in Caddo, DeSoto and Red River parishes, Louisiana. Our net production volumes from our Haynesville Shale Trend wells represented approximately 88%approximately 99% of ourour total equivalent production on a Mcfe basis and substantially all of our natural gas production for the third quarter of 2017.2021. We drilled one gross (0.7 net) wellare focusing on increasing our natural gas production volumes through increased drilling in the third quarter of 2017, which will be completed in the fourth quarter of 2017. WeHaynesville Shale Trend, where we plan to focus all of our 20172021 drilling efforts in the Haynesville Shale Trend.We held approximately 102,000(71,000(34,000 net) acreslease acres in the TMS, as of September 30, 2017.an oil shale play in Southwest Mississippi and Southwest Louisiana, which is predominately held by production. We have 2 gross (1.7 net) TMS wells drilled and awaiting completion. Our net production volumes from our TMS wells represented approximately 12%1% of our total equivalent production on a Mcfe basis and approximately 100%99% of our total oil productionproduction for the third quarter of 2017. We did not conduct any2021. Despite no capital expenditures, we are seeking to maintain production through strategic expense workover operations on any wells in the TMS during the third quarterTMS.holdhave retained approximately 14,0004,300 net acres of undeveloped leasehold in the Eagle Ford Shale Trend allin Frio County, Texas as of which is prospective for future development or sale.September 30, 2021.In addition to adopting Fresh Start Accounting, the Successor also adopted the Full Cost Method of Accounting as of the Effective Date. Prior to the Effective Date, the Predecessor used the Successful Efforts Method of Accounting. The results of operations of the Successor and the Predecessor are not generally comparable nor are they individually comparable with prior periods. We believe however, that production volumes, oil and natural gas revenues, lease operating expenses and production and other taxes are generally comparable and consequently, unless otherwise indicated, the tables and discussions below include such comparisons between the Predecessor and the Successor for these operational items. We believe this presentation gives the reader a better understanding of our operational results in 2017.The predecessor 2016 period results of operations (displayed below) reflect the period from January 1, 2016 to September 30, 2016. Net Lossnet loss of $37.9$48.0 million and $55.0 million for the three and nine months ended September 30, 2016 was2021, compared to prior year respective periods, were higher losses on derivatives not designated as hedges, largely non-cash mark-to-market losses, of $77.4 million and $103.1 million, respectively. These higher losses were partially offset by no impairment expense in the cost of our failed restructuring effort priorcurrent year and increased oil and natural gas revenues due to filing for bankruptcy, interest expenseincreased natural gas and depletion, depreciationoil prices and amortization expense.The successor 2017 period results of operations (displayed below) reflect the periodhigher production from January 1, 2017 to September 30, 2017. new wells brought online. Net Lossnet loss of $6.2$16.4 million and $36.3 million for the three and nine months ended September 30, 20172020, compared to prior respective periods, were workover expenses includedthe decrease in lease operating expenses, performance bonus accrual includedrevenues as a result of a substantial drop in generaloil and administrative expensesnatural gas prices for both the three and interest expense offsetnine months ended September 30, 2020, a mark-to-market loss on unsettled derivative contracts driven by non-recurring other income.in(in thousands, except for price and volume data.data). Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results. Three Months Ended September 30, Nine Months Ended September 30, Successor Predecessor Successor Predecessor (In thousands, except for price data) 2017 2016 Variance 2017 2016 Variance Revenues: Natural gas $ 9,567 $ 2,562 $ 7,005 273 % $ 22,955 $ 5,465 $ 17,490 320 % Oil and condensate 3,397 4,689 (1,292 ) (28 )% 11,535 14,667 (3,132 ) (21 )% Natural gas, oil and condensate 12,964 7,251 5,713 79 % 34,490 20,132 14,358 71 % Net Production: Natural gas (MMcf) 3,235 1,275 1,960 154 % 7,863 4,211 3,652 87 % Oil and condensate (MBbls) 71 107 (36 ) (34 )% 237 376 (139 ) (37 )% Total (Mmcfe) 3,661 1,916 1,745 91 % 9,285 6,466 2,819 44 % Average daily production (Mcfe/d) 39,793 20,826 18,967 91 % 34,011 23,599 10,412 44 % Average realized sales price per unit: Natural gas (per Mcf) $ 2.96 $ 2.01 $ 0.95 47 % $ 2.92 $ 1.30 $ 1.62 125 % Natural gas (per Mcf) including cash settled derivatives $ 3.01 $ 2.01 $ 1.00 50 % $ 2.96 $ 1.30 $ 1.66 128 % Oil and condensate (per Bbl) $ 47.85 $ 43.89 $ 3.96 9 % $ 48.67 $ 39.02 $ 9.65 25 % Average realized price (per Mcfe) $ 3.54 $ 3.78 $ (0.24 ) (6 )% $ 3.71 $ 3.11 $ 0.60 19 % $ 56,888 $ 20,167 $ 36,721 182 % $ 122,981 $ 60,370 $ 62,611 104 % 1,845 1,296 549 42 % 5,727 4,547 1,180 26 % 58,733 21,463 37,270 174 % 128,708 64,917 63,791 98 % 15,108 11,346 3,762 33 % 40,113 35,937 4,176 12 % 26 33 (7 ) (21 )% 89 107 (18 ) (17 )% 15,265 11,543 3,722 32 % 40,646 36,576 4,070 11 % 165,925 125,462 40,463 32 % 148,885 133,487 15,398 12 % $ 3.77 $ 1.78 $ 1.99 112 % $ 3.07 $ 1.68 $ 1.39 83 % $ 2.94 $ 1.89 $ 1.05 56 % $ 2.70 $ 2.06 $ 0.64 31 % $ 70.40 $ 39.63 $ 30.77 78 % $ 64.50 $ 42.76 $ 21.74 51 % $ 70.40 $ 49.90 $ 20.50 41 % $ 64.25 $ 55.06 $ 9.19 17 % $ 3.85 $ 1.86 $ 1.99 107 % $ 3.17 $ 1.77 $ 1.40 79 % $5.7$37.3 million and by $14.4$63.8 million, respectively, for the three and nine months ended September 30, 2017, respectively,2021, compared to the same periods in 2016.2020. The increases wereincrease was primarily driven by higher realized natural gas and oil prices coupled with increased natural gas production and higher realized oil and natural gas prices.volumes. The increaserise in natural gas production volumes is attributed to two operated Haynesville Shale Trend wells completed in the second quarter of 2017 and the continued production of two non-operated Haynesville Shale Trend wells completed in late 2016. Beginning in August 2016, we elected to take our production in-kindoil prices increased revenues by $23.6 million and market the majority of our non-operated Haynesville Shale Trend natural gas volumes resulting in an improvement in the prices we received on such natural gas volumes. Natural gas realized prices$52.1 million, respectively, for the three and nine months ended September 30, 2016 included the netting of transportation2021, and processing costs on such volumes that was discontinued upon taking our production in-kind. For the three and nine months ended September 30, 2017, 74% and 67%, respectively, of our oil andhigher natural gas revenue was attributable to natural gas sales compared to 35%volumes had a $14.2 million and 27%$12.8 million impact on revenues for the three and nine months ended September 30, 2016,2021, respectively.We are concentrating on increasing our natural gas production volumes through increased drilling in the Haynesville Shale Trend.decreased $0.8increased $2.1 million and increased $1.9 million infor the three months ended September 30, 2021 and decreased $18.9 million for the nine months ended September 30, 2017, respectively,2021, compared to the same periods in 2016.2020. The decreaseincrease in total operating expenses for the three months ended September 30, 20172021 was primarily due to the decrease inexpenses associated with higher production volumes, including lease operating expenses, production and other taxes, discussed further below.transportation and processing and depletion and amortization expense, partially offset by no impairment expense in 2021. The increasedecrease in total operating expenses for the nine months ended September 30, 20172021 was primarily the result of $3.1 million of workover costs includeddue to no impairment expense in 2021 and lower transportation and processing and general and administrative expense, partially offset by higher lease operating expenses due to increased production volumes. On a per unit basis, excluding the impact of impairment expense in 20172020, operating costs decreased $0.15 and recognition of additional transportation expense in 2017 by virtue of taking our production in-kind in the Haynesville Shale Trend and paying related transportation costs$0.23 per Mcfe for that production, offset by a $1.3 million decrease in production and other taxes as discussed further below. Three Months Ended September 30, Nine Months Ended September 30, Successor Predecessor Successor Predecessor Operating Expenses (in thousands) 2017 2016 Variance 2017 2016 Variance Lease operating expenses $ 2,184 $ 2,009 $ 175 9 % $ 9,445 $ 6,302 $ 3,143 50 % Production and other taxes (15 ) 944 (959 ) (102 )% 1,068 2,360 (1,292 ) (55 )% Operating Expenses per Mcfe Lease operating expenses $ 0.60 $ 1.05 $ (0.45 ) (43 )% $ 1.02 $ 0.97 $ 0.05 5 % Production and other taxes — 0.49 (0.49 ) (100 )% 0.12 0.36 (0.24 ) (67 )% Lease Operating ExpenseLease operating expense increased $0.2 million and $3.1 million during the three and nine months ended September 30, 2017,2021, respectively, compared to the same periods in 2016.2020. The year over year comparisons for operating expenses are discussed further below. $ 3,277 $ 2,831 $ 446 16 % $ 10,429 $ 9,384 $ 1,045 11 % 1,291 591 700 118 % 2,756 2,361 395 17 % 4,811 4,336 475 11 % 13,457 14,586 (1,129 ) (8 )% $ 0.21 $ 0.25 $ (0.04 ) (16 )% $ 0.26 $ 0.26 $ - 0 % $ 0.08 $ 0.05 $ 0.03 60 % $ 0.07 $ 0.06 $ 0.01 17 % $ 0.32 $ 0.38 $ (0.06 ) (16 )% $ 0.34 $ 0.41 $ (0.07 ) (17 )% substantiallyprimarily attributed to an increase in production volumes and the number of producing wells in 2021 versus 2020 as well as additional workover expense for the nine months ended September 30, 2017, in addition to increased costs due to increased production2021. Per unit LOE was $0.21 per Mcfe and $0.26 per Mcfe for both the three and nine months ended September 30, 2017. We incurred $3.12021, respectively, of which $0.02 per Mcfe was attributed to the $0.3 million in workover cost forexpense incurred in the three months ended September 30, 2021, and $0.04 per Mcfe was attributed to the $1.8 million in workover expense incurred in the nine months ended September 30, 2017 and only $0.8 million for the nine months ended September 30, 2016, as we curtailed such expenditures while in bankruptcy.20172021, respectively, and ad valorem taxes were $0.1$0.2 million and $0.9$0.7 million respectively. Ad valorem taxes for the three months ended September 30, 2017 was a credit of $0.1 million as a result of the receipt of refunds. Ad valorem taxes for the nine months ended September 30, 2017 was $0.2 million. During the three and nine months ended September 30, 2016, production and other2021, respectively.included severance tax of $0.3 million and $0.8 million, respectively and ad valorem tax ofincreased $0.7 million and $1.6$0.6 million respectively.Severance taxes remained relatively flat for both the three and nine months ended September 30, 2017, reflecting decreased oil2021, respectively, compared to the same periods in 2020. The increase is primarily due to higher production volumes directlyupon which the volumetric tax is based as wells have begun to incur severance tax in Louisiana after the exemption ended, partially offset by a lower severance tax increases due to the expiration of the exemption on certain wellsrate in Mississippi and Louisiana. The State of Mississippi has enacted an exemption from the existing 6.0% severance tax for horizontal wells drilled after July 1, 2013 with production commencing before July 1, 2018, which is partially offset by a 1.3% local severance tax on such wells. The exemption is applicable until the earlier of (i) 30 months from the date of first sale of production or (ii) payout of the well. The State of Louisiana has also enacted an exemption from the existing 12.5% severance tax on oil and from the $0.098 per Mcf (through June 30, 2017) and $0.11$0.125 per Mcf (from July 1, 20172019 through June 30, 2018)2020), $0.0934 per Mcf (from July 1, 2020 to June 30, 2021) and $0.091 per Mcf (from July 1, 2021 to June 30, 2022) severance tax on natural gas for horizontal wells with production commencing after July 31, 1994. The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) payout of the well. The net revenuesAll of our recently drilled, operated Haynesville Shale Trend wells in Northwest Louisiana are benefiting from our wells drilled in our TMS acreage in Southwestern Mississippi and Southeast Louisiana have been favorably impacted by these exemptions.The decrease in adthis exemption upon initial production. between periods reflects refunds or tax credits received ofremained flat and decreased $0.2 million and $0.5 million for the three and nine months ended September 30, 2017,2021, respectively, as well ascompared to the reductionsame periods in the assessed values2020, due to more favorable tax calculation methodologies on certain of our properties. We also received severance tax refunds recorded in the third quarterproperties with respective taxing agencies. Three Months Ended September 30, Nine Months Ended September 30, Successor Predecessor Successor Predecessor Operating Expenses (in thousands): 2017 2016 2017 2016 Transportation and processing $ 1,624 $ 360 $ 4,668 $ 1,239 Exploration — 78 — 564 Depreciation, depletion and amortization 3,516 2,312 8,893 7,998 General and administrative 3,749 3,790 11,984 13,874 Operating Expenses per Mcfe Transportation and processing $ 0.44 $ 0.19 $ 0.50 $ 0.19 Exploration $ — $ 0.04 $ — $ 0.09 Depreciation, depletion and amortization $ 0.96 $ 1.21 $ 0.96 $ 1.24 General and administrative $ 1.02 $ 1.98 $ 1.29 $ 2.15 2017 includes $1.02021 increased $0.5 million and $3.0decreased $1.1 million, respectively, compared to the same periods in 2020. The increase in transportation and processing expense for the three months ended September 30, 2021 was primarily due to increased production from our Haynesville Shale Trend wells, partially offset by more favorable rates contracted with third parties. The decrease in transportation and processing expense for the nine months ended September 30, 2021 was primarily due to the more favorable rates contracted with third parties despite an increase in production volumes. Additionally, the mix of operated versus non-operated volumes impacts our transportation fees incurred onand processing expense as our operated natural gas volumes, thatparticularly from our recent operated wells brought online, generally carry less transportation cost than those from wells we take in-kinddo not operate. $ 13,389 $ 10,341 $ 3,048 29 % $ 35,671 $ 35,484 $ 187 1 % 4,329 3,891 438 11 % 11,302 13,327 (2,025 ) (15 )% - 3,040 (3,040 ) (100 )% - 17,170 (17,170 ) (100 )% 4 (11 ) 15 136 % (183 ) (13 ) (170 ) (1308 )% $ 0.88 $ 0.90 $ (0.02 ) (2 )% $ 0.88 $ 0.97 $ (0.09 ) (9 )% $ 0.28 $ 0.34 $ (0.06 ) (18 )% $ 0.28 $ 0.36 $ (0.08 ) (22 )% $ - $ 0.26 $ (0.26 ) (100 )% $ - $ 0.47 $ (0.47 ) (100 )% $ - $ - $ - — % $ - $ - $ - — % pay directlyAmortization (“DD&A”)transportersame periods in 2020. The increase for the three months ended September 30, 2021 was attributed to increased production volumes, partially offset by a lower per unit cost discussed below. The increase in DD&A expense for the nine months ended September, 2021 compared to the prior year period was attributed primarily to increased production volumes partially offset by a lower per unit cost based on non-operated Haynesville Shale Trendthe year-end 2020 and mid-year 2021 reserve reports, largely as a result of recognizing impairment expense of $36.1 million in the prior year.volumes, effective with August 2016 production. properties compared to the impairment expense of $3.0 million and $17.2 million recorded for the three and nine months ended September 30, 2020, respectively.transportationCompany recorded $4.3 million and processing$11.3 million in G&A expense for the three and nine months ended September 30, 2016 did not include these take in-kind transportation fees as gathering fees2021, respectively, which included non-cash expenses for that period were netted againstshare-based compensation of $0.5 million and $1.2 million, respectively. G&A expense increased for the Company's realized natural gas price.ExplorationThe Successor Company adopted the Full Cost Method of Accounting as of the Effective Date, resulting in Exploration Cost being capitalizedthree months ended September 30, 2021 by $0.4 million primarily due to higher bonus accruals due to better performance measures than target related to the full cost pool rather than expensed.Depreciation, Depletionannual and Amortization (“DD&A”)DD&Along-term incentive plans, partially offset by lower rent expense inassociated with a renegotiated lease for office space. For the 2017 Successor Period is calculated on the Full Cost Method of Accounting adopted upon our emergence from bankruptcy based upon asset carrying values as of December 31, 2016.DD&A expense in the 2016 Predecessor Period is calculated on the Successful Efforts Method of Accounting.General and Administrative (“G&A”)The Successor Company recorded $3.7 million and $12.0 million in G&A expense in the three and nine months ended September 30, 2017, respectively, which includes non-cash2021, G&A expense decreased by $2.0 million compared to the same period in 2020 primarily due to reduced employee expenses of (i) $1.0including salaries and stock compensation expense as well as decreased rent expense, partially offset by a higher bonus accrual related to a the cash-based long-term incentive plan due to better performance measures than target for the current year.$3.0 million, respectively, for share based compensation, (ii) $0.7 million and $2.1 million, respectively, in performance bonuses to be compensated in common stock and (iii) $0.1 million and $0.4 million, respectively, of office rent amortization.The Predecessor Company recorded $3.8 million and $13.9$13.3 million in G&A expense in the three and nine months ended September 30, 2016, respectively, which includes $1.1 million and $3.3 million of share based compensation, respectively.Other Income (Expense) Three Months Ended September 30, Nine Months Ended September 30, Other income (expense) (in thousands): Successor Predecessor Successor Predecessor 2017 2016 2017 2016 Interest expense $ (2,529 ) $ (1,251 ) $ (7,068 ) $ (11,190 ) Interest income and other 1,250 — 1,271 58 Gain (loss) on commodity derivatives not designated as hedges (313 ) — 193 30 Average funded borrowings adjusted for debt discount and accretion $ 52,614 $ 445,545 $ 50,543 $ 581,913 Average funded borrowings $ 61,628 $ 439,053 $ 60,190 $ 584,044 Interest ExpenseThe Successor Company's interest expense for the three and nine months ended September 30, 2017 reflects cash interest2020, respectively, which included non-cash expenses of $0.4$1.0 million and $0.9$3.5 million, respectively, for share-based compensation. $ (2,232 ) $ (1,733 ) $ 499 29 % $ (6,255 ) $ (5,410 ) $ 845 16 % - 5 (5 ) (100 )% - 147 (147 ) (100 )% (77,369 ) (11,079 ) (66,290 ) (598 )% (103,111 ) (3,629 ) (99,482 ) (2741 )% - - - — % (935 ) - (935 ) (100 )% $ 124,403 $ 107,268 $ 17,135 16 % $ 119,068 $ 104,925 $ 14,143 13 % $ 127,168 $ 110,505 $ 16,663 15 % $ 121,934 $ 108,323 $ 13,611 13 % $20.02019 Senior Credit Facility (as defined below) and $1.2 million senior secured term loan credit facility (the “Exit Credit Facility”) and non-cash interest of $2.1 million and $6.2 million, respectively, incurred on the Company's 13.50% Convertible Second Lien Senior Secured Notes due 20192023 (the “Convertible“2023 Second Lien Notes”), which includes. Interest expense for the nine months ended September 30, 2021 included $3.0 million incurred on the 2019 Senior Credit Facility, $2.7 million incurred on the Company's 2023 Second Lien Notes and $0.5 million incurred on the Company's 13.50% Convertible Second Lien Senior Secured Notes due 2022 (the “2021/2022 Second Lien Notes”) until exchanged on March 9, 2021. The interest on the 2021/2022 Second Lien Notes and 2023 Second Lien Notes was all non-cash consisting of paid in-kind interest of $1.1 million, amortization of debt discount of $0.1 million and amortization of debt discount.Predecessor Company's interest on the 2019 Senior Credit Facility included $0.9 million and $2.6 million of interest payable in cash for the three and nine months ended September 30, 2021, respectively, and $0.1 million and $0.4 million of non-cash amortization of debt issuance costs for the three and nine months ended September 30, 2021, respectively.2016 reflects2020 reflected interest payable in cash of $0.6$1.0 million and $8.5$3.1 million, respectively, incurred on the 2019 Senior Credit Facility and non-cash interest of $0.6$0.7 million and $2.7$2.3 million, respectively. The Predecessor Company did not recordrespectively, incurred primarily on the 2021/2022 Second Lien Notes, which included $0.5 million of paid in-kind interest expense subsequent to the Petition Date on anyand $0.2 million of its outstanding second lienamortization of debt discount and senior notes. All the accrued interest on such notes was never paid as the underlying debt was canceled in bankruptcy.Interest Income and OtherWe recorded a credit of $1.3 million in interest income and otherissuance costs for the three months ended September 30, 2020, and $1.4 million of paid in-kind interest and $0.9 million of amortization of debt discount and debt issuance costs for the nine months ended September 30, 2017 primarily related to the receipt2020.Gain (loss)2017 is2021 was comprised of an unrealizeda mark-to-market loss of $0.5$64.9 million, representing the change of fair value on our open natural gas derivative contracts, and a $12.5 million loss on net cash settlements of natural gas derivative contracts. The loss on commodity derivatives not designated as hedges of $103.1 million for the nine months ended September 30, 2021 was comprised of a mark-to-market loss of $88.6 million, representing the change of fair value on our open natural gas derivative contracts, and a $14.5 million loss on net cash settlements of natural gas and oil derivative contracts. Volatility in the commodity futures market is quite high and since we do not apply hedge accounting on our derivative contracts there can be large swings in our reported gain or losses between periods. These commodity derivative losses were recorded as a result of the significant increase in natural gas strip prices as of September 30, 2021 compared to our hedged prices.a $0.2$14.9 million net gain on cash settlement. Gain (loss) on commodity derivatives not designated as hedges for the nine months ended September 30, 2017 is comprisedsettlement of an unrealized loss of $0.1 million, representing the change of the fair value of our natural gas and oil derivative contracts, offset by as a $0.3 million gain on cash settlement.RestructuringAs a result of our efforts to restructure the Company outside of bankruptcy and the preliminary preparation involved in filing the Chapter 11 Cases during the first three quarters of 2016, we incurred significant professional fees and other costs. Restructuring costs incurred during the three and nine months ending September 30, 2016 totaled zero and $5.1 million, respectively. No restructuring costs have been incurred during 2017.Reorganization gain (loss), netWe anticipate that we will continue to incur professional fees and costs until the bankruptcy case is final. We continue to work on settling bankruptcy claims. We believe that the estimated liability we have established for these costs is sufficient to cover such cost.2017.2021 and 2020. We recordedmaintained a valuation allowance at December 31, 2016,September 30, 2021, which resulted in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature our deferred tax assets were unrecoverable. ConsideringCompany’s taxable income forecasts, our assessmentnine months ended September 30, 2021 was recorded as a result of the realizationCompany exchanging the 2021/2022 Second Lien Notes for the 2023 Second Lien Notes on March 9, 2021. The $0.9 million loss was comprised of our deferred tax assets has not changed,the remaining unamortized debt discount of $0.8 million and we continue to maintain a full valuation allowance for our net deferred tax assets asremaining unamortized debt issuance costs of September 30, 2017.EBITDA/EBITDAXEBITDA/EBITDAXEBITDA is a supplemental non-United States Generally Accepted Accounting Principle (“US GAAP”) financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Predecessor definedCompany defines Adjusted EBITDAXEBITDA as earnings before interest expense, income and similar tax, DD&A, exploration expense, share basedshare-based compensation expense and impairment of oil and natural gas properties. The Successor calculates Adjusted EBITDA in the same way, but EBITDA reflects the absence of exploration expense in the Full Cost Method of Accounting used by the Successor.properties (if any). In calculating Adjusted EBITDA/EBITDAX,EBITDA, mark-to-market gains/losses on commodity derivatives not designated as hedges and net cash received or paid in settlement of derivative instruments are also excluded. Other excluded items include adjustments resulting from the accounting for operating leases under Accounting Standards Codification (“ASC”) Topic 842 in accordance with our 2019 Senior Credit Facility, interest income gain on sale of assets, restructuring, reorganization and other expense.any extraordinary non-cash gains or losses. Adjusted EBITDA/EBITDAXEBITDA is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDA/EBITDAXEBITDA should not be considered an alternative to net income (loss), as defined by US GAAP.the non-US GAAP measure of Adjusted EBITDA/EBITDAX to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP: Three Months Ended September 30, Nine Months Ended September 30, (In thousands) Successor Predecessor Successor Predecessor 2017 2016 2017 2016 Net loss (US GAAP) $ 720 $ (13,986 ) $ (6,219 ) $ (37,948 ) Exploration expense — 78 — 564 Interest expense 2,529 1,251 7,068 11,190 Depreciation, depletion and amortization 3,516 2,312 8,893 7,998 Share based compensation expense 1,715 1,136 5,093 3,307 Loss (gain) on commodity derivatives not designated as hedges 313 — (193 ) (30 ) Net cash received in settlement of derivative instruments 166 — 313 — Other items (1) (1,358 ) 10,645 (1,574 ) 14,435 Adjusted EBITDA/EBITDAX $ 7,601 $ 1,436 $ 13,381 $ (484 ) $ (47,969 ) $ (16,360 ) $ (55,025 ) $ (36,265 ) 2,232 1,733 6,255 5,410 13,389 10,341 35,671 35,484 - 3,040 - 17,170 517 1,035 1,207 3,564 64,871 12,676 88,596 18,534 - - 935 - 177 266 246 684 $ 33,217 $ 12,731 $ 77,885 $ 44,581 (1)includeincluded $0.2 million, $0.3 million, $0.2 million and $0.8 million, respectively, from the impact of accounting for operating leases under ASC Topic 842 as well as interest income restructuring, reorganizationfor the three and other non-recurring incomenine months ended September 30, 2021 and expense.2020, respectively. Our computations20172021 were cash from operating activities, cash on hand and cash from operating activities.borrowings under our 2019 Senior Credit Facility (as defined below). We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 20172021 through a combination of cash on hand, cash from operating activities and borrowing under our 2017 Senior Credit Facility (as defined below),revolving credit facility, although we may from time to time consider the funding alternatives described below.October 17, 2017, weMay 14, 2019, the Company entered into thea Second Amended and Restated Senior Secured Revolving Credit Facility (“Agreement (the “2019 Credit Agreement”) withamong the Company, the Subsidiary, as borrower JPMorgan Chase(in such capacity, the “Borrower”), Truist Bank, N.A. as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2017“2019 Senior Credit Facility”). Total lender commitments under the 2017 Senior Credit Facility are $250 million. 20172019 Senior Credit Facility matures on a) October 17, 2021the earlier of (a) May 14, 2024 or b)(b) December 2, 2022, if the Convertible2023 Second Lien Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by December 2, 2022, which is the date that is 180 days prior to the May 31, 2023 “Maturity Date” of the 2023 Second Lien Notes. The 2019 Senior Credit Facility provides for a maximum credit amount of $500 million subject to a borrowing base limitation, which was $120.0 million as of September 30, 2021 and was increased to $150.0 million during the Fall 2021 borrowing base redetermination. The borrowing base is redetermined in March and September of each calendar year, and is subject to additional adjustments from time to time, including, without limitation, for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. Under the Fifth Amendment to 2019 September 30, 2019. RevolvingCredit Agreement entered into on November 5, 2021, the Company is permitted to make restricted payments under the 2019 Credit Agreement so long as (i) no borrowing base deficiency, default or event of default exists or would result therefrom, (ii) after giving pro forma effect to such restricted payment, availability is no less than 20% of the aggregate amount of the available commitments under the 2019 Credit Agreement and (iii) after giving pro forma effect to such restricted payment, the ratio of net funded debt of the Company to EBITDAX shall not be greater than 1.50 to 1.00. The Fifth Amendment to 2019 Credit Agreement also permits the Company to make redemptions of the Second Lien Debt (as defined in the 2019 Credit Agreement) and payments of interest on the 2023 Second Lien Notes so long as each such redemption and interest payment would be permitted as a restricted payment. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to $10 million, which reduce the amount of available borrowings under the 2017borrowing base in the amount of such issued and outstanding letters of credit.FacilityFacility. In connection with the purchase and exchange agreement, we recorded a $0.9 million loss on early extinguishment of debt related to the remaining unamortized debt discount and debt issuance costs from the 2021/2022 Second Lien Notes.limitedscheduled to mature on May 31, 2023. The 2023 Second Lien Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the 2023 Second Lien Notes by increasing the principal amount of the outstanding 2023 Second Lien Notes.periodic redeterminations,certain adjustments as described in the 2023 Second Lien Notes Indenture. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the borrowing base. The initial borrowing base2023 Second Lien Notes Indenture, (2) cash or (3) a combination of shares of its common stock and cash; however, the Company’s ability to redeem the 2023 Second Lien Notes with cash is $40 million. Pursuantsubject to the terms of the 2017 Senior2019 Credit Facility, borrowing base redeterminations will be on a semi-annual basis on or about March 1st and September 1st of each calendar year, commencing on or about March 1, 2018. JPMorgan Chase Bank, N.A. is the lead lender and administrative agent under the Senior Credit Facility.20172021 with $5.5 million cash of $31.7 million, which includes $0.6on hand and $90.4 million of restricted cash heldoutstanding borrowings with $29.6 million of availability under the 2019 Senior Credit Facility borrowing base of $120.0 million in effect as collateral for the issuance of a letter of credit in connection with a natural gas gathering agreement. As of September 30, 2017, we had outstanding borrowings under the Exit Credit Facility of $16.7 million. The outstanding Exit Credit Facility amount was paid off upon entering into the 2017 Senior Credit Facility on October 17, 2017 with a $16.7 million balance due under the 2017 Senior Credit Facility.Our total capital expenditure budget for 2017 is expected to range between $40 million to $50 million. 2021.2017capital on drilling effortsand development of our Haynesville Shale Trend natural gas properties in North Louisiana, and we currently contemplate drilling and developing 22 gross (10.4 net) wells utilizing improved completion techniques during 2021.Haynesville Shale Trend.future and raise capital as needed.sale of non-core assets;joint venture partnerships• joint ventures in our TMS, Eagle Ford Shale Trend, and/or core Haynesville Shale Trend acreage; andissuance of debt or equity securities.We have supported our TMS and/or Haynesville Shale Trend acreage;• sale of non-core assets; and • issuance of equity securities if favorable conditions exist. withand protect against a sharp drop in commodity prices, we enter into strategic derivative contracts that covered approximately 47% of our natural gas sales volumes for the first nine months of 2017. We had no oil derivative contracts for the first nine months of 2017. For additional information on our derivative instruments see positions as reflected in Note 7—8—“Commodity Derivative Activities” and Note 11—“Subsequent Events” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.presentssummarizes our comparative cash flow summaryflows for the periods reportedindicated (in thousands): Three Months Ended September 30, Nine Months Ended September 30, Successor Predecessor Successor Predecessor 2017 2016 2017 2016 Cash flow statement information: Net cash: Provided by (used in) operating activities $ 285 $ (1,838 ) $ 15,813 $ (14,152 ) Used in investing activities (3,716 ) (1,735 ) (21,235 ) (3,206 ) Provided by (used in) financing activities 106 — (342 ) 12,075 Decrease in cash and cash equivalents $ (3,325 ) $ (3,573 ) $ (5,764 ) $ (5,283 ) $ 29,935 $ 13,512 $ 66,604 $ 44,592 (25,045 ) (14,816 ) (71,065 ) (48,012 ) (161 ) 991 8,612 3,219 $ 4,729 $ (313 ) $ 4,151 $ (201 ) both the three and nine months months ended September 30, 2017.2021 and 2020. Changes in working capital and net cash settlements related to our derivative contracts also impact cash flows. Net cash provided by operating activities for the three months ended September 30, 20172021 was $0.3$29.9 million including operating cash flows before negative working capital changes of $8.3$32.3 million andincluding net cash payments of $12.5 million in settlement of derivative contracts. Net cash provided by operating activities for the nine months ended September 30, 20172021 was $15.8$66.6 million including operating cash flows before negative working capital changes of $13.6 million. We recorded capital expenditures of approximately $5.4 million and $25.8 million for the three and nine months ended September 30, 2017, respectively. Net cash used in investing activities, which represents our cash expended for capital projects, was approximately $3.7$25.0 million and $21.2$71.1 million for the three and nine months ended September 30, 2017, respectively. The difference2021, respectively. We recorded $27.9 million in capital expenditures and net cash used in investing activities for the nine months ended September 30, 2017 was attributed to $3.3 million accrued at September 30, 2017, $1.0 million of utilized inventory, $0.5 million proceeds received from the sale of assets, and the utilization of $0.4 million of cash advanced in 2016, offset by the $0.6 million accrued at December 31, 2016 and paid in 2017. The full year 2017 capital expenditures include $2.3 million of capitalized internal costs directly related to our acquisition of leasehold, drilling and completion activities. Capital expenditures during the three months ended September 30, 2017 were substantially all spent2021. The difference in capital expenditures and cash expended on drillingcapital projects for the three months ended September 30, 2021 was primarily attributed to a net capital accrual increase of $2.3 million and completions costs, whilecapitalization of $0.4 million of asset retirement and non-cash internal costs. We recorded $77.0 million in capital expenditures during the nine months ended September 30, 2021. The difference in capital expenditures and cash expended on capital projects for the nine months ended September 30, 2017 were comprised2021 was attributed to a net capital accrual increase of $25.6$4.6 million associated with drilling and, completions costsutilization of $0.6 million in cash calls and $0.2the capitalization of $0.7 million for miscellaneous expenditures.Financing activities: Net cash used in financing activities forof asset retirement and non-cash internal costs. During the nine months ended September 30, 2017 consisted2021, we conducted drilling and completion operations on 24 gross (10.5 net) wells bringing 16 gross (8.1 net) wells on production with 8 gross (2.3 net) wells remaining in the drilling and completion process at September 30, 2021.$0.3 million in registration andthe 2023 Second Lien Notes, offset by debt issuance costs associatedpaid in connection with various securities issued since our emergence from bankruptcy or to be issuedissuance of the 2023 Second Lien Notes and cash paid for treasury shares in the future. September 30, 2017 December 31, 2016 Principal Carrying
Amount Principal Carrying
AmountExit Credit Facility $ 16,651 $ 16,651 $ 16,651 $ 16,651 13.50% Convertible Second Lien Senior Secured Notes due 2019 (1) 45,480 36,688 41,170 30,554 Total debt $ 62,131 $ 53,339 $ 57,821 $ 47,205 $ 90,400 $ 90,400 $ 96,400 $ 96,400 - - 14,811 13,759 32,535 31,349 - - $ 122,935 $ 121,749 $ 111,211 $ 110,159 August 30, 2019.May 31, 2023. The principal includes $5.5 million and $1.2$2.3 million of paid in-kind interest atas of September 30, 2017 and December 31, 2016, respectively.2021. The carrying value includes $8.8 million and $10.6$0.9 million of unamortized debt discount atand $0.3 million of unamortized issuance cost as of September 30, 2017 and December 31, 2016, respectively.3—4—“Debt” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.2016,2020 includes a discussion of our critical accounting policies, and there have been no material changes to such policies during the threenine months ended September 30, 2017.2021.Our primary market risksattributablenot required to fluctuations in commodity prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. Our risk-management policies provide for the useinformation required by this Item 3.For information regarding our accounting policies and additional information related to our derivative and financial instruments, see Note 1—“Description of Business and Significant Accounting Policies”, Note 3—“Debt”and Note 7—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.Commodity Price RiskOur most significant market risk relates to fluctuations in crude oil and natural gas prices. Management expects the prices of these commodities to remain volatile and unpredictable. As these prices decline or rise significantly, revenues and cash flow will also decline or rise significantly. In addition, a non-cash write-down of our oil and natural gas properties may be required if future commodity prices experience a sustained and significant decline. We entered into natural gas derivative instruments during the nine months ended September 30, 2017 in order to reduce the price risk associated with production in 2017 of approximately 18,000 MMBtu per day. We did not enter into derivatives instruments for trading purposes. Utilizing actual derivative contractual volumes, a hypothetical increase of 10% in the underlying commodity prices would have increased the derivative liability position by $0.4 million as of September 30, 2017. Likewise, a hypothetical decrease of 10% in the underlying commodity prices would have increased the fair market value of derivatives by $0.4 million to a net derivative asset position as of September 30, 2017. Furthermore, a gain or loss would have been substantially offset by an increase or decrease, respectively, in the actual sales value of production covered by the derivative instruments.Adoption of Comprehensive Financial ReformThe adoption of comprehensive financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under theis recorded, processed, summarizedRules 13a-15 and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us is recorded, processed, summarized and reported to our management including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.As required by Rule 13a-15(b) under the Exchange Act,15d-15, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rulesRules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2021. Our disclosure controls and procedures are designed to provide reasonable assurance that the endinformation required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the period covered by this report. OurSEC. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer based upon their evaluation as of September 30, 2017, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.ourany current legal proceedings is set forth in Part I, Item 1 under 1—“Description of Business and Significant Accounting Policies” and Note 89—“Commitments and Contingencies” to the Notes to Consolidated Financial Statements and Part I, Item II under “—Emergence from Bankruptcy” in this Quarterly Report on Form 10-Q.2017,2021, we did not have any material outstanding and pending litigation.2016,2020, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our business, financial condition or future results.3.110.110.1*31.1*22Goodrich Petroleum Company L.L.C. - Organized in the State of Louisiana. 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) Filed herewith**Date:20172021 Date:20172021Robert T. BarkerKristen McWattersRobert T. BarkerController, Chief AccountingFinancial Officer, and Chief FinancialAccounting Officer32