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
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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 Registrant (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
☒ No ☐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
☒ No ☐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 Registrant had 10,538,51312,152,318 shares of common stock outstanding on November 8, 2017.
TABLE OF CONTENTS Page PART I ITEM 1 7 ITEM 2 22 ITEM 3 30 ITEM 4 31 PART II 32 ITEM 1 32 ITEM 1A 32 ITEM 6 33Page 6 ITEM 1232 ITEM 1A
Item 1—Financial Statements GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (In thousands, except share amounts) (Unaudited) March 31, 2019 December 31, 2018 ASSETS CURRENT ASSETS: Total current assets PROPERTY AND EQUIPMENT: Net property and equipment TOTAL ASSETS LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES: Total current liabilities Total liabilities Commitments and contingencies (See Note 9) STOCKHOLDERS’ EQUITY: Total stockholders’ equity TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts) (Unaudited) Three Months Ended March 31, Three Months Ended March 31, 2019 2018 REVENUES: OPERATING EXPENSES: Operating income (loss) OTHER INCOME (EXPENSE): Income (loss) before income taxes Income tax benefit Net income (loss) PER COMMON SHARE See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited) Three Months Ended March 31, Three Months Ended March 31, 2019 2018 CASH FLOWS FROM OPERATING ACTIVITIES: Adjustments to reconcile net loss to net cash provided by operating activities: Change in assets and liabilities: Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Net cash used in investing activities CASH FLOWS FROM FINANCING ACTIVITIES: Net cash provided by (used in) financing activities 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: See accompanying notes to consolidated financial statements. CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT) (In thousands) (Unaudited) Preferred Stock Common Stock Additional Paid-in Treasury Stock Retained Total Stockholders’ Shares Value Shares Value Capital Shares Value Deficit Equity Balance at December 31, 2017 Net loss Share-based compensation Restricted stock vesting & other Convertible Second Lien Notes warrant exercises Issuance cost Balance at March 31, 2018 Balance at December 31, 2018 Net income Share-based compensation Treasury stock activity Balance at March 31, 2019 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,” 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. Basis of Presentation The consolidated financial statements of the Company included in this Quarterly Report on Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission Principles of Consolidation Use of Estimates Cash and Cash Equivalents Accounts Payable (In thousands) March 31, 2019 December 31, 2018 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 March 31, 2019 and December 31, 2018: (In thousands) March 31, 2019 December 31, 2018 Total Accrued liabilities Inventory Property and Equipment Under the Full Cost Method, we capitalize all costs associated with acquisitions, exploration, development and estimated abandonment costs. 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 both the three Under the Full Cost Method, we amortize our investment in oil and natural gas properties through DD&A expense using the units of production (the “UOP”) method. An amortization rate is calculated based on total proved reserves converted to equivalent thousand cubic feet of natural gas (“Mcfe”) as the denominator and the net book value of evaluated oil and 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' production also converted to Mcfe to arrive at the periods' DD&A expense. 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 There were no Full Cost Ceiling Test write-downs for the three 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 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 As of 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, 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 likely-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 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 Convertible Second Lien Notes as a contra balance to long term debt, net in our Consolidated Balance Sheets, which is amortized straight-line over the GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS New Accounting Pronouncements On August 28, The Company adopted ASU 2016-02, Leases (Topic 842) along with other corresponding ASU's during the quarter using a modified retrospective approach. See Note 10 for further details regarding the adoption of the new lease guidance. NOTE 2—Revenue Recognition On January 1, 2018, we 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 The following table presents our revenues disaggregated by revenue source and by operated and non-operated properties for the Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 (In thousands) NGL Revenue Total Oil and Natural Gas Revenues NGL Revenue Total Oil and Natural Gas Revenues Total oil and natural gas revenues GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE The reconciliation of the beginning and ending asset retirement obligation for the Three Months Ended March 31, 2019 Beginning balance as of December 31, 2018 Ending balance as of March 31, 2019 NOTE Debt consisted of the following balances as of Principal Carrying Amount Principal Carrying Amount Total debt (1) The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The following table summarizes the total interest expense for the Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 Interest Expense Effective Interest Expense Effective 2017 Senior Credit Facility Convertible Second Lien Notes (1) Total interest expense (1) Interest expense for the three months ended 2017 Senior Credit Facility On October 17, 2017, the Company entered into the Amended and Restated Senior Secured Revolving Credit Agreement All amounts outstanding under the 2017 Senior Credit Facility shall bear interest at a rate per annum equal to, at the Company's option, either (i) the alternative base rate plus an applicable margin ranging from 1.75% to 2.75%, depending on the percentage of the borrowing base that is utilized, or (ii) adjusted LIBOR plus an applicable margin ranging from 2.75% to 3.75%, depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the 2017 Senior Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the 2017 Senior Credit Facility The 2017 Senior Credit Facility also contains certain financial covenants, including (i) the maintenance of a ratio of Total Debt (as defined in the 2017 Credit Agreement) to EBITDAX not to exceed 4.00 to 1.00 as of the last day of any fiscal quarter, (ii) in accordance with the second amendment to the 2017 Credit Agreement, beginning with the quarter ended December 31, 2018, a current ratio (based on the ratio of current assets plus availability under the current borrowing base to current liabilities) not to be less than 1.00 to 1.00 and (iii) until no Convertible Second Lien Notes remain outstanding, (A) the maintenance of a ratio of Total Proved PV-10 attributable to the Company’s and Borrower’s Proved Reserves (as defined in the 2017 Credit Agreement) 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 and (B) minimum liquidity requirements. GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The obligations under the 2017 Credit Agreement are secured by a first lien security interest in substantially all of the assets of the Company and the Subsidiary. As of March 31, 2019, the Company had a borrowing base of $75.0 million, subject to an elected draw limit of $50.0 million, with $32.0 million outstanding. The Company also had $0.5 million of unamortized debt issuance costs recorded as of March 31, 2019 related to the 2017 Senior Credit Facility. As of March 31, 2019, the Company was not in compliance with all covenants within the 2017 Senior Credit Facility as the current ratio was less than 1.00 to 1.00 primarily due to the elected draw limit of $50.0 million. On April 29, 2019, the Company entered into a Limited Waiver to Credit Agreement with the Subsidiary, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, pursuant to which the lenders agreed to waive the Company’s failure to comply with the current ratio financial covenant under the 2017 Senior Credit Facility as of the last day of the fiscal quarter ending March 31, 2019. 2019 Senior Credit Facility On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, 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 “2019 Senior Credit Facility”). The 2019 Senior Credit Facility amends, restates and refinances the obligations under the 2017 Credit Agreement. The 2019 Senior Credit Facility matures (a) May 14, 2024 or (b) the date that is 180 days prior to the “Maturity Date” as defined in the New 2L Notes Indenture (as defined below) as in effect on the date of issuance of the New 2L Notes if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by, such date. The maximum credit amount under the 2019 Senior Credit Facility is currently $500 million with an initial borrowing base of $115 million. The borrowing base is scheduled to be redetermined on or about June 1, 2019 and thereafter in March and September of each calendar year, and is subject to additional adjustments from time to time, including 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. 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 borrowing base in the amount of such issued and outstanding letters of credit. All amounts outstanding under the 2019 Senior Credit Facility shall bear interest at a rate per annum equal to, at the Company’s option, either (i) the alternative base rate plus an applicable margin ranging from 1.50% to 2.50%, depending on the percentage of the borrowing base that is utilized, or (ii) adjusted LIBOR plus an applicable margin from 2.50% to 3.50%, depending on the percentage of the borrowing base that is utilized. Undrawn amounts under the 2019 Senior Credit Facility are subject to a commitment 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 2019 Senior Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. 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. 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 The foregoing description of the 2019 Credit Agreement is qualified in its entirety by reference to such 2019 Credit Agreement, a copy of which is filed herewith as Exhibit 10.1 and is incorporated herein by reference. Capitalized terms used but not otherwise defined in the foregoing description have the respective meanings ascribed to such terms in the 2019 Credit Agreement. On May 14, 2019, the Company drew down funds from the 2019 Senior Credit Facility to refinance its obligations under the 2017 Senior Credit Convertible Second Lien On 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 representing 1.9 million shares of the Company's common stock, subject to adjustments. At closing, the Purchasers were issued 10-year costless warrants The Convertible Second Lien Notes, The indenture governing the Convertible Second Lien Notes (the “Indenture”) contains certain covenants pertaining to us and our The 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 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 is amortized using the effective interest rate method based upon an original term through August 30, 2019. As of Redemption of Convertible Second Lien Notes On May 14, 2019, the Company delivered a notice of redemption to the trustee for the Convertible Second Lien Notes to call for redemption on May 29, 2019 (the “Redemption Date”) approximately $56.7 million aggregate principal amount of the outstanding Convertible Second Lien Notes, representing 100% of the aggregate principal amount of the outstanding Convertible Second Lien Notes (the “Redemption”). The Company instructed the trustee to provide notice of such redemption to the holders of the Convertible Second Lien Notes on May 14, 2019 in accordance with the terms of the Indenture. The Convertible Second Lien Notes will be redeemed at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest from April 15, 2019 to, but not including, the Redemption Date. The Redemption is expected to be funded with proceeds from draws on the 2019 Senior Credit Facility. New Convertible Second Lien Notes On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement (the “New 2L Notes Purchase Agreement”) with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company will issue to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering is conditioned upon the Redemption and is expected to occur contemporaneously therewith, subject to the satisfaction of other customary closing conditions. Proceeds from the sale of the New 2L Notes will be used to pay down outstanding borrowings under the 2019 Revolving Credit Facility. The New 2L Notes will be convertible into the Company’s Common Stock at the conversion rate, which is the sum of the outstanding principal amount of New 2L 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 Indenture governing the Notes (the “New 2L 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 New 2L Notes Indenture, (2) cash or (3) a combination of shares of its Common Stock and cash, however the Company's ability to redeem the New 2L Notes with cash is subject to the terms of the 2019 Credit Agreement. The New 2L Notes will be issued and sold to the New 2L Notes Purchasers pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereunder. The New 2L Notes Purchasers intend to resell the New 2L Notes only to qualified institutional buyers in accordance with Rule 144A under the Securities Act and to certain persons outside the United States in accordance with Regulation S under the Securities Act. The New 2L Notes will not be registered under the Securities Act or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state laws. The New 2L Notes Purchase Agreement contains customary representations, warranties and agreements by the Company and the Subsidiary and obligations of the parties. The foregoing description of the New 2L Notes Purchase Agreement is qualified in its entirety by reference to such New 2L Notes Purchase Agreement, a copy of which is filed herewith as Exhibit 10.2 and is incorporated herein by reference. GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE During the three months ended March 31, 2019, no 10 year costless warrants associated with the Convertible Second Lien Notes were exercised. As of March 31, 2019, 150,000 of such warrants remain un-exercised. The Company also did not have a material vesting of its share-based compensation units during the three months ended March 31, 2019. During the three months ended NOTE Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted net income (loss) per common share for the three Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 (Amounts in thousands, except per share data) Basic net income (loss) per common share: Net income (loss) applicable to common stock Weighted average shares of common stock outstanding Basic net income (loss) per common share Diluted net income (loss) per common share: Net income (loss) applicable to common stock Weighted average shares of common stock outstanding Common shares issuable upon conversion of the Convertible Second Lien Notes associated warrants Common shares issuable upon conversion of warrants of unsecured claim holders Common shares issuable on assumed conversion of restricted stock ** Diluted weighted average shares of common stock outstanding Diluted net income (loss) per common share (1) (2) (3) (1) Common shares issuable on assumed conversion of share-based compensation were not included in the computation of diluted net loss per common share since their inclusion would have been anti-dilutive. ** (2) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted net income (loss) per common share since their inclusion would have been anti-dilutive. (3) Common shares issuable upon conversion of the warrants associated with the Convertible Second Lien Notes and unsecured claim holders were not included in the computation of diluted net income (loss) per common share since their inclusion would have been anti-dilutive. ** - Common shares issuable on assumed conversion 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 250% of the initial performance units granted. GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS NOTE We As of 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 Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 Oil and Natural Gas Derivatives (in thousands) Total 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 Contract Type Daily Volume Total Volume Weighted Average Fixed Price Fair Value at Oil swaps (Bbls) 2019 Total oil Natural Gas swaps (MMBtu) 2020 (through March 31, 2020) 2019 Total natural gas Total oil and natural gas During the Contract Type Daily Volume Fixed Price Contract Start Date Contract Termination The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each Level as of Description Level 1 Level 2 Level 3 Total Total We enter into oil and natural gas derivative contracts under which we have netting arrangements with each March 31, 2019 December 31, 2018 Fair Value of Oil and Natural Gas Derivatives Gross Amount As Gross Amount As (in thousands) Amount Offset Presented Amount Offset Presented 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 NOTE 10—Leases We adopted ASU 2016-02, Leases, during the quarter ended March 31, 2019, and we elected the transition relief package of practical expedients. 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 (in thousands) March 31, 2019 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 March 31, 2019: (in thousands) March 31, 2019 Consolidated Balance Sheets Classification Lease asset, gross Furniture, fixtures and equipment and other capital assets 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 liability maturities as of March 31, 2019: (in thousands) March 31, 2019 2019 2020 2021 2022 2023 Thereafter Total lease payments Less imputed interest Present value of lease liabilities The future minimum obligations under operating leases in effect as of December 31, 2018 having a noncancelable term in excess of one year as determined prior to the (in thousands) December 31, 2018 2019 2020 2021 2022 2023 Thereafter Future minimum lease obligations As of March 31, 2019, our office building operating lease has a NOTE 11—Dispositions On March 1, 2019, the Company closed on the sale of working interests in certain non-core Haynesville Shale Trend oil and NOTE 12—Subsequent Events On April 29, 2019, the On May 14, 2019, the Company entered into the 2019 Credit Agreement among the Company, the Subsidiary, as borrower, SunTrust Bank, as administrative agent, and certain lenders that are party thereto, which provides the 2019 Senior Credit Facility. The 2019 Senior Credit Facility amends, restates and refinances the obligations under the On May 14, 2019, the Company delivered a notice of On May 14, 2019, the Company and the Subsidiary entered into Please see Note 4—“Debt” for a 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, 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; 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, environmental risks and liability under federal, state and foreign and local environmental laws and regulations; the creditworthiness of our financial 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 report and Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the "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 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. We strive 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. 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. 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. Such pricing factors are largely beyond our control; however, we Primary Operating Areas Haynesville Shale Trend Our relatively low risk development acreage in this trend is primarily centered in Caddo, DeSoto and Tuscaloosa Marine Shale Trend We 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 March 31, (In thousands, except for price and average daily production data) 2019 2018 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 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 March 31, Operating Expenses (in thousands) 2019 2018 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 $0.8 million during the three months ended March 31, 2019 compared to the same period in 2018. The increase in Production and Other Taxes Production and other taxes includes severance and ad valorem taxes. Severance taxes for the three Severance taxes decreased less than $0.1 million Ad valorem tax Transportation and Processing Transportation and processing expense for the three Three Months Ended March 31, Operating Expenses (in thousands): 2019 2018 Variance Depreciation, depletion and amortization General and administrative Other Operating Expenses per Mcfe Depreciation, depletion and amortization General and administrative Other Depreciation, Depletion and Amortization (“DD&A”) DD&A expense General and Administrative (“G&A”) The The Other Income (Expense) Three Months Ended March 31, Other income (expense) (in thousands): 2019 2018 Variance Interest expense Interest income and other Gain (loss) on commodity derivatives not designated as hedges Interest Expense The The Gain (Loss) on Commodity Derivatives Not Designated as Hedges The loss on commodity derivatives not designated as hedges of $1.0 million for the three months ended We Income Tax Benefit We recorded no income tax expense or benefit for the three Adjusted Adjusted The following table presents a reconciliation of the non-US GAAP measure of Adjusted Three Months Ended March 31, (In thousands) 2019 2018 Adjusted EBITDA (1) Other items include $0.3 million from the impact of accounting for operating leases under ASC 842 as well as interest income, 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 On October 17, 2017, we entered into the We exited the On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, 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 “2019 Senior Credit Facility”). The 2019 Senior Credit Facility amends, restates and refinances the obligations under the 2017 Credit Agreement. The 2019 Senior Credit Facility matures (a) May 14, 2024 or (b) the date that is 180 days prior to the “Maturity Date” as defined in the New 2L Notes Indenture (as defined below) as in effect on the issuance date of the New 2L Notes if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by, such date. The maximum credit amount under the 2019 Senior Credit Facility is currently $500 million with an initial borrowing base of $115 million. The borrowing base is scheduled to be redetermined on or about June 1, 2019 and thereafter in March and September of each calendar year, and is subject to additional adjustments from time to time, including 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. 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 borrowing base in the amount of such issued and outstanding letters of credit. On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement (the “New 2L Notes Purchase Agreement”) with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company will issue to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering is conditioned upon the Redemption and is expected to 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 Secured Credit Facility; • issuance of debt securities; We have supported our cash flows with derivative contracts that covered Cash Flows The following table Three Months Ended March 31, 2019 2018 Cash flow statement information: Net cash: Decrease in cash and cash equivalents Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers behind our cash flow from operations for Investing activities: Financing activities: Debt consisted of the following balances as of the dates indicated (in thousands): March 31, 2019 December 31, 2018 Principal Carrying Amount Principal Carrying Amount Total debt (1) The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes 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, Our primary market risks are attributable 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 use of derivative instruments to manage these risks. The types of derivative instruments we utilize include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments we utilize may vary from year to year and is governed by risk-management policies with levels of authority delegated by our Board. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and we may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its For information regarding our accounting policies and additional information related to our derivative and financial instruments, see Commodity Price Risk Our 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 have entered into natural gas and oil derivative instruments The 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, Evaluation of Disclosure Controls and Procedures We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized 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, 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 rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of 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 our current legal proceedings is set forth in Part I, Item 1 under As of 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, Item 2—Unregistered Sales of Equity Securities and Use of Proceeds On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement (the “New 2L Notes Purchase Agreement”) with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company will issue to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering is conditioned upon the Redemption and is expected to occur contemporaneously therewith, subject to the satisfaction of other customary closing conditions. Proceeds from the sale of the New 2L Notes will be used to pay down outstanding borrowings under the 2019 Revolving Credit Facility. The New 2L Notes will be convertible into the Company’s Common Stock at the conversion rate, which is the sum of the outstanding principal amount of New 2L 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 Indenture governing the Notes (the “New 2L 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 New 2L Notes Indenture, (2) cash or (3) a combination of shares of its Common Stock and cash, however the Company's ability to redeem the New 2L Notes with cash is subject to the terms of the 2019 Credit Agreement. The New 2L Notes will be issued and sold to the New 2L Notes Purchasers pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereunder. The New 2L Notes Purchasers intend to resell the New 2L Notes only to qualified institutional buyers in accordance with Rule 144A under the Securities Act and to certain persons outside the United States in accordance with Regulation S under the Securities Act. The New 2L Notes will not be registered under the Securities Act or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state laws. 3.1 3.2 31.1* 31.2* 32.1** 32.2** 101.INS* XBRL Instance Document 101.SCH* XBRL Schema Document 101.CAL* XBRL Calculation Linkbase Document 101.LAB* XBRL Labels Linkbase Document 101.PRE* XBRL Presentation Linkbase Document 101.DEF* 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: By: /S/ Walter G. Goodrich Walter G. Goodrich Chairman & Chief Executive Officer Date: By: /S/ Robert T. Barker Robert T. Barker Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer 34 Cash and cash equivalents $ - $ 4,068 Accounts receivable, trade and other, net of allowance 1,400 744 Accrued oil and natural gas revenue 12,228 14,464 Fair value of oil and natural gas derivatives 1,826 803 Inventory 584 596 Prepaid expenses and other 488 533 16,526 21,208 Unevaluated properties 231 180 Oil and natural gas properties (full cost method) 234,242 206,097 Furniture, fixtures and equipment and other capital assets 4,307 1,360 238,780 207,637 Less: Accumulated depletion, depreciation and amortization (52,695 ) (42,447 ) 186,085 165,190 Deferred tax asset 786 786 Other 543 580 $ 203,940 $ 187,764 Accounts payable $ 28,375 $ 25,734 Accrued liabilities 17,479 16,518 Fair value of oil and natural gas derivatives 742 - 46,596 42,252 Long term debt, net 84,969 76,820 Accrued abandonment cost 3,886 3,791 Fair value of oil and natural gas derivatives - 471 Other non-current liabilities 1,871 - 137,322 123,334 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 12,152,318 and 12,150,918 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively 122 122 Treasury stock (414 and zero shares, respectively) (5 ) - Additional paid in capital 76,606 74,861 Accumulated deficit (10,105 ) (10,553 ) 66,618 64,430 $ 203,940 $ 187,764 (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 Oil and natural gas revenues $ 29,146 $ 11,843 Other (6 ) (9 ) 29,140 11,834 Lease operating expense 3,335 2,566 Production and other taxes 631 640 Transportation and processing 4,701 1,312 Depreciation, depletion and amortization 10,046 3,452 General and administrative 5,310 5,196 Other 10 - 24,033 13,166 5,107 (1,332 ) Interest expense (3,657 ) (2,673 ) Interest income and other expense 6 (7 ) Loss on commodity derivatives not designated as hedges (1,008 ) (981 ) (4,659 ) (3,661 ) Reorganization items, net - (331 ) 448 (5,324 ) - - $ 448 $ (5,324 ) Net income (loss) per common share - basic $ 0.04 $ (0.47 ) Net income (loss) per common share - diluted $ 0.03 $ (0.47 ) Weighted average shares of common stock outstanding - basic 12,151 11,218 Weighted average shares of common stock outstanding - diluted 14,132 11,218 (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 Net income (loss) $ 448 $ (5,324 ) Depletion, depreciation and amortization 10,046 3,452 Right of use asset depreciation 285 - Loss on commodity derivatives not designated as hedges 1,008 981 Net cash paid in settlement of derivative instruments (1,760 ) (384 ) Share-based compensation (non-cash) 1,568 1,675 Amortization of finance cost, debt discount, paid in-kind interest and accretion 3,193 2,501 Reorganization items (non-cash) and other 12 331 Accounts receivable, trade and other, net of allowance (656 ) (1,165 ) Accrued oil and natural gas revenue 2,236 (828 ) Prepaid expenses and other 35 (108 ) Accounts payable 2,641 6,848 Accrued liabilities (1,149 ) (1,723 ) 17,907 6,256 Capital expenditures (28,254 ) (28,990 ) Proceeds from sale of assets 1,284 23,209 (26,970 ) (5,781 ) Principal payments of bank borrowings (2,000 ) (16,723 ) Proceeds from bank borrowings 7,000 - Issuance cost, net - (10 ) Purchase of treasury stock (5 ) (3 ) 4,995 (16,736 ) (4,068 ) (16,261 ) 4,068 25,992 $ - $ 9,731 Cash paid for reorganization items, net $ - $ 81 Cash paid for interest $ 505 $ 175 Increase (decrease) in non-cash capital expenditures $ 1,059 $ (8,360 ) (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 ) - $ - 10,771 $ 108 $ 68,446 - $ - $ (12,303 ) $ 56,251 - - - - - - - (5,324 ) (5,324 ) - - - - 1,776 - - - 1,776 - - 203 2 2,224 (75 ) (827 ) - 1,399 - - 589 6 (6 ) - - - - - - - - (34 ) - - - (34 ) - - 11,563 116 72,406 (75 ) (827 ) (17,627 ) 54,068 - $ - 12,151 $ 122 $ 74,861 - $ - $ (10,553 ) $ 64,430 - - - - - - - 448 448 - - - - 1,745 - - - 1,745 - - 1 - - - (5 ) - (5 ) - $ - 12,152 $ 122 $ 76,606 - $ (5 ) $ (10,105 ) $ 66,618 (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 report on Form 10-K for the year ended December 31, 2016.2018. Operating results for the three and nine months ended September 30, 2017March 31, 2019 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 to the presentation of the current period.Fresh Start Accounting—We applied fresh start accounting upon emergence from bankruptcy on October 12, 2016 (the “Effective Date”). This resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. As a result, our consolidated statements of operations subsequent to the Effective Date are not comparable to our consolidated statement of operations prior to the Effective Date. Our consolidated financial statements and related footnotes are presented in a format that illustrates the lack of comparability between amounts presented on or after the Effective Date 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.September 30, 2017March 31, 2019 and December 31, 2016:2018: Trade payables $ 12,275 $ 8,633 Revenue payables 15,535 16,665 Prepayments from partners 325 132 Miscellaneous payables 240 304 $ 28,375 $ 25,734 (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 Accrued capital expenditures $ 9,145 $ 8,086 Accrued lease operating expense 980 1,100 Accrued production and other taxes 443 338 Accrued transportation and gathering 3,300 1,888 Accrued performance bonus 976 3,420 Accrued interest 402 443 Accrued office lease 1,332 598 Accrued general and administrative expense and other 901 645 $ 17,479 $ 16,518 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. and nine months ended September 30, 2017,March 31, 2019 and 2018, we transferred $5.8$0.1 million and $18.6 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"ceiling test"“ceiling test”. If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a 12-month average pricing assumption. or nine months ended September 30, 2017.March 31, 2019 and 2018.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 (Levelslevels (levels 1, 2 and 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:Levellevel are our Exit2017 Senior Credit Facility (as defined below) 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;counter-parties; andLevellevel would be acquisitions and impairmentsour initial measurement of oil and natural gas properties, if any, and our asset retirement obligations.September 30, 2017March 31, 2019 and December 31, 2016,2018, 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 propertiesvolumes to our customers. We record revenue in whichthe 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 have an interest with other producers are recognized usingrequired to estimate the entitlements method.amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record a liability or an asset for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. AtSeptember 30, 2017As ofMarch 31, 2019and December 31, 2016,2018, theGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSoptions, collars and swapsoptions for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates.gas. 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; 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.67.stockholdersstock for each reporting period by the weighted-average numbershares of common sharesstock outstanding during the period. Diluted 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 of convertible 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 usingMarch 31, 2019, Goodrich Petroleum Company LLC, the closing pricewholly owned subsidiary of Goodrich Petroleum Corporation, was the Subsidiary Guarantor of our common stock onConvertible Second Lien Notes (as defined below).daylife of the award.2017,2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-12, Derivatives and Hedging2018-13, Fair Value Measurements (Topic 815)820): Targeted ImprovementsDisclosure Framework - Changes to Accountingthe Disclosure Requirements for Hedging Activities. This ASU is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, theFair Value Measurement. The amendments in this ASU makemodify the disclosure requirements on fair value measurements in Topic 820 including the removal, modification and addition of certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP based on the feedback received from preparers, auditors, users, and other stakeholders.disclosure requirements. For publicall entities, the amendments in this ASU are effective for annualfiscal periods beginning after December 15, 2018.2019, including interim periods therein. We do not expect this ASU toare evaluating the expected impact these amendments will have a material impact on our consolidated financial statements asstatements.currently mark to market alladopted ASU 2014-09, Revenue from Contracts with Customers, and the series of related ASU's that followed under Accounting Standards Codification (“ASC”) Topic 606 (collectively, “Topic 606”).Topic 606 did not change our pattern of timing of revenue recognition. Under Topic 606, revenue is generally recognized upon delivery of our derivative positions; however,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.evaluatingrequired to estimate the impactamount of this ASU should we chooseproduction delivered to utilize hedge accountingthe 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 future.On May 10, 2017,period they become finalized. As of March 31, 2019 and December 31, 2018, receivables from contracts with customers were $12.2 million and $14.5 million, respectively.FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718)three months ended March 31, 2019 and 2018: Scope Oil Revenue Gas Revenue Oil Revenue Gas Revenue Operated $ 2,711 $ 20,174 $ - $ 22,885 $ 3,799 $ 5,801 $ - $ 9,600 Non-operated 75 6,182 4 6,261 143 2,096 4 2,243 $ 2,786 $ 26,356 $ 4 $ 29,146 $ 3,942 $ 7,897 $ 4 $ 11,843 be required to apply modification accounting under ASC 718. For public entities, the amendments in this ASU are effective for annual periods 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. For public 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, including interim periods within those fiscal years, for public entities. Early application is permitted. We are currently evaluating 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 most of the existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods 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 uncertainty 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. The Company is currently analyzing the impact of Update 2014-09, and the related ASU's, to evaluate the impact of the new standard on its revenue contracts. The Company is considering its revenue contracts, reviewing 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.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO CONSOLIDATED FINANCIAL STATEMENTS2—3—Asset Retirement Obligationsperiod ending September 30, 2017three months ended March 31, 2019 is as follows (in thousands): September 30, 2017 Beginning balance at December 31, 2016 $ 2,933 $ 3,791 Liabilities incurred 93 24 Liabilities settled (1 ) Accretion expense 171 72 Ending balance at September 30, 2017 $ 3,197 $ 3,886 Current liability $ — $ - Long term liability $ 3,197 $ 3,886 3—4—Debtthe dates indicatedMarch 31, 2019 and December 31, 2018 (in thousands): March 31, 2019 December 31, 2018 2017 Senior Credit Facility $ 32,000 $ 32,000 $ 27,000 $ 27,000 Convertible Second Lien Notes (1) 55,493 52,969 53,691 49,820 $ 87,493 $ 84,969 $ 80,691 $ 76,820 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 $5.5$15.5 million and $1.2$13.7 million of paid in-kind interest at September 30, 2017as of March 31, 2019 and December 31, 2016,2018, respectively. The carrying value includes $8.8$2.5 million and $10.6$3.9 million of unamortized debt discount at September 30, 2017as of March 31, 2019 and December 31, 2016,2018, respectively.periods shownthree months ended March 31, 2019 and 2018 including contractual interest expense, amortization of debt discount accretion and financing costs and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates):
Interest Rate
Interest Rate $ 508 6.7 % $ 173 6.3 % 3,149 24.3 % 2,500 24.6 % $ 3,657 $ 2,673 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 September 30, 2017 includes $0.7March 31, 2019 included $1.3 million of debt discount amortization and $1.4$1.8 million of paid in-kind interest, and interest expense for the ninethree months ended September 30, 2017 includes $1.8March 31, 2018 included $0.9 million of debt discount amortization and $4.3$1.6 million of paid in-kind interest.* - Not comparative as the Company was in bankruptcy during portions of the 2016 periods shown and did not pay interest on its debt while in bankruptcy.Exit Credit FacilityOn 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”), 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 September 30, 2017, we had $16.7 million outstanding on 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 September 30, 2018, unless the Borrower notified the Administrative Agent that it intended to extend the maturity date to September 30, 2019, subject to certain conditions and the payment of a fee.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).GOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSAdditionally, 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.(the “Credit(as amended, the “2017 Credit Agreement”) with the Subsidiary, as borrower, JP MorganJPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the(as amended, the “2017 Senior Credit Facility”). The 2017 Senior Credit Facility amends, restates and refinances the obligations under the Exit Credit Facility. The 2017 Senior Credit Facility matures (a) October 17, 2021 or (b) December 30, 2019, if the Convertible Second Lien Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by September 30, 2019, SeptemberDecember 30, 2019. The maximum credit amount under the 2017 Senior Credit Facility is currentlyas of March 31, 2019 was $250.0 million with an initiala borrowing base of $40.0 million.$75.0 million, subject to an elected draw limit of $50.0 million in recognition of the limitation set forth in the Convertible Second Lien Notes. 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 for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the BorrowerSubsidiary and theGOODRICH PETROLEUM CORPORATION AND SUBSIDIARYNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSwill bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto.TotalNet Funded Debt (as defined in the Credit Agreement) to EBITDAX not to exceed 4.00 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) not to be less than 1.00 to 1.00 and (iii) from and after the issuance of the 2021 Notes, until no Convertible Second Lien2021 Notes remain outstanding, a ratio of Total Proved PV10% attributable to the Company’s and Borrower’s Proved Reserves (as defined in the Credit Agreement) to Total Secured Debt (net of any Unrestricted Cash not to exceed $10.0$10 million) not to be less than 1.50 to 1.00 and minimum liquidity requirements.Agreement are guaranteed byFacility and to fund the Company and secured by a first lien security interest in substantially all of the assets of the Company.13.50% Redemption (as defined below).Senior Secured Notes Due 2019the Effective Date,October 12, 2016, the Company 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 Limitedinvestors (collectively, and together with each of their successors and assigns, the “Purchasers”), in connection with the issuance of $40.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2019 (the “Convertible Second Lien Notes”).equal to acquire 2.5 million shares of common stock. Holders of the Convertible Second Lien Notes have a second priority lien on all assets of the Company, and holders of such warrants have a continuing right to appoint two members to our Board of Directors (the “Board”) as long as the Convertible Second Lien Notessuch warrants are outstanding.willas set forth in the agreement, were scheduled to mature on August 30, 2019 or suchsix months after the maturity of our current revolving credit facility but in no event later date as set forth inthan March 30, 2020. The 2017 Senior Credit Facility was scheduled to mature no earlier than December 30, 2019; consequently, the Convertible Second Lien Notes but in no event later thanwere scheduled to mature on March 30, 2020. The Convertible 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 Convertible Second Lien Notes by increasing the principal amount of the outstanding Convertible Second Lien Notes or by issuing additional Second Lien Notes (“PIK Interest Notes”). The PIK Interest Notes are not convertible. During such time as the 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;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 Convertible Second Lien Notes in cash, at its election.subsidiary,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 STATEMENTS1.35 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)(ii) minimum liquidity requirements.$8.8As of March 31, 2019, $2.5 million of debt discount remains to be amortized on the Convertible Second Lien Notes as of September 30, 2017.September 30, 2017, we wereMarch 31, 2019, the Company was in compliance with all covenants within the Indenture governing the Convertible Second Lien Notes.4—5—EquitySeptember 30, 2017,March 31, 2018, certain holders of the 10 year costless warrants associated with the Convertible Second Lien Notes exercised 54,687589,375 warrants 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 the issuance of 54,68742,500 common shares. During the ninethree months ended September 30, 2017, certain holdersMarch 31, 2018, the Company issued 201,969 shares of its common stock to employees for payment of a portion of the 10 year costless warrants associated with the Convertible Second Lien Notes, exercised 1,429,687 warrants for the issuancebonus earned by such employees during 2017 and accrued as of an equal amount of our one cent par value common stock.December 31, 2017. The Company received cashrepurchased 75,053 of these shares into Treasury for payroll taxes withheld from employees related to the one cent par value for issuance of 679,687 common sharesbonus payout, and the remaining commonthese Treasury shares were issued cashless, which resultedretired in 564 shares repurchased byDecember 2018. The Company did not have a material vesting of its share-based compensation units during the Company and held in treasury stock. As of September 30, 2017, 1,070,312 of such warrants remain un-exercised.three months ended March 31, 2018.5—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. and nine months ended September 30, 2017March 31, 2019 and 2016.2018. 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 net income (loss) per common share: $ 448 $ (5,324 ) 12,151 11,218 $ 0.04 $ (0.47 ) $ 448 $ (5,324 ) 12,151 11,218 150 - 1,418 - 413 - 14,132 11,218 $ 0.03 $ (0.47 ) - 201 1,875 1,875 - 1,916 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 Taxesrecordedrecorded no income tax expense or benefit for either the three and nine months ended September 30, 2017.March 31, 2019 or 2018. We recorded a valuation allowance at December 31, 2016, which resulted in nofor our net deferred tax asset or liability appearing on our statement of financial position. at December 31, 2016. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years)losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, ourthese deferred tax assets were unrecoverable.The valuation allowance was $84.1 million as of December 31, 2018, which resulted in a net non-current deferred tax asset of $0.8 million appearing on our statement of financial position. The net $0.8 million deferred tax asset relates to Alternative Minimum Tax (“AMT”) credits, which are expected to be fully refundable in tax years 2018 - 2021 regardless of the Company's regular tax liability. 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 full valuation allowance for our net deferred tax assets as of September 30, 2017.September 30, 2017,March 31, 2019, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2016.2018.7—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. and nine months ended September 30, 2017March 31, 2019 and 2016:2018: Loss on commodity derivatives not designated as hedges, settled $ (1,760 ) $ (384 ) Gain (loss) on commodity derivatives not designated as hedges, not settled 752 (597 ) $ (1,008 ) $ (981 ) 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 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 amounts had our counterparties$1.6 million had SunTrust Bank been unable to fulfill their obligations as of September 30, 2017.March 31, 2019.September 30, 2017,March 31, 2019, the open positions on our outstanding commodity derivative contracts, all of which were natural gas contracts with BP,JPMorgan Chase Bank, N.A. and SunTrust Bank, were as follows:
March 31, 2019
(In thousands) 308 84,775 $ 51.08 $ (742 ) $ (742 ) 70,000 6,370,000 $ 2.873 $ (787 ) 100,000 27,500,000 $ 2.887 $ 2,613 $ 1,826 $ 1,084 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 tothirdfirst quarter of 2017,2019 we entered into the following new derivative contractscontract with JP Morgan: SunTrust Bank: Natural gas swap (MMBtu) 30,000 $2.951 April 1, 2019 March 31, 2020 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 September 30, 2017March 31, 2019 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Fair value of oil and natural gas derivatives - Current Assets $ - $ 1,826 $ - $ 1,826 Fair value of oil and natural gas derivatives - Non-current Assets - - - - Fair value of oil and natural gas derivatives - Current Liabilities - (742 ) - (742 ) Fair value of oil and natural gas derivatives - Non-current Liabilities - - - - $ - $ 1,084 $ - $ 1,084 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 ) 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 September 30, 2017as of March 31, 2019 and December 31, 2016:2018: Fair value of oil and natural gas derivatives - Current Assets $ 3,035 $ (1,209 ) $ 1,826 $ 2,893 $ (2,090 ) $ 803 Fair value of oil and natural gas derivatives - Non-current Assets - - - - - - Fair value of oil and natural gas derivatives - Current Liabilities (1,951 ) 1,209 (742 ) (2,090 ) 2,090 - Fair value of oil and natural gas derivatives - Non-current Liabilities - - (471 ) - (471 ) $ 1,084 $ - $ 1,084 $ 332 $ - $ 332 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 Contingencieswillwould not behave been material to our consolidated financial position, results of operations or liquidity.liquidity for the three months ended March 31, 2019 and 2018.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 under operatingalso entered into leases for certain vehicles and other equipment which are immaterial to our financial statements and have therefore not been recorded on our Consolidated Balance Sheets.agreements for office space and office equipment. Total rent expensecost components for the three months ended September 30, 2017 and 2016 was approximately $0.4 million and $0.4 million, respectively, and total rent expense forMarch 31, 2019 are classified as follows: $ 353 47 $ 400 $ 2,922 Accumulated depreciation (285 ) Accumulated depletion, depreciation and amortization Lease asset, net $ 2,637 $ 1,332 1,871 $ 3,203 $ 1,155 1,540 813 - - - $ 3,508 305 $ 3,203 nine months ended September 30, 2017 and 2016 was approximately $1.3 million and $1.2 million, respectively. $ 3,753 1,556 513 - - - $ 5,822 Defined Contribution Plan – We have a defined contribution plan (“DCP”) thatCompany matching option to employees' contributions. Participationweighted-average remaining lease term of 2.1 years and a weighted-average discount rate of 8.0 percent. Cash paid for amounts included in the DCP is voluntary and all employeesmeasurement of the Company are eligible to participate. We suspended the Company's match in April 2016. We charged to expense plan contributions of zerooperating lease liabilities was $0.4 million for the three months ended September 30, 2017March 31, 2019.2016,gas leases and zerorelated facilities in Caddo Parish, Louisiana for total consideration of $1.3 million, subject to customary post-closing adjustments. The disposition was recorded as a reduction to our oil and $0.1 million fornatural gas properties (full cost method) on our Consolidated Balance Sheets.nine months ended September 30, 2017Company entered into a Limited Waiver to Credit Agreement with the Subsidiary, JPMorgan Chase Bank, N.A., as administrative agent, and 2016, respectively.NOTE 9—Subsequent EventsOn October 17, 2017, we entered intocertain lenders that are party thereto, pursuant to which the lenders agreed to waive the Company’s failure to comply with the current ratio financial covenant under the 2017 Senior Credit Facility as of the last day of the fiscal quarter ending March 31, 2019.Exit2017 Credit Facility. For further discussion, see Note 3—“2017 Senior Credit Facility”. AsAgreement.October 17, 2017, we had $16.7redemption to the trustee for the Convertible Second Lien Notes to call for redemption on May 29, 2019 approximately $56.7 million aggregate principal amount of borrowingsthe outstanding underConvertible Second Lien Notes, representing 100% of the 2017 Senior Credit Facility.Theaggregate principal amount of the outstanding Convertible Second Lien Notes.new natural gas swaps and oil swapsthe New 2L Notes Purchase Agreement with JP Morgan on October 23, 2017the New 2L Notes Purchasers pursuant to which the Company will issue to the New 2L Notes Purchasers $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021.totaldetailed description of 9,006,500 MMbtueach of natural gas and 263,225 barrelsthese transactions.the impact of restrictive covenants in our debt agreements;counterpartiescounter-parties and operation partners; andfailure 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; and2016.2018.have historically employedemploy commodity hedging techniques 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 of Title 11 of the United States Bankruptcy Code 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 administration of the Chapter 11 Cases under the caption In re Goodrich Petroleum Corporation, et al. (Case No. 16-31975). Our joint plan of reorganization (the “Plan of Reorganization”) was confirmed by the Bankruptcy Court on September 28, 2016, and we emerged from bankruptcy on October 12, 2016 (the “Effective Date”).Upon our emergence from bankruptcy, we adopted Fresh Start Accounting 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 and the effects of the implementation of our Plan of Reorganization resulted in our Consolidated Financial Statements on or after the Effective Date not being comparable with the Consolidated Financial Statements prior to that date. Our financial results for periods following our 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.On the Effective Date, to better reflect the true economics of our exploration and development of oil 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.CaddoRed River parishes, Louisiana and Angelina and Nacogdoches counties, Texas. We heldhave acquired or farmed-in leases totaling approximately 50,00039,100 gross (26,000(22,100 net) acres as of September 30, 2017 producing from and prospective forMarch 31, 2019 in the Haynesville Shale Trend. During the thirdfirst quarter of 2017,2019, we entered intosold a portion of our non-core Haynesville Shale Trend acreage swap transactions which increased our contiguous acreage position and will allow us to drill longer lateral wells.the associated production located in Caddo Parish, Louisiana. We completed and produced 2 gross (2.0 net) new wells in the first quarter of 2019 and had 3 gross (2.7 net) wells in the drilling or completions phase as of March 31, 2019. Our net production volumes from our Haynesville Shale Trend wells represented approximately 88%96% of our total equivalent production on a Mcfe basis and substantially all of our natural gas production for the thirdfirst quarter of 2017.2019. 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 20172019 drilling efforts in the Haynesville Shale Trend.heldhave acquired approximately 102,00049,900 gross (71,000(34,500 net) lease acres in the TMS as of September 30, 2017.March 31, 2019 with approximately 39,300 gross (33,000 net) acres 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%3% of our total equivalent production on a Mcfe basis and approximately 100%substantially all of our total oil production for the thirdfirst quarter of 2017. We did not conduct any2019. 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 14,00012,300 net acres of undeveloped leasehold in the Eagle Ford Shale Trend allin Frio County, Texas as ofMarch 31, 2019, which is prospective for future development or sale.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 income of $37.9$0.5 million for the ninethree months ended September 30, 2016 was the cost of our failed restructuring effort prior to filing for bankruptcy, interestMarch 31, 2019 were oil and gas revenues, transportation and processing expense and depletion, depreciation and amortization expense.The successor 2017 period results of operations (displayed below) reflect All these items increased compared to the period from January 1, 2017three months ended March 31, 2018, which is primarily attributable to September 30, 2017. production volume increases.Net Lossnet loss of $6.2$5.3 million for the ninethree months ended September 30, 2017March 31, 2018 were workover expenses included in lease operating expenses, performance bonus accruala $1.0 million loss on our commodity derivatives not designated as hedges, $1.7 million share-based compensation included in general and administrative expensesexpense and $2.7 million in interest expense offset 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 % $ 26,360 $ 7,901 $ 18,459 234 % 2,786 3,942 (1,156 ) (29 )% 29,146 11,843 17,303 146 % 9,060 2,952 6,108 207 % 47 61 (14 ) (23 )% 9,342 3,316 6,026 182 % 103,795 36,844 66,951 182 % $ 2.91 $ 2.68 $ 0.23 9 % $ 2.73 $ 2.69 $ 0.04 1 % $ 59.45 $ 65.00 $ (5.55 ) (9 )% $ 57.06 $ 57.99 $ (0.93 ) (2 )% $ 3.12 $ 3.57 $ (0.45 ) (13 )% $5.7 million and by $14.4$17.3 million for the three and nine months ended September 30, 2017, respectively,March 31, 2019 compared to the same periodsperiod in 2016.2018. The increases wereincrease was primarily driven by higherincreased natural gas production and higher realized oil and natural gas prices. The increase in natural gas production volumes is attributed to two operated Haynesville Shale Trend wells completed in the secondfirst quarter of 20172019 and the continued production of twofive operated and eight non-operated Haynesville Shale Trend wells completed in late 2016. Beginning in August 2016, we elected to take oursince the first quarter of 2018. The revenue increases were also offset by decreased oil production in-kind and market the majority of our non-operated Haynesville Shale Trend natural gas volumes resulting in an improvementlower realized oil prices in the prices we received on such natural gas volumes. Natural gas realized prices forfirst quarter of 2019 versus the prior year period. For the three and nine months ended September 30, 2016 included the netting of transportation 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%March 31, 2019, respectively,90% of our oil and natural gas revenue was attributable to natural gas sales compared to 35% and 27%67% for the three and nine months ended September 30, 2016, respectively.March 31, 2018.We are concentrating on increasing our natural gas production volumes through increased drilling in the Haynesville Shale Trend.decreased $0.8increased $10.9 million and increased $1.9to $24.0 million infor the three and nine months ended September 30, 2017, respectively,March 31, 2019 compared to the same periodsperiod in 2016.2018. The decreaseincrease in total operating expenses for the three months ended September 30, 2017March 31, 2019 was primarily due to the decrease in productionincreased depreciation, depletion and other taxesamortization, transportation expense and lease operating expense discussed further below. $ 3,335 $ 2,566 $ 769 30 % 631 640 (9 ) (1 )% 4,701 1,312 3,389 258 % $ 0.36 $ 0.77 $ (0.41 ) (53 )% $ 0.07 $ 0.19 $ (0.12 ) (63 )% $ 0.50 $ 0.40 $ 0.10 25 % operating expensesLOE between periods included $0.3 million ($0.04 per Mcfe) of workover expense. The increase in LOE not attributable to workover expense is attributable to increased well count and production for the ninethree months ended September 30, 2017 was primarily the result of $3.1 million of workover costs included in lease operating expense in 2017 and recognition of additional transportation expense in 2017 by virtue of taking ourMarch 31, 2019. Per unit LOE will continue to decrease as we increase production in-kind in the Haynesville Shale Trend, and paying related transportation costs for that production, offset bywhich carries 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 duringmuch lower per unit LOE than the three and nine months ended September 30, 2017, respectively compared to the same periods in 2016. The increase is substantially attributed to an increase in workover expense for the nine months ended September 30, 2017, in addition to increased costs due to increased production for both the three and nine months ended September 30, 2017. We incurred $3.1 million in workover cost for 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. and nine months ended September 30, 2017March 31, 2019 were $0.1$0.4 million, and $0.9 million, respectively. Adad valorem taxes for the three months ended September 30, 2017 was a credit ofMarch 31, 2019 were $0.3 million, which both remained unchanged from the prior year period.as a result of the receipt of refunds. Ad valorem taxes for the ninethree months ended September 30, 2017 was $0.2 million. DuringMarch 31, 2019 as compared with the three and nine months ended September 30, 2016, production and other taxes included severance tax of $0.3 million and $0.8 million, respectively and ad valorem tax of $0.7 million and $1.6 million, respectively.Severance taxes remained relatively flat for both the three and nine months ended September 30, 2017, reflecting decreased oil production volumes directly offset by tax increases due to the expiration of the exemption on certain wellssame period 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$0.111 per Mcf (from July 1, 2017 through June 30, 2018) and $0.122 per Mcf (starting on July 1, 2018) 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 drilled 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.this exemption.The decrease in adbetween periods reflects refunds or tax credits received of $0.2 million and $0.5increased by less than $0.1 million for the three and nine months ended September 30, 2017, respectively,March 31, 2019 as wellcompared to the same period in 2018 due to adding wells offset by property values slightly decreasing. We expect ad valorem taxes to increase as our newly producing wells begin to be valued by the reduction in the assessed valuestaxing jurisdictions. 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 and nine months ended September 30, 2017 includes $1.0 million and $3.0 million, respectively, of transportation fees incurred onMarch 31, 2019 increased compared to the same period in 2018, reflecting increased production from our Haynesville Shale Trend wells. Our natural gas volumes thatfrom our operated wells generally carry less transportation cost per Mcf than from wells we take in-kind and pay directlydo not operate. Despite an increase in our operated natural gas production volumes between periods, our cost per Mcfe increased in the first quarter of 2019 compared to the transporter on non-operated Haynesville Shale Trendsame period in 2018. This per unit increase is partially attributed to the mix of oil and natural gas production volumes effective with August 2016 production. Theduring each period as our oil production is not burdened by transportation and processing expense for the three and nine months ended September 30, 2016 did not include these take in-kind transportation fees as gathering fees for that period were netted against 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 capitalized to the full cost pool rather than expensed. $ 10,046 $ 3,452 $ 6,594 191 % 5,310 5,196 114 2 % 10 - 10 100 % $ 1.08 $ 1.04 $ 0.04 4 % $ 0.57 $ 1.57 $ (1.00 ) (64 )% $ - $ - $ - 0 % in the 2017 Successor Period is calculated on the Full Cost Method using the units of Accounting adopted upon our emergence from bankruptcy based upon asset carrying values as of December 31, 2016.the 2016 Predecessor Period is calculated on the Successful Efforts Method of Accounting. Successor Company recorded $3.7 million and $12.0$5.3 million in G&A expense infor the three and nine months ended September 30, 2017, respectively,March 31, 2019, which includesincluded non-cash expenses of (i) $1.0$1.5 million and $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)share-based compensation. G&A expense increased for the three months ended March 31, 2019 by $0.1 million and $0.4 million, respectively, of office rent amortization. Predecessor Company recorded $3.8 million and $13.9$5.2 million in G&A expense infor the three and nine months ended September 30, 2016, respectively,March 31, 2018, which includes $1.1included non-cash expenses of $1.7 million and $3.3 million of share based compensation, respectively. 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 $ (3,657 ) $ (2,673 ) $ (984 ) 37 % 6 (7 ) 13 186 % (1,008 ) (981 ) (27 ) 3 % Average funded borrowings adjusted for debt discount $ 80,588 $ 50,652 $ 29,936 59 % Average funded borrowings $ 84,490 $ 58,258 $ 26,232 45 % Successor Company's interest expense for the three and nine months ended September 30, 2017 reflectsMarch 31, 2019 reflected interest payable in cash interest of $0.4$0.5 million and $0.9 million, respectively, incurred on the $20.0 million senior secured term loan credit facility (the “Exit2017 Senior Credit Facility”)Facility (as defined below) and non-cash interest of $2.1$3.2 million and $6.2 million, respectively, incurred on the Company's 13.50% Convertible Second Lien Senior Secured Notes due 2019 (the “Convertible Second Lien Notes”), which includes theincluded $1.8 million of paid in-kind interest and $1.3 million of amortization of debt discount. Predecessor Company's interest expense for the three and nine months ended September 30, 2016 reflectsMarch 31, 2018 reflected interest payable in cash of $0.6$0.2 million and $8.5 million, respectively,incurred on the 2017 Senior Credit Facility and non-cash interest of $0.6$2.5 million incurred on the Convertible Second Lien Notes, which included $1.6 million of paid in-kind interest and $2.7$0.9 million respectively. The Predecessor Company did not record interest expense subsequent to the Petition Date on any of its outstanding second lien and senior notes. All the accrued interest on such notes was never paid as the underlyingamortization of debt was canceled in bankruptcy.discount.Interest Income and OtherGain (loss)September 30, 2017 isMarch 31, 2019 was comprised of an unrealizeda $1.8 million loss on cash settlement of $0.5natural gas and oil derivative contracts offset by a mark to market gain of $0.8 million, representing the change of the fair value of our open natural gas and oil derivative contracts, offset by a $0.2 million gain on cash settlement. Gain (loss) on commodity derivatives not designated as hedges for the nine months ended September 30, 2017 is comprised of an unrealized loss of $0.1 million, representing the change of the fair value of our natural gas 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.anticipate that we will continue to incur professionalincurred $0.3 million in trustee and legal fees in the three months ended March 31, 2018 before settling the final outstanding bankruptcy claims and costs until theclosing our 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. and nine months ended September 30, 2017. March 31, 2019. We recorded a valuation allowance at December 31, 2016, which resulted in nofor our net deferred tax asset or liability appearing on our statement of financial position. at December 31, 2016. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of net operating losses in 2016 and prior years)losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, ourthese deferred tax assets were unrecoverable.The valuation allowance was $84.1 million as of December 31, 2018, which resulted in a net non-current deferred tax asset of $0.8 million appearing on our statement of financial position. The net $0.8 million deferred tax asset relates to Alternative Minimum Tax (“AMT”) credits, which are expected to be fully refundable in tax years 2018 - 2021 regardless of the Company's regular tax liability. 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 full valuation allowance for our net deferred tax assets as 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, lenderslenders 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, gains/losses on reorganization and 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”) 842, 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/EBITDAXAdjusted EBITDA should not be considered an alternative to net income (loss), as defined by US GAAP.EBITDA/EBITDAXEBITDA 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 ) Net income (loss) (US GAAP) $ 448 $ (5,324 ) Interest expense 3,657 2,673 Depreciation, depletion and amortization 10,046 3,452 Share-based compensation expense (non-cash) 1,568 1,675 Loss on commodity derivatives not designated as hedges, not settled (752 ) 597 Other items (1) 247 338 $ 15,214 $ 3,411 (1)restructuring, reorganization items and other non-recurring income and expense. Our computationsninethree months of 20172019 were cash on hand, and cash from operating activities.activities, net proceeds from borrowings on our 2017 Senior Credit Facility and proceeds from the sale of assets. We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 20172019 through a combination of cash on hand, cash from operating activities and borrowing under our 2017 Senior Credit Facility (as defined below), althoughrevolving credit facility, although we may from time to time consider the funding alternatives described below.Amended and Restated2017 Senior Secured Revolving Credit Facility, (“Credit Agreement”) with the Subsidiary, as borrower, JPMorgan Chase Bank, N.A. as 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 Senior Credit Facility”).effect. Total lender commitments under the 2017 Senior Credit Facility are $250 million subject to a borrowing base limitation, which as of March 31, 2019 was $75 million, subject to an elected draw limit of $50 million. The 2017 Senior Credit Facility matures on a) October 17, 2021 or b) December 30, 2019, if the Convertible Second Lien Notes have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by September 30, 2019, SeptemberDecember 30, 2019. Revolving borrowings under the 2017 Senior Credit Facility are limited to, and subject to periodic redeterminations of, the borrowing base. The initialamount of the borrowing base is $40 million.determined by the lenders in their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. We may, however, elect to reduce the proposed borrowing base to a lower draw limit by providing notice to the lenders contemporaneously with each redetermination of the borrowing base. Pursuant to the terms of the 2017 Senior 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 onyear. The borrowing base is subject to additional adjustments from time to time, including for asset sales, elimination or about March 1, 2018.reduction of hedge positions and incurrence of other debt. Additionally, we and the administrative agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. JPMorgan Chase Bank, N.A. is the lead lender and administrative agent under the 2017 Senior Credit Facility.thirdfirst quarter of 20172019 with no cash of $31.7 million, which includes $0.6on hand and $32.0 million of restricted cash held 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 Facilitywith $18 million of $16.7 million. The outstanding Exit Credit Facility amount was paid off upon entering intoavailability under the 2017 Senior Credit Facility on October 17,borrowing base draw limit of $50 million. Due to the timing of payment of our capital expenditures, we reflected a working capital deficit of $30 million as of March 31, 2019. Subsequently, our working capital deficit was not covered by availability under our 2017 Senior Credit Facility due to our draw limit, and we were therefore not in compliance with a $16.7 million balance dueour current ratio covenant under the 2017 Senior Credit Facility.Our total capital expenditure budget On April 29, 2019, we entered into a Limited Waiver to Credit Agreement with the Subsidiary, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, pursuant to which the lenders agreed to waive our failure to comply with the current ratio financial covenant under the 2017 Senior Credit Facility as of the last day of the fiscal quarter ending March 31, 2019.range between $40 millionoccur contemporaneously therewith, subject to $50 million. We planthe satisfaction of other customary closing conditions. Proceeds from the sale of the New 2L Notes will be used to focus all of our 2017 drilling efforts inpay down outstanding borrowings under the Haynesville Shale Trend.sale of non-core assets;joint venture partnerships in our TMS, Eagle Ford Shale Trend, and/or core Haynesville Shale Trend acreage; andissuance of debt or equity securities.• joint ventures in our TMS and/or Haynesville Shale Trend acreage; • issuance of equity securities; and • sale of non-core assets. approximately 47%approximately 79% of our natural gas sales volumes for the first ninethree months of 2017. We had no2019 and 62% of our oil derivative contractsvolumes for the first ninethree months of 2017. 2019. For additional information on our derivative instruments see 7—8—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this 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 ) Provided by operating activities $ 17,907 $ 6,256 Used in investing activities (26,970 ) (5,781 ) Provided by (used in) financing activities 4,995 (16,736 ) $ (4,068 ) $ (16,261 ) both the three and nine months ended September 30, 2017.March 31, 2019 and 2018. 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, 2017March 31, 2019 was $0.3$17.9 million including operating cash flows before positive working capital changes of $8.3$3.1 million and including a reduction due to net cash payments of $1.8 million in settlement of derivative contracts. The substantial increase in cash provided by operating activities forin the nine months ended September 30, 2017current quarter compared to the first quarter 2018 was $15.8 million including operating cash flows before working capital changes of $13.6 million.attributable to a 146% increase in oil and natural gas revenues driven by a 182% increase in equivalent production volumes offset by a 13% decrease in equivalent realized prices. 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 was approximately $3.7 million and $21.2$27.0 million for the three and nine months ended September 30, 2017, respectively.March 31, 2019 which reflected cash expended on capital projects of $28.3 million reduced by $1.3 million cash proceeds received from sale of oil and gas properties. We recorded $29.5 million in capital expenditures in this period. The difference in capital expenditures and net cash used in investing activitiesexpended on capital projects for the ninethree months ended September 30, 2017March 31, 2019 was attributed to $3.3a net capital accrual increase of $1.1 million accrued at September 30, 2017, $1.0and capitalization of $0.2 million of utilized inventory, $0.5 million proceeds received from the sale of assets,asset retirement 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 capitalizednon-cash internal costs directly related to our acquisition of leasehold, drilling and completion activities. Capital expenditures duringcosts. During the three months ended September 30, 2017 were substantially all spent onMarch 31, 2019, we conducted drilling and completions costs, while capital expenditures forcompletion operations on 5 gross (4.7 net) wells bringing 2 gross (2.0 net) wells on production with 3 gross (2.7 net) wells remaining in the nine months ended September 30, 2017 were comprised of $25.6 million associated with drilling and completions costs and $0.2 million for miscellaneous expenditures.used inprovided by financing activities for the ninethree months ended September 30,March 31, 2019 reflects primarily net borrowings under our 2017 consistedSenior Credit Facility. 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 2017 Senior Credit Facility $ 32,000 $ 32,000 $ 27,000 $ 27,000 Convertible Second Lien Notes (1) 55,493 52,969 53,691 49,820 $ 87,493 $ 84,969 $ 80,691 $ 76,820 $5.5$15.5 million and $1.2$13.7 million of paid in-kind interest at September 30, 2017as of March 31, 2019 and December 31, 2016,2018, respectively. The carrying value includes $8.8$2.5 million and $10.6$3.9 million of unamortized debt discount at September 30, 2017as of March 31, 2019 and December 31, 2016,2018, respectively.3—4—“Debt” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.2016,2018 includes a discussion of our critical accounting policies and there have been no material changes to such policies during the three months ended September 30, 2017.March 31, 2019.counterpartiescounter-parties in order to satisfy these margin requirements.3—4—“Debt”and Note 7—8—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q. during the nine months ended September 30, 2017 in order to reduce the price risk associated with production in 2017for the rest of 2019 of approximately 18,000100,000 MMBtu per day and 308 barrels per day, respectively, and in the first quarter of 2020 of 70,000 MMBtu per day. We did not enter into derivatives instruments for trading purposes. purposes. Utilizing actual derivative contractual volumes, a hypothetical increase of 10% in the underlying commodity prices would have changed the derivative natural gas net asset position to a liability position with a change of $9.1 million and increased the derivative oil liability position by $0.4$0.5 million as of September 30, 2017.March 31, 2019. 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 aderivative natural gas net derivative asset position by $9.4 million and decreased the derivative oil liability position by $0.5 million as of September 30, 2017.March 31, 2019. 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.2016.2018.September 30, 2017,March 31, 2019, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.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.September 30, 2017,March 31, 2019, we did not have any material outstanding and pending litigation.2016,2018, 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*10.2**Filed herewith**November 8, 2017May 14, 2019 November 8, 2017May 14, 201932