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.

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 nine months ended September 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 months ended September 30, 2018 and 2017, we transferred $5.7 million and $5.8 million, respectively, from unevaluated properties to proved oil and natural gas properties. For the nine months ended September 30, 2018 and 2017, we transferred $5.8$6.1 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 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 nine months ended September 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 September 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 September 30, 20172018 and December 31, 2016,2017, the

New Accounting Pronouncements

 

On August 28, 2017,2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this ASU modify the disclosure requirements on fair value measurements in Topic 820 including the removal, modification and addition of certain disclosure requirements. For all entities, the amendments in this ASU are effective for fiscal periods beginning after December 15, 2019, including interim periods therein. We are evaluating the expected impact these amendments will have 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.

We record revenue in the newmonth our production is delivered to the purchaser. However, settlement statements and payments for our oil and natural gas sales may not be received for up to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. As of September 30, 2018 and December 31, 2017, receivables from contracts with customers were $9.3 million and $5.0 million, respectively.

Topic 606 will not change our pattern of timing of revenue standard. In May 2016,recognition. We utilized the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potentialfull retrospective method for diversity in practice at initial applicationadoption 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 Pursuantin accordance with this method our consolidated financial statements for periods prior 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 hasJanuary 1, 2018 were not yet selectedmaterially affected or revised. We also do not anticipate a transition method. The Company is currently analyzing thematerial 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.our financial statements on an ongoing basis.

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 September 30, 2018, the interest rate on the 2017 Senior Credit Facility was 7.25%.

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 December 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$5.1 million of debt discount remains to be amortized on the Convertible Second Lien Notes as of September 30, 2017.2018.

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

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

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

* - Adjustments to weighted average shares of common stock is not applicable due to a net loss for the period.

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

Subsequent to the third quarter of 2017,2018 we entered into the following new derivative contracts with JP Morgan:    JPMorgan Chase Bank, N.A. and SunTrust Bank:

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.

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.

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), on derivatives not yet settled, 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.

Primary Operating Areas

Haynesville Shale Trend

 

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 50,00046,400 gross (26,000(22,400 net) acres as of September 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%96% of our total equivalent production on a Mcfe basis for the third quarter of 2017.2018. We drilled onecompleted and produced 7 gross (0.7(3.0 net) wellnew wells in the third quarter of 2017, which will be completed2018 and have 5 gross (3.4 net) wells in the fourth quarterdrilling and completion phases as of 2017.September 30, 2018. We plan to focus all of our 2017remaining 2018 drilling efforts in the Haynesville Shale Trend.

Tuscaloosa Marine Shale Trend

We held approximately 102,00055,500 gross (71,000(39,300 net) acres in the TMS as of September 30, 2017.2018. We have 2 gross (1.7 net) TMS wells drilled and awaiting completion. Our net production volumes from our TMS wells represented approximately 12%4% of our total equivalent production on a Mcfe basis and approximately 100% of our total oil production for the third 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.

Eagle Ford Shale Trend

We hold approximately 14,00012,300 net acres of undeveloped leasehold in the Eagle Ford Shale Trend all of which is prospective for future development or sale.

In addition to adopting Fresh Start Accounting,The Company recorded net income of $1.7 million for 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 successorCompany recorded net income of $0.7 million for the three months ended September 30, 2017 period resultsand a net loss of operations (displayed below) reflect$6.2 million for the period from January 1, 2017 tonine months ended September 30, 2017. The items that had the most material financial effect on our Net Lossnet loss of $6.2 million for the nine months ended September 30, 2017 were workover expenses included in lease operating expenses, performance bonus accrualexpense and $3.0 million in shared-based compensation included in general and administrative expense. Lease operating expense in the period included $3.1 million in workover expenses and interest expense offset by non-recurring other income.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(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.