UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-Q

 

 

For the Quarterly Period Ended September 30, 2015

OR

Commission file number: 001-12719

 

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

 

801 Louisiana, Suite 700

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(Registrant’s telephone number, including area code): (713) 780-9494

 

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  x    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  x    No  ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 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  x

The number of shares outstanding of the Registrant’s common stock as of November 2, 2015 was 60,642,398.

 

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

TABLE OF CONTENTS

 

 

 

 

 

 

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PART 1 – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

 

 

See accompanying notes to consolidated financial statements.

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, Except Per Share Amounts)

(Unaudited)

 

 

See accompanying notes to consolidated financial statements.

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

See accompanying notes to consolidated financial statements.

 

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1—Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (together with its 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) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), (ii) South Texas, which includes the Eagle Ford Shale Trend and (iii) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend.  

Liquidity and Capital Resources—We are an exploration and production company with interests in non-conventional oil and natural gas shale properties that require large investments of capital to develop.  Our immediate capital resources to develop our properties come from cash on hand, operating cash flows and borrowings from our Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”). The current significant decline in crude oil prices and to a lesser extent the continued depressed natural gas prices has negatively impacted our cash flows that enable us to invest in and maintain our properties and service our long term obligations.

We have taken the following steps in 2015 to mitigate the effects of lower crude oil prices on our operations:

1. Reduced our capital expenditures planned for 2015 thereby conserving capital.

2. Extended the maturity of our Senior Credit Facility to February 24, 2017.

3. Received proceeds of $100 million from the issuance of Second Lien Notes.

4. Received net proceeds of $47.5 million from the sale of 12,000,000 shares of our common stock to the public.

5. Reduced staff headcount by more than 30% from year-end 2014 levels thereby reducing expenses.

6. Closed the sale of proved reserves and a portion of the associated leasehold in the Eagle Ford Shale Trend in September 2015 for proceeds of $101.6 million, with an additional $14.4 million placed into escrow pending resolution of post-closing adjustments.  The proceeds were used to pay off Senior Credit Facility debt in early September.

7. In September and October 2015, we exchanged an aggregate of $72.1 million of our 5.0% Senior Convertible Notes due 2032 for $36.0 million of new 5.0% Senior Convertible Notes due 2032, thereby reducing future annual cash interest by $1.8 million.

8. In October 2015, we exchanged $158.2 million of our 8.875% Senior Notes due 2019 for $75.0 million of 8.875% Second Lien Notes due 2018, thereby reducing our future annual cash interest by $7.4 million.

9. Suspended all preferred stock dividend payments beginning in the third quarter of 2015 to conserve capital.

Additionally, we have all of our remaining projected 2015 oil and condensate sales volumes favorably hedged. See Note 6.

We have other resource options to enhance liquidity as well, such as selling non-core properties, entering into joint ventures in our core areas and/or further reducing our planned capital expenditures.

As a result of the steps we have taken to conserve capital and enhance our liquidity, we anticipate our cash on hand, cash from operations and our available borrowing capacity under our Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements in 2016. We may be reliant on the availability of borrowings under our Senior Credit Facility to accomplish our operation and capital expenditure plan in 2016 and beyond.  A sustained drop from current commodity price levels will result in financial results that could violate a financial covenant despite the flexibility we have obtained under the revised debt covenants (See Note 3). This could prevent us from accessing our borrowings available under the Senior Credit Facility.

Principles of Consolidation—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 accounting principles generally accepted in the United States (“US GAAP”) has been condensed or omitted. The consolidated financial statements include the financial statements of the Company and its wholly-owned subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Use of Estimates— Our management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with US GAAP.

Cash and Cash Equivalents—Cash and cash equivalents includes cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at the date of purchase.

Property and Equipment—As of September 30, 2015, we had interests in oil and natural gas properties totaling $530.9 million, net of accumulated depletion, which we account for under the successful efforts method. Under this method, costs of acquiring unproved and proved oil and natural gas leasehold acreage are capitalized. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Costs of all other unproved leases are amortized over the estimated average holding period of the leases. Development costs are capitalized, including the costs of unsuccessful development wells.

Impairment—We periodically assess our long-lived assets recorded in oil and natural gas properties on the Consolidated Balance Sheets to ensure that they are not carried in excess of fair value, which is computed using Level 3 inputs such as discounted cash flow models or valuations, based on estimated future commodity prices and our various operational assumptions. An evaluation is performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicate that our oil and natural gas properties may be impaired.

To determine if a field is impaired, we compare 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 are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the field.

Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depletion, depreciation and amortization to reduce the carrying value of the field. Each part of this calculation is subject to a large degree of judgment, including the determination of the fields’ estimated reserves, future cash flows and fair value.

During the third quarter of 2015 there was an indication, due to declines in estimated proved reserves, the carrying amount of certain of our natural gas properties was not recoverable from future cash flows. We recorded an impairment of $32.5 million for the three and nine months ended September 30, 2015. The impairment charge reduced the fields’ carrying value to an estimated fair value of $7.8 million. Estimated fair value was measured using the income approach with Level 3 inputs. No impairments were recorded for the three months ended March 31, 2015 or June 30, 2015.

Fair Value Measurement—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, our credit risk.

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.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Each of these levels and our corresponding instruments classified by level are further described below:

As of September 30, 2015 and December 31, 2014, 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 following table summarizes the fair value of our financial instruments and long lived assets that are recorded or disclosed at fair value classified in each level as of September 30, 2015:

 

Depreciation—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. Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in operating income. 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.

Transportation Obligation—We entered into a natural gas gathering agreement with an independent service provider, effective July 27, 2010. The agreement was scheduled to remain in effect for a period of ten years and required the service provider to construct pipelines and facilities to connect our wells to the service provider’s gathering system in our Eagle Ford Shale Trend area of South Texas. In compensation for the services, we agreed to pay the service provider 110% of the total capital cost incurred by the service provider to construct new pipelines and facilities. The service provider billed us for 20% of the accumulated unpaid capital costs annually. This obligation was relieved upon the sale of our Eagle Ford Shale Trend properties in September 2015, however we are obligated to pay the 2015 annual billing. As a result, the transportation obligation liability was reduced to $1.5 million as of September 30, 2015. The obligation totaled $5.4 million as of December 31, 2014.

We accounted for the agreement by recording a long-term asset, included in “Deferred financing cost and other” on the Consolidated Balance Sheets. The asset was being amortized using the units-of-production method and the amortization expense was included in “Transportation and processing” on the Consolidated Statements of Operations. The related current and long-term liabilities were presented on the Consolidated Balance Sheets in “Accrued liabilities” and “Transportation obligation,” respectively.

Asset Retirement Obligations—Asset retirement obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and natural gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in “Depreciation, depletion and amortization” on our Consolidated Statements of Operations. See Note 2.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 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 sold 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. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method. 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, 2015 and December 31, 2014, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps 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. 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 counterparty for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. All 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 6.

Income or Loss Per Share—Basic income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted-average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) applicable to common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive stock options, stock warrants and restricted stock calculated using the Treasury Stock method and the potential dilutive effect of the conversion of shares associated with our 5.375% Series B Convertible Preferred Stock (“Series B Preferred Stock”), 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), 5.0% Convertible Senior Notes due 2029 (the “2029 Notes”), and 5.0% Convertible Senior Notes due 2032 (the “2032 Notes”) and 2032 Exchange Notes. See Note 4.

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, when probable of realization, are separately recorded and are not offset against the related environmental liability.

Guarantees—On March 2, 2011, we issued and sold $275 million aggregate principal amount of our 8.875% Senior Notes due 2019 (the “2019 Notes”). Upon issuance of the guarantee related to the 2019 Notes, our subsidiary also became a guarantor on our outstanding 2029 Notes and our 2026 Notes, pursuant to the respective indentures governing the 2029 Notes and 2026 Notes. On August 26, 2013 and October 1, 2013, we issued $109.25 million and $57.0 million, respectively, aggregate principal amount of our 2032 Notes, which are also guaranteed by our subsidiary pursuant to the terms of the indenture governing the 2032 Notes. The 2019 Notes, 2029 Notes, 2026 Notes and 2032 Notes are guaranteed on a senior unsecured basis by our 100% owned subsidiary, Goodrich Petroleum Company, L.L.C.  On March 12, 2015, we issued and sold $100 million aggregate principal amount of our Second Lien Notes and upon issuance our subsidiary became the guarantor of the Second Lien Notes under the governing indenture. On September 8, 2015, we issued $27.5 million aggregate principal amount of our 2032 Exchange Notes and, upon issuance, our subsidiary became the guarantor of the 2032 Exchange Notes under the governing indenture.

Goodrich Petroleum Corporation, as the parent company (the “Parent Company”), has no independent assets or operations. The guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2019 Notes, 2026 Notes, 2029 Notes, 2032 Notes and 2032 Exchange Notes, as discussed below. The Parent Company has no other subsidiaries. In addition, there are no restrictions on the ability of the Parent Company to obtain funds from its subsidiary by dividend or loan. Finally, the Parent Company’s wholly-owned subsidiary does not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third party.

Guarantees of the 2019 Notes will be released under certain circumstances, including in the event a Subsidiary Guarantor (as defined in the indenture governing the 2019 Notes) is sold or disposed of (whether by merger, consolidation, the sale of its capital

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction to a person which is not the Parent Company or a Restricted Subsidiary of the Parent Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “Limitation on Sales of Assets and Subsidiary Stock” in the indenture governing the 2019 Notes. In addition, a Subsidiary Guarantor will be released from its obligations under the indenture and its guarantee if such Subsidiary Guarantor ceases to guarantee any other indebtedness of the Parent Company or a Subsidiary Guarantor under a credit facility, and is not a borrower under the Senior Secured Credit Agreement, provided no Event of Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing; or if the Parent Company designates such subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the indenture or if such subsidiary otherwise no longer meets the definition of a Restricted Subsidiary; or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the 2019 Notes in accordance with the indenture.

Guarantees of the 2032 Exchange Notes, 2032 Notes, 2029 Notes and 2026 Notes will be released if the Subsidiary Guarantor no longer guarantees the 2019 Notes, if the Subsidiary Guarantor is dissolved or liquidated, if the Subsidiary Guarantor is no longer the Parent Company’s subsidiary or upon satisfaction and discharge of the 2032 Exchange Notes, 2032 Notes, 2029 Notes or 2026 Notes in accordance with their respective indentures.

Guarantees of the Second Lien Notes will be released under certain circumstances, including in the event the Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its capital stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction to a person which is not the Parent Company or a Restricted Subsidiary of the Parent Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “Limitation on Sales of Assets and Subsidiary Stock” in the indenture governing the Second Lien Notes. In addition, a Subsidiary Guarantor will be released from its obligations under the indenture and its guarantee if such Subsidiary Guarantor ceases to guarantee any other indebtedness of the Parent Company or a Subsidiary Guarantor, provided no Event of Default (as defined in the indenture governing the Second Lien Notes) has occurred and is continuing; or if the Parent Company designates such subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the indenture or if such subsidiary otherwise no longer meets the definition of a Restricted Subsidiary; or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the Second Lien Notes in accordance with the indenture.

New Accounting Pronouncements

In August 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-15. The ASU incorporates the SEC staff's announcement that clarifies the exclusion of line-of-credit arrangements from the scope of ASU 2015-03. Therefore, debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the time of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest, which seeks to simplify presentation of debt issuance costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. Entities should apply the amendments in this ASU on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. For public entities, this ASU is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. We are currently evaluating the provisions of this ASU and assessing the impact it may have on our consolidated financial statements.

In January 2015, the FASB issued ASU 2015-01, which eliminates the concept of “extraordinary” items from US GAAP.  This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity also may apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. This new standard requires management to perform interim and annual assessments

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

of our ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This ASU applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted.

In May 2014, the FASB issued ASU 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This revenue standard was originally effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods. In July 2015, the FASB elected to defer its effective date by one year to December 15, 2017. Adoption as of the original effective date is permitted. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

 

 

NOTE 2—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the period ending September 30, 2015 is as follows (in thousands):

 

 

 

NOTE 3—Debt

Debt consisted of the following balances as of the dates indicated (in thousands):

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

The following table summarizes the total interest expense (contractual interest expense, accretion, amortization of debt discount and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates): 

 

* - Not meaningful

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Senior Credit Facility

Total lender commitments under the Senior Credit Facility are $600 million subject to a borrowing base limitation, which as of September 30, 2015 was $105 million. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of September 30, 2015, we had $17.5 million outstanding under the Senior Credit Facility and $4.0 million in cash.   In February 2015, we entered into the Thirteenth Amendment to the Senior Credit Facility (the “Thirteenth Amendment”) with an effective date of February 26, 2015. On the effective date, the Thirteenth Amendment reduced our borrowing base to $200 million and extended the maturity of the Senior Credit Facility to February 24, 2017. In March 2015, we closed on $100 million of Second Lien Notes, which was used to pay down the amount drawn on our Senior Credit Facility.  Our borrowing base was further reduced to $150 million upon the funding of the Second Lien Notes. On September 4, 2015, we closed on the sale of our Eagle Ford Shale Trend assets at which time the borrowing base was reduced to $105 million. In October 2015, we entered into the Fourteenth Amendment to the Senior Credit Facility (the “Fourteenth Amendment”) with an effective date of October 1, 2015. On the effective date, the Fourteenth Amendment reduced our borrowing base to $75 million in conjunction with the exchange of $158.2 million of our 2019 Notes for the issuance of $75.0 million of 8.875% Second Lien Notes due 2018. Interest on revolving borrowings under the Senior Credit Facility, as amended, accrues at a rate calculated, at our option, at the bank base rate plus 1.25% to 2.25% or LIBOR plus 2.25% to 3.25%, depending on borrowing base utilization. Substantially all of our assets are pledged as collateral to secure the Senior Credit Facility.

The terms of the Senior Credit Facility require us to maintain certain covenants. Capitalized terms used here, but not defined, have the meanings assigned to them in the Senior Credit Facility. The primary financial covenants under the Thirteenth Amendment, included:

As used in connection with the Senior Credit Facility, Current Ratio is consolidated current assets (including current availability under the Senior Credit Facility, but excluding non-cash assets related to our derivatives) to consolidated current liabilities (excluding non-cash liabilities related to our derivatives, accrued capital expenditures and current maturities under the Senior Credit Facility).

As used in connection with the Senior Credit Facility, EBITDAX is earnings before interest expense, income tax, depreciation, depletion and amortization, exploration expense, stock based compensation and impairment of oil and natural gas properties. In calculating EBITDAX for this purpose, gains/losses on derivatives not designated as hedges, less net cash received (paid) in settlement of commodity derivatives are excluded from Adjusted EBITDAX.

We were in compliance with all the financial covenants of the Senior Credit Facility as of September 30, 2015.

On November 3, 2015, the Company entered into the Fifteenth Amendment to the Senior Credit Facility (the “Fifteenth Amendment”) with an effective date of November 3, 2015. The Fifteenth Amendment includes the following key elements:

 

The Fifteenth Amendment also revised the Senior Credit Facility to include the following provisions and covenants: (i) Maximum First Lien Debt not greater than 1.25 times EBITDAX for the Trailing Twelve Months; (ii) Interest Coverage Ratio of EBITDAX of not less than 1.25 to 1.0 for the Trailing Twelve Months; (iii) No-hoarding provision of a maximum cash balance of $15 million at any time; (iv) No borrowed proceeds to redeem junior capital; (v) restricts the ability to declare, pay or distribute dividends

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

on our preferred capital stock consistent with the terms of the 8.0% Second Lien Notes and the 8.875% Second Lien Notes; and (vi) the next redetermination date will be January 1, 2016.

8.0% Second Lien Senior Secured Notes due 2018

On March 12, 2015, we sold 100,000 units (the “Units”), each consisting of a $1,000 aggregate principal amount at maturity of our Second Lien Notes and one warrant to purchase 48.84 shares of our $0.20 par value common stock. The Second Lien Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility. The Company received proceeds, before offering expenses payable by the Company, of $100 million from the sale of the Units. The proceeds from the issuance of the Second Lien Notes were used to repay borrowings under the Senior Credit Facility and for general corporate purposes. The Second Lien Notes are secured on a senior second-priority basis by liens on certain assets of the Company and its subsidiary that secures our Senior Credit Facility, which liens are subject to an inter-creditor agreement in favor of the lenders under the Senior Credit Facility. The Second Lien Notes mature on March 15, 2018. If the aggregate principal amount outstanding on the 2032 Notes on August 1, 2017 is more than $25.0 million then the outstanding amount of the Second Lien Notes shall be due on September 1, 2017.  Interest on the Second Lien Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2015.  

We may redeem all or a portion of the Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 106% for the twelve-month period beginning on March 15, 2016 and (ii) 100% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date.  Prior to March 15, 2016, we may redeem the Second Lien Notes at a customary “make-whole” premium.

The indenture governing the Second Lien Notes restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem or retire such capital stock or our unsecured debt; (iii) sell assets, including the capital stock of our restricted subsidiaries; (iv) pay dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications.  At any time when the Second Lien Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indenture governing the Second Lien Notes) has occurred and is continuing, many of these covenants will terminate.

The Second Lien Notes and the warrants became separately transferable on June 4, 2015 when a registration statement related to the resale of the warrants was declared effective by the SEC. The warrants are exercisable upon payment of the exercise price of $4.664 or convertible on a cashless basis as set forth in the agreement governing the warrants. Any warrants not exercised by March 12, 2025 will expire.

In connection with the Second Lien Notes, we entered into a registration rights agreement that provides holders of the Second Lien Notes certain rights relating to registration of the Second Lien Notes under the Securities Act of 1933, as amended (the “Securities Act”).  Pursuant to the registration rights agreement, the Company is obligated to file an exchange offer registration statement with the SEC with respect to an offer to exchange the Second Lien Notes for substantially identical notes that are registered under the Securities Act. We will use our reasonable best efforts to consummate the exchange offer by March 12, 2016. Additionally, we agreed to commence the exchange offer promptly after the exchange offer registration statement is declared effective by the SEC and use our reasonable best efforts to complete the exchange offer not later than 60 days after such effective date. Under certain circumstances, in lieu of a registered exchange offer, we have agreed to file a shelf registration statement with respect to the Second Lien Notes. If the exchange offer is not completed on or before March 12, 2016, or the shelf registration statement, if required, is not declared effective within the time periods specified in the Registration Rights Agreement, we have agreed to pay additional interest with respect to the Second Lien Notes in an amount of 0.25% of the principal amount of the Second Lien Notes per year for the first 90 days following such failure, increasing by 0.25% for each additional 90 days and not to exceed 1.00% of the principal amount per year, until the exchange offer is completed or the shelf registration statement is declared effective.  As of the date of this filing, neither an exchange offer nor shelf registration statement for the Second Lien Notes has been filed with the SEC.

We separately accounted for the liability and equity components of our Second Lien Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. We measured the debt component of the Second Lien Notes using a discount rate of 32% on the date of issuance. We attributed $84.6 million of the Second Lien Notes relative fair value to the debt component, which compared to the face value results in a debt discount of $15.4 million. Additionally, we recorded $15.4 million within additional paid-in capital representing the equity component of the Second Lien Notes. The debt

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

discount will be amortized using the effective interest rate method through September 1, 2017 along with the applicable debt issuance costs.  A debt discount of $12.5 million remains to be amortized on the Second Lien Notes as of September 30, 2015.

8.875% Senior Notes due 2019

On March 2, 2011, we sold $275 million of our 2019 Notes. The 2019 Notes mature on March 15, 2019, unless earlier redeemed or repurchased. The 2019 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future unsecured indebtedness. The 2019 Notes accrue interest at a rate of 8.875% annually, and interest is paid semi-annually in arrears on March 15 and September 15. The 2019 Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.

On October 1, 2015, we closed a privately-negotiated exchange under which we retired, in two tranches, $158.2 million in aggregate original principal amount of our outstanding 2019 Notes in exchange for the issuance of $75.0 million in aggregate original principal amount of our 8.875% Second Lien Senior Secured Notes due 2018 (the “New Second Lien Notes”) and 38,250 warrants. Each warrant is entitled to purchase approximately 156.9 shares of our $0.20 par value common stock for $1.00 per share. The New Second Lien Notes will mature on March 15, 2018. See Note 9 “Subsequent Event”. Following this exchange, approximately $116.8 million aggregate original principal amount of the 2019 Notes remain outstanding with terms unchanged.

We may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to approximately (i) 104% for the twelve-month period beginning on March 15, 2015; (ii) 102% for the twelve-month period beginning on March 15, 2016 and (iii) 100% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date.

The indenture governing the 2019 Notes restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem or retire such capital stock; (iii) sell assets, including the capital stock of our restricted subsidiaries; (iv) pay dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing, many of these covenants will terminate.

5.0% Convertible Senior Notes due 2029

In September 2009, we sold $218.5 million of our 2029 Notes. The 2029 Notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. We exchanged $166.7 million of the 2029 Notes for the 2032 Notes in 2013.  On October 1, 2014, we repurchased $45.1 million of the 2029 Notes using restricted cash held in escrow for that purpose.  The 2029 Notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of 2029 Notes (equal to an initial conversion price of approximately $34.66 per share of common stock).  As of September 30, 2015, $6.7 million in aggregate principal amount of the 2029 Notes remain outstanding.

The 2029 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future unsecured indebtedness. The 2029 Notes accrue interest at a rate of 5.0% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year.

Investors may convert their 2029 Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances: (i) during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of our common stock is greater than or equal to 135% of the conversion price of the 2029 Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter; (ii) if the 2029 Notes have been called for redemption or (iii) upon the occurrence of one of specified corporate transactions. Investors may also convert their 2029 Notes at their option at any time beginning on September 1, 2029, and ending at the close of business on the second business day immediately preceding the maturity date.

We separately accounted for the liability and equity components of our 2029 Notes in a manner that reflected our nonconvertible debt borrowing rate when interest was recognized in subsequent periods. The debt discount was amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount on the 2029 Notes was fully amortized as of December 31, 2014.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

5.0% Convertible Senior Notes due 2032

As described above, we entered into separate, privately negotiated exchange agreements in which we retired $166.7 million in aggregate principal amount of our outstanding 2029 Notes in exchange for the issuance of the 2032 Notes in an aggregate principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032.

On September 8, 2015, we closed a privately-negotiated exchange under which we retired $55.0 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of a new series of 5.0% Convertible Exchange Senior Notes due 2032 (the "2032 Exchange Notes") in an aggregate original principal amount of approximately $27.5 million. As of September 30, 2015, $111.3 million in aggregate principal amount of the 2032 Notes remained outstanding with terms unchanged. See the description of the 2032 Exchange Notes below. Also, see Note 10 for discussion on additional 2032 Note exchanges subsequent to September 30, 2015.

Many terms of the 2032 Notes remain the same as the 2029 Notes they replaced, including the 5.0% annual cash interest rate and the conversion rate of 28.8534 shares of our common stock per $1,000 principal amount of 2032 Notes (equivalent to an initial conversion price of approximately $34.6580 per share of common stock), subject to adjustment in certain circumstances.

Unlike the 2029 Notes, the principal amount of the 2032 Notes accretes at a rate of 2% per year commencing August 26, 2013, compounding on a semi-annual basis, until October 1, 2017. The accreted portion of the principal is payable in cash upon maturity but does not bear cash interest and is not convertible into our common stock. Holders have the option to require us to purchase any outstanding 2032 Notes on each of October 1, 2017, 2022 and 2027, at a price equal to 100% of the principal amount plus the accretion thereon. Accretion of principal is and will be reflected as a non-cash component of interest expense on our consolidated statement of operations during the term of the 2032 Notes. We recorded $0.8 million and $2.5 million of accretion in the three and nine months ended September 30, 2015, respectively.

We have the right to redeem the 2032 Notes on or after October 1, 2016 at a price equal to 100% of the principal amount, plus accrued but unpaid interest and accretion thereon. The 2032 Notes also provide us with the option, at our election, to convert the new notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds $45.06 (or 130% of the then applicable conversion price) for the required measurement period. If we elect to convert the 2032 Notes on or before October 1, 2016, holders will receive a make-whole premium.

We separately accounted for the liability and equity components of our 2032 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. We measured the debt component of the 2032 Notes using an effective interest rate of 8%. We attributed $158.8 million of the fair value to the 2032 Note debt component which compared to the face results in a debt discount of $7.5 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $24.4 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $2.6 million remains to be amortized on the 2032 Notes as of September 30, 2015.

5.0% Convertible Senior Exchange Notes due 2032

 

On September 8, 2015, we closed a privately-negotiated exchange under which we retired $55.0 million in principal amount of outstanding 2032 Notes in exchange for our issuance of approximately $27.5 million in aggregate original principal amount of 2032 Exchange Notes.  Many terms of the 2032 Exchange Notes remain the same as the 2032 Notes they replaced, including the 5.0% annual cash interest rate and the final maturity date of October 1, 2032.

 

Investors may convert their 2032 Exchange Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances: (1) if the 2032 Exchange Notes have been called for redemption or the Company exercises its option to convert the 2032 Exchange Notes, or (2) upon the occurrence of one of specified corporate transactions. The conversion rate is 500.00 shares per $1,000 principal amount of the 2032 Exchange Notes (equal to an initial conversion price of $2.00 per share of common stock), subject to adjustment.

 

Like the 2032 Notes, the principal amount of the 2032 Exchange Notes will accrete at a rate of 2% per year from August 26, 2013, compounding on a semi-annual basis, until October 1, 2018. The accreted portion of the principal is payable in cash upon maturity but does not bear cash interest and is not convertible into our common stock. Holders have the option to require us to purchase any outstanding 2032 Exchange Notes on each of October 1, 2018, October 1, 2022 and October 1, 2027, at a price equal to 100% of the accreted principal amount thereof, plus accrued and unpaid interest on the original principal amount thereof.  We have the

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

right to redeem the 2032 Exchange Notes on or after October 1, 2017, at a price equal to 100% of the accreted principal amount thereof, plus accrued but unpaid interest on the original principal amount thereof. The 2032 Exchange Notes also provide us with the option to convert the 2032 Exchange Notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds 125% of the then applicable conversion price for at least 20 trading days in any 30 trading day period. The initial conversion rate is 500 shares of common stock per $1,000 principal amount of 2032 Exchange Notes, subject to adjustment. Upon conversion, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the indenture related to the 2032 Exchange Notes, or (2) a combination of cash and shares of our common stock, if any.

 

If the holders elect to convert the 2032 Exchange Notes on or before October 1, 2018, holders will receive a make-whole premium equal to (i) $100 per $1,000 face amount of the 2032 Exchange Notes if the conversion occurs prior to October 1, 2017 or (ii) $100 per $1,000 face amount of the 2032 Exchange Notes less an amount equal to 0.2778 multiplied by the number of days between September 30, 2017 and the conversion date, if the conversion occurs on or after October 1, 2017.

 

We are accounting for this transaction as a troubled debt transaction pursuant to guidance provided by FASB Accounting Standards Codification (“ASC”) section 470-60 “Troubled Debt Restructurings by Debtors.”  We have determined that the prospective undiscounted cash flows from the 2032 Exchange Notes through their maturity exceed the adjusted carrying amount of the retired 2032 Notes, consequently no gain for this exchange will be recorded. Accordingly, on the date of the exchange, a carrying amount of $45.2 million remained as a liability and we recorded $10.1 million to additional paid in capital representing the net fair value of the convert feature. An annual discount rate of 1.3% will be used to amortize the liability until maturity on October 1, 2032.  Prior to September 30, 2015, holders converted an aggregate amount of $5.7 million of 2032 Exchange Notes into our common stock. As of September 30, 2015, $39.5 million aggregate principal amount of the 2032 Exchange Notes remained outstanding.

3.25% Convertible Senior Notes Due 2026

At September 30, 2015, $0.4 million of the 2026 Notes remained outstanding. Holders may present to us for redemption the remaining outstanding 2026 Notes on December 1, 2016 and December 1, 2021.

Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem in cash or in certain circumstances redeem in a combination of cash and shares.

The 2026 Notes are convertible into shares of our common stock at a rate equal to the sum of:

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 4—Net Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the three and nine months ended September 30, 2015 and 2014. Included in Net loss applicable to common stock for the three and nine months ended September 30, 2015 is $7.4 million of preferred dividends that have been suspended in the third quarter of 2015. The suspended dividend amount is included in the 2015 Net loss applicable to common stock calculation for period-to-period comparison purposes only. The following table sets forth information related to the computations of basic and diluted loss per share:

 

 

 

NOTE 5—Income Taxes

We recorded no income tax expense or benefit for the three and nine months ended September 30, 2015. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed, and as a result we continue to maintain a full valuation allowance for our net deferred assets as of September 30, 2015.

As of September 30, 2015, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2014.

 

 

NOTE 6—Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. We are currently not designating our derivative contracts for hedge accounting. All derivative gains and losses from our derivative contracts have been recognized in “Other income (expense)” on our Consolidated Statements of Operations.

The following table summarizes gains and losses we recognized on our oil and natural gas derivatives for the three and nine month periods ended September 30, 2015 and 2014.

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 hedges are approved by the Hedging Committee of our Board of Directors, and reviewed periodically by the Board of Directors. As of September 30, 2015, the commodity derivatives we used were in the form 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 counterparties. Neither our counterparties nor we require any collateral upon entering derivative contracts. We had exposure of $15.3 million in derivative fair value had our counterparties as a group been unable to fulfill their obligations as of September 30, 2015.

As of September 30, 2015, our open positions on our outstanding commodity derivative contracts, all of which were with Royal Bank of Canada, Bank of Montreal, JPMorgan Chase Bank, N.A., Merrill Lynch Commodities, Inc. and Wells Fargo Bank, N.A., were as follows:

 

 

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of September 30, 2015 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 “Description of Business and Significant Accounting Policies-Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

We enter into oil and natural gas derivative contracts under which we have netting arrangements with each 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, 2015 and December 31, 2014.

 

 

 

NOTE 7—Stockholders’ Equity

Common Stock Offering

On March 10, 2015, we closed an underwritten public offering of 12 million shares of our common stock at $ 4.15 per share.  Proceeds after offering expenses totaled approximately $47.5 million. The proceeds were used to repay borrowings under our Senior Credit Facility and for general corporate purposes.

Warrants

In connection with the issuance of the Second Lien Notes, we issued a detachable warrant for each $1,000 note. The holder of a warrant has the right to purchase 48.84 shares of our $0.20 par value common stock. The warrants were issued pursuant to a Warrant Agreement, dated March 12, 2015 (the “Warrant Agreement”), with American Stock Transfer & Trust Company LLC. Under the terms of the Warrant Agreement, the Second Lien Notes and the warrants were not separately transferable until the earliest of (i) 365 days after the date on which the warrants were originally issued; (ii) the date on which a registration statement related to the resale of the warrants was declared effective; (iii) the date on which a registration statement with respect to a registered exchange offer for the Second Lien Notes was declared effective; or (iv) in the event of the occurrence of a change of control (as defined in the governing indenture), the date on which requisite notice of such change of control was mailed to the holders of Second Lien Notes. Also, on March 12, 2015, we entered into a Registration Rights Agreement with the Purchaser that provides holders of the warrants certain rights to registration under the Securities Act relating to the Warrants.  Pursuant to the Warrant Registration Rights Agreement, we were obligated to file a shelf registration statement with the SEC within 90 days of March 12, 2015, relating to re-sales of the Warrants.

A Form S-3 was filed with the SEC on May 22, 2015 to register the resale of the warrants and the common stock issuable upon the conversion of such warrants. The Second Lien Notes and warrants became separately transferable on June 4, 2015 when the Form S-3 registration statement related to the resale of the warrants was declared effective by the SEC. The warrants are exercisable upon payment of the exercise price of $4.664 or convertible on a cashless basis as set forth in the agreement governing the warrants. Any warrants not exercised by March 12, 2025 will expire.

Upon issuance, we valued the warrants as a separate financial instrument using the Black-Scholes model and recorded the $15.4 million relative fair value to Additional paid in capital on the Consolidated Balance Sheets.

Conversions to Common Stock

In September 2015, we issued 1.7 million shares of our common stock to holders that exercised their conversion rights on $3.5 million face amount of the 2032 Exchange Notes. We recorded the $5.7 million carrying amount of the converted 2032 Exchange Notes to stockholders equity. See Note 3.

Preferred Stock Dividends

Beginning in the third quarter of 2015 all preferred stock dividend declarations and payments have been suspended.  If we fail to pay dividends on our 5.375% Series B Convertible Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Preferred Stock for all dividend

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.  If we fail to pay dividends for six or more quarterly periods, whether or not consecutive, on our 10% Series C Cumulative Preferred Stock or 9.75% Series D Cumulative Preferred Stock the holders will receive limited voting rights.

 

 

NOTE 8—Commitments and Contingencies

On June 10, 2015, we entered into an eighteen month term agreement with a third party vendor which obligated us to purchase $11.4 million in pipe. We will receive and pay for approximately $0.6 million of pipe each month during the term of the agreement. Our obligation may be reduced subject to the vendor identifying an opportunity to sell the pipe to the open market.  We have taken delivery of four shipments under this agreement and an $8.6 million commitment remained at September 30, 2015.

As of September 30, 2015, we did not have any other changes in material commitments and contingencies, which includes outstanding and pending litigation.

 

 

NOTE 9 – Disposition

On September 4, 2015 we closed the sale of our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale Trend located in La Salle and Frio counties in Texas for $118.0 million. We received net proceeds of $101.6 million after closing adjustments based upon an effective date of July 1, 2015. We used the net proceeds from the sale to repay borrowings under our Senior Credit Facility. As of September 30, 2015, $14.4 million remains in escrow subject to title resolution. We recorded a $42.8 million gain on the sale in the third quarter of 2015.

 

NOTE 10 – Subsequent Events

On October 1, 2015, we closed on a separate privately-negotiated exchange under which we retired approximately $158.2 million in aggregate original principal amount of our outstanding 2019 Notes in exchange for the issuance of $75.0 million in aggregate original principal amount of our New Second Lien Notes and 38,250 warrants. Each warrant is entitled to purchase approximately 156.9 shares of our $0.20 par value common stock for $1.00 per share.

We will account for this transaction as a troubled debt transaction pursuant to guidance provided by FASB ASC 470-60 “Troubled Debt Restructurings by Debtors”. We have determined that the prospective undiscounted cash flows from the New Second Lien Notes do not exceed the adjusted carrying amount of the retired 2019 Notes, consequently we will record an estimated $62.6 million gain on this transaction in the fourth quarter of 2015. We will also record an estimated $2.5 million in Additional Paid in Capital in the fourth quarter of 2015 representing the fair value of the warrants issued.

On October 14, 2015, we closed a privately-negotiated exchange under which we retired approximately $17.1 million in aggregate original principal amount of our outstanding 2032 Notes in exchange for our issuance of additional 2032 Exchange Notes in an aggregate original principal amount of approximately $8.5 million. We will account for this transaction as a troubled debt transaction pursuant to guidance provided by FASB ASC 470-60 “Troubled Debt Restructurings by Debtors”. See Note 3 “Debt” under the caption “5.0% Convertible Senior Exchange Notes due 2032.”

 

 

 

 

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

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, 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 risk and uncertainties:

 

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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, 2014.

Overview

We are an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas properties primarily in (i) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), (ii) South Texas, which includes the Eagle Ford Shale Trend and (iii) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend.

We seek to increase shareholder value by growing our oil and natural gas reserves, production revenues and operating cash flow. In our opinion, on a long term basis, growth in oil and natural gas reserves 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 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 cash flow from operating activities (“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 employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.

Beginning in the second half of 2014, commodity prices, particularly crude oil, began to decline sharply. The decline became precipitous late in the fourth quarter of 2014 and into 2015.  As discussed below, the significant magnitude of this price decline has materially and adversely impacted our results of operations and led to substantial changes in our operating and drilling programs for the second half of 2015.  As a result, we have focused on managing our balance sheet to reduce leverage and preserve liquidity during the current low commodity price environment.

Business Strategy

Our business strategy is to provide long-term growth in reserves and cash flow on a cost-effective basis. We focus on maximizing our return on capital employed and adding reserve value through the timely development of our Haynesville Shale Trend, TMS and Eagle Ford Shale Trend acreage. We regularly evaluate possible acquisitions of prospective acreage and oil and natural gas drilling opportunities.

Several of the key elements of our business strategy are as follows:

 

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Overview of Third Quarter 2015 Results

Third Quarter 2015 financial and operating results included:

Primary Operating Areas

Tuscaloosa Marine Shale Trend

We held approximately 429,000 gross (300,000 net) acres in the TMS as of September 30, 2015. During the nine months of 2015, we conducted drilling operations on 5 gross (3.9 net) wells in the TMS. As of September 30, 2015, we had 2 gross (1.7 net) TMS wells drilled and waiting on completion. Our net production volumes from our TMS wells represented approximately 34% of our total equivalent production on a Boe basis and approximately 69% of our total oil production for the third quarter of 2015.

During the first nine months of 2015, we spent $70.3 million in the TMS, which included $3.3 million for leasehold costs.

Eagle Ford Shale Trend

We closed the sale of our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015. Immediately prior to the sale, our net production volumes from these sold properties represented approximately 28% of our total equivalent production volumes for 2015 on a Boe basis. We have retained approximately 17,000 net acres of our undeveloped leasehold, all of which is prospective for future development or sale.

Haynesville Shale Trend

Our relatively low risk development acreage in this trend is primarily centered in Angelina and Nacogdoches counties, Texas and DeSoto and Caddo Parishes, Louisiana. We held approximately 55,000 gross (27,000 net) acres as of September 30, 2015

 

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producing from and prospective for the Haynesville Shale Trend. Our net production volumes from our Haynesville Shale Trend wells represented approximately 46% of our total equivalent production on a Boe basis for the third quarter of 2015.

Results of Operations

For the three months ended September 30, 2015, we reported net loss applicable to common stock of $25.2 million, or $0.44 per basic and diluted share, on total revenue of $17.7 million as compared to a net loss applicable to common stock of $87.1 million, or $1.96 per basic and diluted share, on total revenue of $54.9 million for the three months ended September 30, 2014.

For the nine months ended September 30, 2015, we reported net loss applicable to common stock of $92.8 million, or $1.70 per basic and diluted share, on total revenue of $67.9 million as compared to a net loss applicable to common stock of $149.6 million, or $3.37 per basic and diluted share, on total revenue of $160.0 million for the nine months ended September 30, 2014.

The items that had the most material financial effect on us in the three and nine months ended September 30, 2015 compared to the same periods in 2014 were revenues, depreciation, depletion and amortization, impairment and gain on sale of assets.  Revenues were down due to significantly lower realized oil and natural gas sales prices as well as lower oil, condensate and natural gas production volumes.  The decreases reflected in depreciation, depletion and amortization were driven by lower rates, the sale of non-core assets in December 2014 and lower natural gas production volumes. In the third quarter 2015 we recorded an impairment related to certain natural gas properties which was offset by a gain on the sale of our producing interests in the Eagle Ford Shale Trend.

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.

 

 

Revenues from Operations

Revenues from operations decreased by $37.1 million for the three months ended September 30, 2015 compared to the same period in 2014, reflecting lower average realized natural gas, oil and condensate sales prices, which decreased revenues by $28.6 million, while the decline in oil and natural gas production volumes decrease revenues by $8.2 million. We were focused on maintaining our oil production in 2015, which we were able to sell at a more favorable price relative to natural gas. For the three

 

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months ended September 30, 2015, 81% of our oil and natural gas revenue was attributable to oil sales compared to 77% for the three months ended September 30, 2014.

Revenues from operations decreased by approximately $92.1 million for the nine months ended September 30, 2015 compared to the same period in 2014, reflecting lower average realized natural gas, oil and condensate sales prices, which decreased revenues by $80.0 million, while a decrease in oil and natural gas production volumes decreased revenues by $11.7 million. For the nine months ended September 30, 2015, 83% of our oil and natural gas revenue was attributable to oil sales compared to 71% for the nine months ended September 30, 2014.

Operating Expenses

As described below, operating expenses decreased $114.5 million to $27.8 million, in the three months ended September 30, 2015 and decreased $150.8 million to $102.3 million in the nine months ended September 30, 2015, each compared to the same periods in 2014.

 

 

Lease Operating Expense

Lease operating expense (“LOE’) during the three month period ended September 30, 2015 decreased compared to the three months ended September 30, 2014. The decrease was the result of a $2.1 million decrease in operating costs stemming from the sale of our non-core East Texas natural gas fields in December 2014, a $1.1 million decrease from our Eagle Ford Shale Trend properties sold in September 2015 and a $0.4 million decrease from our Haynesville Shale Trend properties. These decreases were partially offset by a $0.9 million increase in operating costs associated with the continued development of the TMS in 2015. Workover expense in the third quarter of 2015 totaled $0.5 million which added $0.75 per Boe to unit expense compared to workover expense of $0.6 million in the third quarter of 2014 which added $0.59 per Boe to unit expense.

LOE for the nine months ended September 30, 2015 decreased in comparison to the same period in 2014. The decrease was the result of a $6.1 million decrease in operating costs stemming from the sale of our non-core East Texas natural gas fields in December 2014, a $4.0 million decrease from Eagle Ford Shale Trend properties sold in September 2015 and a $1.1 million decrease from our Haynesville Shale Trend properties.  These decreases were partially offset by a $2.2 million increase in operating costs associated with the continued development of the TMS in 2015.  LOE in the first nine months of 2015 included workover expense of $1.3 million which added $0.59 per Boe to unit expense compared to workover expense of $3.9 million in the first nine months of 2014 which added $1.25 per Boe to unit expense.

Production and Other Taxes

Production and other taxes for the three months ended September 30, 2015 included production tax of $0.6 million and ad valorem tax of $0.7 million. During the comparable period in 2014, production and other taxes included production tax of $1.9 million and ad valorem tax of $1.0 million.

Production and other taxes for the nine months ended September 30, 2015 included production tax of $2.0 million and ad valorem tax of $2.1 million. During the comparable period in 2014, production and other taxes included production tax of $5.0 million and ad valorem tax of $2.3 million.

 

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Production and other taxes decreased in the third quarter of 2015 due to significantly lower crude oil prices during the three and nine months ended September 30, 2015, lower oil production from our Eagle Ford Shale Trend wells and lower tax rates on the TMS wells we have drilled. The State of Mississippi has enacted an exemption from the existing 6% severance tax for horizontal wells drilled after July 1, 2013 with production commencing before July 1, 2018, which will be 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) until payout of the well cost is achieved. The State of Louisiana has also enacted an exemption from the existing 12.5% severance tax 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) until payout of the well cost is achieved. The net revenues from our wells drilled in our TMS acreage in Southwestern Mississippi and Southeast Louisiana have been favorably impacted by these exemptions.

Transportation and Processing Expense

Transportation and processing expense decreased in the three months and nine months ended September 30, 2015 compared to the same period in 2014. The decrease is due to lower operated natural gas production, as our natural gas production incurs substantially all of our transportation and processing cost. The lower natural gas production is directly associated with the sale of our non-core East Texas natural gas fields in December 2014.

Exploration

The increase in exploration expense for the three months and nine months ended September 30, 2015 compared to the same periods in 2014 is attributable to an increase in leasehold amortization costs related to non-cash lease expirations in our TMS and Eagle Ford Shale Trend acreage.  

 

 

* – Not meaningful.

Depreciation, Depletion and Amortization (“DD&A”)

DD&A expense for the three and nine months ended September 30, 2015 decreased as compared to the same periods in 2014 due to a decrease in DD&A rates for our Eagle Ford Shale Trend, the absence of our non-core East Texas assets that were sold in December 2014 and lower production from our core natural gas assets.  These decreases were partially offset by the increase in volumes associated with the continued development of the TMS in 2015.

Impairment

We recorded impairment expense of $32.5 million in the three and nine months ended September 30, 2015.  The impairment was recorded in relation to a decline in estimated proved reserves for certain of our natural gas producing properties as of September 30, 2015. In addition, we recorded $85.3 million of impairment expense during the third quarter of 2014 for properties that were sold in December 2014.

General and Administrative (“G&A”) Expense

G&A expense decreased in the three and nine months ended September 30, 2015 compared to the same period in 2014. The decrease stems from lower compensation expense, professional fees and share based compensation. We have reduced our staff headcount by more than 30% from year-end 2014 levels.  The higher rate per Boe for the nine months ended September 30, 2015,

 

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reflects a 30% reduction in oil and natural gas production during 2015. Share-based compensation expense, which is a non-cash item, amounted to $0.9 million for the three months ended September 30, 2015, a $1.1 million decrease over the same period in 2014. For the nine months ended September 30, 2015, share-based compensation totaled $4.7 million, a $2.0 million decrease over the same period in 2014.

Other Expense

Other expense for the prior year nine month period ended September 30, 2014 includes a $2.8 million charge for gathering and marketing cost on non-operated Haynesville Shale wells. In addition, a $0.6 million charge was recorded in relation to a decision handed down by the Louisiana Court of Appeals regarding a long standing working interest dispute on a property we no longer own.

Other Income (Expense)

 

 

Interest Expense

Our interest expense increased in the three and six months ended September 30, 2015 compared to the same periods in 2014 primarily as a result of the issuance of $100 million in Second Lien Notes in March 2015 and the direct cost paid to third parties in September, 2015 for the 5.0% Convertible Senior Notes due 2032 exchange transaction.  The increase was partially offset by a decrease in cash and non-cash interest expense attributable to our repurchase of $45.1 million of the 2029 Notes on October 1, 2014.  Non-cash interest expense for the three months ended September 30, 2015 totaled $4.7 million compared to $2.7 million in the same period in 2014. Non-cash interest of $10.5 million is included in interest expense reported for the nine month period in 2015 compared to $8.0 million in the 2014 comparative period. The increase in both periods reflects the debt discount amortization on the Second Lien Notes.

Gain (loss) on Derivatives Not Designated as Hedges

Gain on derivatives not designated as hedges for the three months ended September 30, 2015 includes an unrealized loss of $5.8 million for the change of the fair value of our oil and natural gas derivative contracts and net cash receipts of $13.7 million on the settlement of our oil derivatives. There were no natural gas derivative contract settlements during the period.  The unrealized loss consisted of a $6.1 million loss on our oil derivatives offset by a $0.3 million unrealized gain on our natural gas derivatives. The decrease in fair value of our oil derivatives reflects the realization of settled contracts and the gain on the natural gas derivative is reflective of the contracts that are expiring.

Gain on derivatives not designated as hedges for the three months ended September 30, 2014 includes an unrealized gain of $20.1 million for the change of the fair value of our oil and natural gas derivative contracts and net cash receipts of $0.2 million on the settlement of our oil and natural gas derivatives. The unrealized gain consisted of a $19.4 million gain on our oil derivatives and a $0.7 million gain on our natural gas derivatives. The unrealized gain on oil and natural gas derivatives reflects the decrease in futures prices for the period.

Gain on derivatives not designated as hedges for the nine months ended September 30, 2015 includes an unrealized loss of $31.7 million for the change of the fair value of our oil and natural gas derivative contracts and net cash receipts of $38.0 million on the settlement of our oil derivatives. There were no natural gas derivative contract settlements during the period.  The unrealized loss consisted of a $0.5 million gain on our natural gas derivatives and a $32.2 million loss on our oil derivatives. The decrease in fair value of our oil derivatives reflects the realization of settled contracts and the gain on the natural gas derivative is reflective of the contracts that are expiring during 2015.

Gain on derivatives not designated as hedges for the nine months ended September 30, 2014 includes an unrealized gain of $7.6 million for the change of the fair value of our oil and natural gas derivative contracts and net cash payments of $5.6 million on the

 

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settlement of our oil and natural gas derivatives. The unrealized gain consisted of an $11.4 million gain on our oil derivatives and a $3.8 million loss on our natural gas derivatives. The unrealized gain on oil derivatives reflects the decrease in futures prices for the period.

We will continue to be exposed to volatility in earnings in 2015 resulting from changes in the fair value of our commodity contracts as we do not designate these contracts as hedges.  All of our oil derivative contracts will expire on December 31, 2015.

Income Tax Benefit

We recorded no income tax benefit for the three and nine months ended September 30, 2015. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of September 30, 2015.

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-US GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as earnings before interest expense, income tax, DD&A, exploration expense, stock compensation expense and impairment of oil and natural gas properties. In calculating Adjusted EBITDAX, gains/losses on derivatives, less net cash received or paid in settlement of commodity derivatives are excluded from Adjusted EBITDAX. Other excluded items include Interest income and other, Gain/loss on sale of assets, Gain/loss on early extinguishment of debt and Other expense. Adjusted EBITDAX is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDAX should not be considered an alternative to net income (loss), as defined by US GAAP. The following table presents a reconciliation of the non-US GAAP measure of Adjusted EBITDAX to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP.  

 

 

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. Our computations of Adjusted EBITDAX may not be comparable to other similarly totaled measures of other companies.

Liquidity and Capital Resources

Overview

Our primary sources of cash during the third quarter of 2015 were proceeds from the sale of our Eagle Ford Shale Trend producing properties and cash flow from our operating activities. We used cash primarily to fund our capital spending program, repay bank borrowings and pay interest on outstanding debt. We do not plan to have any material capital expenditures for the remainder of 2015 and will fund our operations through a combination of cash on hand and cash from operating activities.

We have in place a Senior Credit Facility with a syndicate of U.S. and international lenders. As of September 30, 2015, we had a $105 million borrowing base with $17.5 million in outstanding borrowings and $4.0 million of cash. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. Our borrowing base

 

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was reduced to $75 million on October 1, 2015 in conjunction with the exchange of $158.2 million of our 2019 Notes for the issuance of $75.0 million of 8.875% Second Lien Notes due 2018 and the Fourteenth Amendment to the Senior Credit Facility. Under the Fifteenth Amendment to the Senior Credit Facility we obtained, among other items, financial covenant revisions. Our next borrowing base redetermination is set for January 1, 2016.

Outlook

We are an exploration and production Company with interests in non-conventional oil and natural gas shale properties that require large investments of capital to develop.  Our immediate capital resources to develop our properties come from cash on hand, operating cash flows and borrowings on our Senior Credit Facility. The current significant decline in crude oil prices and to a lesser extent the continued depressed natural gas prices has negatively impacted our cash flows that enable us to invest in and maintain our properties and service our long term obligations.

We have taken the following steps in 2015 to mitigate the effects of lower crude oil prices on our operations and conserve capital:

We have taken the following steps in 2015 to enhance liquidity:

Given the current downturn in oil and natural gas prices, we expect to continue to face liquidity constraints.  Our cash flows are negatively impacted by lower realized oil and natural gas sales prices.  Through the end of 2015, we have in place derivative positions covering all of our anticipated oil and condensate sales volumes. See Note 6 – “Derivative Activities” in the Notes to the Consolidated Financial Statements in Part I Item 1 of this Quarterly Report on Form 10-Q for more information. However, given the current oil futures pricing, we currently have limited hedging opportunities after year end and therefore, in 2016, we do not anticipate having in place any derivative positions with respect to our 2016 anticipated oil and condensate sales volumes and thus expect further deteriorating realized sale prices if oil prices do not improve.

The recent significant decline in oil and natural gas prices also increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market.  A prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserve portfolio.  The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the SEC-mandated 2014 beginning of the prior 12 months average prices used for our December 31, 2014 reserve report had been replaced with the NYMEX strip prices for the applicable commodity as of September 30, 2015 (without regard to our commodity derivative positions and without assuming any change in development plans or costs, which has historically not been the case in periods of prolonged depressed commodity prices), then the estimated proved reserves volumes as of December 31, 2014 would have decreased

 

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by approximately 35%. The prices assumed in this example were derived using NYMEX strip prices at September 30, 2015 through December 31, 2021 and then held flat thereafter. We believe that the use of this NYMEX strip price may help provide investors with an understanding of the impact of sustained lower commodity price conditions on our proved reserves through an assumed period. However, the use of this pricing example does not necessarily indicate management’s overall view on future commodity prices. In addition, if revisions of proved reserves occur in the future, we could have further increases in our DD&A rates. We are unable to predict the timing and amount of future reserve revisions, nor the impact such revisions may have on our future DD&A rates.

Capital Resources

We have additional resource options to enhance liquidity as well, such as:

As a result of the steps we have taken to conserve capital and enhance our liquidity, we anticipate our cash on hand, cash from operations and our available borrowing capacity under our Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements in 2016. We may be reliant on the availability of borrowings under our Senior Credit Facility to accomplish our operation and capital expenditure plan in 2016 and beyond.  A sustained drop from current commodity price levels will result in financial results that could violate a financial covenant despite the flexibility we have obtained under the revised debt covenants. This could prevent us from accessing our borrowings available under the Senior Credit Facility.

Cash Flows

The following table presents our comparative cash flow summary for the periods reported (in thousands):

 

 

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. Changes in working capital also impact cash flows. Net cash used in operating activities for the nine months ended September 30, 2015 was $11.9 million, a decrease of $107.0 million from the nine months ended September 30, 2014. Operating cash flows before working capital changes decreased $29.0 million for the nine months ended September 30, 2015 compared to the same period in 2014 reflecting the absence of cash flows from natural gas properties sold in December 2014, lower commodity prices and to a lesser extent, the absence of cash flows from our Eagle Ford Shale Trend properties that we sold in September 2015.  The decrease in cash flows of $78.0 million from the change in working capital for the nine months ended September 30, 2015 compared to the same period in 2014 resulted from the timing of payments in winding down our drilling activity.

Investing activities: Net cash used in investing activities was $9.1 million for the nine months ended September 30, 2015, compared to $237.7 million for the nine months ended September 30, 2014. While we recorded capital expenditures of approximately $81.9 million in the nine months ended September 30, 2015, we paid out cash amounts totaling $114.0 million in the nine months ended September 30, 2015. The difference is attributed to $33.8 million accrued at December 31, 2014 and paid in the nine months ended September 30, 2015 offset by $1.7 million in drilling and completion costs accrued at September 30, 2015. Capital expenditures in the first nine months of 2015 were offset by the receipt of $104.8 million in net proceeds, primarily from the sale of our Eagle Ford Shale Trend assets in September 2015.

 

 

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Financing activities: Net cash provided in financing activities for the nine months ended September 30, 2015 consisted of net proceeds from the issuance of Second Lien Notes of $100 million and net proceeds from the sale of common stock of $47.5 million partially offset by net repayments of borrowings under the Senior Credit Facility of $103.5 million, preferred stock dividends of $14.9 million and debt issuance cost of $3.6 million. We had $17.5 million in borrowings outstanding under our Senior Credit Facility as of September 30, 2015. In the nine months ended September 30, 2014, net cash provided in financing activities consisted of net proceeds from borrowings under our Senior Credit Facility of $118.0 million, partially offset by preferred stock dividends of $22.3 million.

Debt consisted of the following balances as of the dates indicated (in thousands):

 

    

 

 

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The following table summarizes the total interest expense (contractual interest expense, accretion, amortization of debt discount and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates):  

* - Not meaningful

For additional information on our financing activities, see Note 3 – “Debt” in the Notes to Consolidated Financial Statements under Part 1, Item I of this Form 10-Q.

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 generally accepted accounting principles in the United States. 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, 2014, includes a discussion of our critical accounting policies and there have been no material changes to such policies during the nine months ended September 30, 2015.

 

 

Item 3—Quantitative and Qualitative Disclosures about Market Risk

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 of Directors. 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 counterparties in order to satisfy these margin requirements.

For information regarding our accounting policies and additional information related to our derivative and financial instruments, see Note 1—“Description of Business and Significant Accounting Policies”, Note 3—“Debt” and Note 6—“Derivative Activities” in the Notes to Consolidated Financial Statements under Part 1, Item I of this Quarterly Report on Form 10-Q.

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

 

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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. Below is a sensitivity analysis of our commodity-price-related derivative instruments.

As of September 30, 2015 we had derivative instruments in place for 2015 of 3,500 Bbls per day (crude oil) and 20,000 MMBtu per day (natural gas). At September 30, 2015, we have a net asset derivative position of $15.2 million related to these derivative instruments. Utilizing actual derivative contractual volumes a hypothetical 10% increase in oil and natural gas prices would have reduced our net asset derivative position to $13.75 million, while a hypothetical 10% decrease in oil and natural gas prices would have increased our net derivative asset to $16.7 million. However, a gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instruments.

Adoption of Comprehensive Financial Reform

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 “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

 

Item 4—Controls and Procedures

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 Securities Exchange Act of 1934, as amended (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 Interim 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 Interim Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Interim Chief Financial Officer, based upon their evaluation as of September 30, 2015, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.

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.

 

 

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PART II—OTHER INFORMATION

 

Item 1—Legal Proceedings

A discussion of current legal proceedings is set forth in Part I, Item 1 under Note 8—“Commitments and Contingencies” to the Notes to Consolidated Financial Statements in this Form 10-Q.

 

Item 1A—Risk Factors

In addition to the risk factors below and 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, 2014 and Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, 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.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. For example, Chesapeake Energy Corp operates certain properties in the Haynesville Shale. As of December 31, 2014, approximately 28% of our reserves were attributable to non-operated properties.  Additionally, for the nine months ended September 30, 2015, approximately 28% of our production was attributable to non-operated properties.  We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.

A sustained depression of oil and natural gas prices can affect our ability to obtain funding, obtain funding on acceptable terms or obtain funding under our current credit facility. This may hinder or prevent us from meeting our future capital needs.

We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

Because our operations require significant capital expenditures, we may not have the funds available to replace reserves, maintain production or maintain interests in our properties.

We must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. Historically, we have paid for these expenditures with cash from operating activities, proceeds from debt and equity financings and asset sales. Our revenues or cash flows could be reduced because of lower oil and natural gas prices or for other reasons. If our revenues or cash flows decrease, we may not have the funds available to replace reserves or maintain production at current levels. If this occurs, our production will decline over time. Other sources of financing may not be available to us if our cash flows from operations are not sufficient to fund our capital expenditure requirements. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. Where we are not the majority owner or operator of an oil and natural gas property, we may have no control over the timing or amount of capital expenditures associated with the particular property. If we cannot fund such capital expenditures, our interests in some properties may be reduced or forfeited.

If we are unable to replace reserves, we may not be able to sustain production at present levels.

Our future success depends largely upon our ability to find, acquire or develop additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. By their nature, estimates of proved undeveloped reserves and timing of their production are less certain particularly because we may chose not to develop such reserves on anticipated schedules in future adverse oil or natural gas price environments. Recovery of such reserves will require significant capital expenditures and successful drilling

 

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operations. The lack of availability of sufficient capital to fund such future operations could materially hinder or delay our replacement of produced reserves. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.

We may incur substantial impairment write-downs.

If management’s estimates of the recoverable proved reserves on a specific field are revised downward or if oil and natural gas prices decline, we may be required to record additional non-cash impairments in the future, which would result in a negative impact to our financial position. Management’s assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Changes in Management’s assumptions could cause an impairment of our oil and natural gas properties, impacting our results of operations reported in the future and our basis in the related property. Any change in reserves directly impacts our estimate of future cash flows from our properties, as well as the properties’ fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these estimates will directly impact our assessment of future impairments of our oil and natural gas properties.

 

 

 

 

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Item 6—Exhibits

 

 

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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.

 

 

 

 

 

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