UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

TABLE OF CONTENTS

 

CONSOLIDATED BALANCE SHEETS

 

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

See accompanying notes to consolidated financial statements.

NOTE 1—Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (“Goodrich” and, together with its wholly-owned 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 (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, 2016.2017. Operating results for the three and ninesix months ended SeptemberJune 30, 20172018 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.

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 the three and nine months ended SeptemberJune 30, 2018 and 2017, we transferred $5.8$0.3 million and $18.6$1.9 million, respectively, from unevaluated properties to proved oil and natural gas properties. For the six months ended June 30, 2018 and 2017, we transferred $0.4 million and $12.8 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 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.

There were no Full Cost Ceiling Test write-downs for the three or ninesix months ended SeptemberJune 30, 2017.

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 Levels (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.

Each of these Levels and our corresponding instruments classified by Level are further described below:

As of SeptemberJune 30, 20172018 and December 31, 2016,2017, 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.

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—Oil and natural gas revenues are recognized when production is soldupon delivery of our produced oil and natural gas volumes to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable.our customers. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized usingin accordance with when the entitlements method.producing company records revenue on those volumes. 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. At SeptemberJune 30, 20172018 and December 31, 2016,2017, the

New Accounting Pronouncements

 

On August 28, 2017,June 20, 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. The amendments specify that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be used or consumed in a grantor’s own operations by issuing share-based payment awards. The amendments also clarify that Topic 718 does not apply to share-based payments used to effectively provide (1) financing to the issuer or (2) awards granted in conjunction with selling goods or services to customers as part of a contract accounted for under Topic 606, Revenue from Contracts with Customers. For public entities, the amendments in this ASU are effective for annual periods beginning after December 15, 2018. We have not granted or issued share-based payments to nonemployees. We have evaluated the provisions of this ASU and do not expect it to have a material impact on our consolidated financial statements.

On August 28, 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting 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, the amendments in this ASU make 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. For public entities, the amendments in this ASU are effective for annual periods beginning after December 15, 2018. We do not expect this ASU to have a material impact on our consolidated financial statements as we currently mark to marketmark-to-market all of our derivative positions; however, we are evaluating the impact of this ASU should we choose to utilize hedge accounting in the future.

On May 10, 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. This ASU amends the scope of modification accounting for share-based payment arrangements and provides guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would

NOTE 2—3—Asset Retirement Obligations

NOTE 3—4—Debt

2017 Senior Credit Facility

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 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 will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. As of June 30, 2018, the interest rate on the 2017 Senior Credit Facility was 6.75%.

The 2017 Senior Credit Facility also contains certain financial covenants, including (i) the maintenance of (i) a ratio of Total 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) until no Convertible Second Lien Notes remain outstanding, (A) the maintenance of 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 million) not to be less than 1.50 to 1.00 and (B) minimum liquidity requirements.

The obligations under the Credit Agreement are guaranteed by the Company and are secured by a first lien security interest in substantially all of the assets of the Company.Company and the Subsidiary.

 

 

On the Effective Date,October 12, 2016, upon emergence from bankruptcy, 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 Limited (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”).

 

The aggregate principal amount of the Convertible Second Lien Notes is convertible at the option of the Purchasers at any time prior to the scheduled maturity date at $21.33 per share, subject to adjustments. At closing, the Purchasers were issued 10-year costless warrants 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 have a continuing right to appoint two members to our Board of Directors (the “Board”) as long as the Convertible Second Lien Notes are outstanding.

 

The Convertible Second Lien Notes as set forth in the agreement, will 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 matures no earlier than September 30, 2019; consequently, the Convertible Second Lien Notes but in no event later thanwill 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; 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.

The indenture governing the Convertible Second Lien Notes (the “Indenture”) contains certain covenants pertaining to us and our subsidiary, including delivery of financial reports; environmental matters; conduct of business; use of proceeds; operation and maintenance of properties; collateral and guarantee requirements; indebtedness; liens; dividends and distributions; limits on sale of assets and stock; business activities; transactions with affiliates; and changes of control.

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. $8.8$6.1 million of debt discount remains to be amortized on the Convertible Second Lien Notes as of SeptemberJune 30, 2017.2018.

As of SeptemberJune 30, 2017, we were2018, the Company was in compliance with all covenants within the Indenture governing the Convertible Second Lien Notes.

NOTE 4—5—Equity

During the three months ended SeptemberJune 30, 2017,2018, certain holders of the 10 year costless warrants associated with the Convertible Second Lien Notes exercised 54,687273,437 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 273,437 common shares. During the six months ended June 30, 2018, certain holders of the 10 year costless warrants associated with the Convertible Second Lien

During the three and six months ended June 30, 2017, holders of the 10 year costless warrants attached to the Convertible Second Lien Notes, exercised 1,375,000 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 issuance of 54,687 common shares. During the nine months ended September 30, 2017, certain holders of the 10 year costless warrants associated with the Convertible Second Lien Notes, exercised 1,429,687 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 issuance of 679,687625,000 common shares and the remaining common shares were issued cashless, which resulted in 564 shares repurchased by the Company and held in treasury stock. AsThese treasury stock shares were subsequently retired.

The Company had no material vestings of Septemberits share based compensation units during the three or six months ended June 30, 2017, 1,070,312 of such warrants remain un-exercised.2018 or 2017.

NOTE 5—6—Net Income (Loss) Per Common Share

* Adjustments- 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 performance units granted (or a ratio of one unit to weighted average sharesone common share). The range of common stock is not applicable dueshares which may be earned ranges from zero to a net loss for250% of the period.initial performance units granted.

We recorded no income tax expense or benefit for the three and nineor six months ended SeptemberJune 30, 2017.2018. We recorded a valuation allowance at December 31, 2016, which resulted in nofor our net deferred tax asset or liabilityat December 31, 2016. The valuation allowance was $86.7 million at December 31, 2017, which resulted in a net non-current deferred tax asset of $0.9 million appearing on our statement of financial position. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of net operating losses in 20162017 and prior years) 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 tax benefit recorded for 2017 is due to Alternative Minimum Tax (“AMT”) credits that are expected to be recognized by the Company, which have been reduced for the anticipated sequestration. The remaining $0.9 million of AMT credits, which is less anticipated sequestration, are expected to be fully refundable in tax years 2018 - 2021 regardless of the Company's regular tax liability as a result of the repeal of the Corporate AMT under the Tax Cuts and Jobs Act. The Company no longer has a valuation allowance recorded against our estimate of refundable AMT credits. 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 SeptemberJune 30, 2017.2018 aside from the deferred tax asset related to the AMT credits.

As of SeptemberJune 30, 2017,2018, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2016.2017.

NOTE 7—8—Commodity Derivative Activities

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

proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position, results of operations or liquidity.

respectively. Total rent expense for the ninesix months ended SeptemberJune 30, 20172018 and 20162017 was approximately $1.3$0.8 million and $1.2$0.9 million, respectively.

NOTE 9—Subsequent Events10—Dispositions

Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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:

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, 2016.2017.

Overview

Goodrich Petroleum Corporation (“Goodrich” and, together with its wholly-owned subsidiary, Goodrich Petroleum Company, L.L.C. (the "Subsidiary”“Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.

We 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 external financing, such as bank debt, asset divestitures, issuanceissuances 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 hedgingderivative 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 prevailing commodity prices for oil and natural gas. Such pricing factorsCommodity prices are largely beyond our control; however, we have historically employedemploy commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earningsrevenues and operating cash flow.

 

Our development acreage in this trendthe Haynesville Shale Trend is primarily centered in DeSoto, Caddo and CaddoRed River parishes, Louisiana and Angelina and Nacogdoches counties, Texas.Louisiana. We held approximately 50,00045,900 gross (26,000(21,800 net) acres as of SeptemberJune 30, 20172018 producing from and prospective for the Haynesville Shale Trend. During the third quarter of 2017, we entered into acreage swap transactions which increased our contiguous acreage position and will allow us to drill longer lateral wells. Our net production volumes from our Haynesville Shale Trend wells represented approximately 88%94% of our total equivalent production on a Mcfe basis for the thirdsecond quarter of 2017.2018. We drilled onecompleted and produced 4 gross (0.7(2.0 net) wellnew wells in the thirdsecond quarter of 2017, which will be completed2018 and have 7 gross (2.8 net) wells in the fourth quarterdrilling and completion phases as of 2017.June 30, 2018. We plan to focus all of our 20172018 drilling efforts in the Haynesville Shale Trend.

We held approximately 102,00060,000 gross (71,000(43,100 net) acres in the TMS as of SeptemberJune 30, 2017.2018. We have 2 gross (1.7 net) TMS wells drilled and awaiting completion. During the second quarter of 2018, we sold a portion of our interest in the western area of our TMS acreage position in East and West Feliciana Parishes, Louisiana for $3.3 million. Our net production volumes from our TMS wells represented approximately 12%6% of our total equivalent production on a Mcfe basis and approximately 100% of our total oil production for the thirdsecond quarter of 2017. We did not conduct any2018. Despite making no capital expenditures, we are seeking to maintain production through strategic expense workover operations on any wells in the TMS during the third quarter of 2017.TMS.

We hold approximately 14,000 net acres of undeveloped leasehold in the Eagle Ford Shale Trend all of which is prospective for future development or sale.

Results of Operations

The item that had the most material financial effect on our net loss of $1.2 million for the three months ended June 30, 2017 was lease operating expense. Lease operating expense in the period included $0.7 million in workover expenses and interestincurred in our effort to increase production volumes after having curtailed such expenditures while in bankruptcy during the previous year. The item that had the most material financial effect on our net loss of $6.9 million for the six months ended June 30, 2017 was lease operating expense. Lease operating expense offset by non-recurring other income.in the period included $2.9 million in workover expenses incurred in our effort to increase production volumes after having curtailed such expenditures while in bankruptcy during the previous year.

The following table reflects our summary operating information for the periods presented in thousands, except for price and volume 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.