UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-Q

 

 

For the Quarterly Period Ended June 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 August 3, 2015 was 57,485,270.

 

 

 

 

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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 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. We have significantly reduced our capital expenditures planned for 2015 thereby conserving capital.

2. We have extended the maturity of our Senior Credit Facility to February 24, 2017.

3. We have received proceeds from our issuance of $100 million Second Lien Notes.

4. We have received proceeds of $48 million from the sale of 12,000,000 shares of our common stock to the public.

5. We have reduced our staff headcount by 25% from year-end 2014 levels thereby reducing expenses.

6. We have entered into a definitive agreement to sell our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale for $118 million, which is expected to close in early September 2015.

Additionally, we have approximately 95% of our remaining projected 2015 oil production 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 enhance our liquidity, we anticipate our cash on hand, cash from operations, proceeds from asset sales and our available borrowing capacity under our Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements through the middle of 2016. If we are not able to sell our other non-core properties at a favorable price or find joint venture partners and the current low commodity prices continue past the middle of 2016, it will be necessary to seek debt covenant relief, or if covenant relief is not received, restructure our debt.

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.

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 June 30, 2015, we had interests in oil and natural gas properties totaling $631.6 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

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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.

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.

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

As of June 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 June 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,

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 is scheduled to remain in effect for a period of ten years and requires 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 bills us for 20% of the accumulated unpaid capital costs annually. The transportation obligation liability was $5.3 million as of June 30, 2015 and $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 is being amortized using the units-of-production method and the amortization expense is included in “Transportation and processing” on the Consolidated Statements of Operations. The related current and long-term liabilities are 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 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.

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 June 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% Convertible Senior Notes due 2029 (the “2029 Notes”) and 5% Convertible Senior Notes due 2032 (the “2032 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

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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.

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 and 2032 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 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 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 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 a 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 April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

On January 9, 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.

On August 27, 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 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 June 30, 2015 is as follows (in thousands):

 

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 3—Debt

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

 

 

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

Senior Credit Facility

Total lender commitments under the Senior Credit Facility are $600 million subject to borrowing base limitation, which as of June 30, 2015 was $150 million. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

annual basis on April 1 and October 1. As of June 30, 2015, we had $86 million outstanding under the Senior Credit Facility and $0.3 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. The next borrowing base redetermination will occur on October 1, 2015.  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 as amended by the Thirteenth Amendment, 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 include:

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 June 30, 2015.

8% Second Lien Senior Secured Notes due 2018

On March 12, 2015, we sold 100,000 Second Lien Note units (the “Units”), each consisting of a $1,000 principal amount at maturity 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 secure 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. In addition, prior to September 12, 2015,  we may redeem up to 35% of the aggregate principal amount of the Second Lien Notes with the net cash proceeds of one or more equity offerings at a redemption price of 108% of the principal amount plus accrued and unpaid interest, if any, up to the redemption date.

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

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 will not be separately transferable until the earliest of (i) 365 days after the date on which the warrants are originally issued, (ii) the date on which a registration statement related to the resale of the warrants is declared effective, (iii) the date on which a registration statement with respect to a registered exchange offer for the Second Lien Notes is declared effective and (iv) in the event of the occurrence of a change of control (as defined in the indenture), the date on which requisite notice of such change of control is mailed to the holders of Second Lien Notes. At such time, the warrants will become 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 in ten years 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 Securities Exchange Commission (“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 account 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 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 $13.8 million remains to be amortized on the Second Lien Notes as of June 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 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.

We may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 104.438% for the twelve-month period beginning on March 15, 2015; (ii) 102.219% for the twelve-month period beginning on March 15, 2016 and (iii) 100.000% 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.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

5% 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 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 June 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 indebtedness. The 2029 Notes accrue interest at a rate of 5% 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 through September 30, 2014. 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.

5% 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.

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 $0.9 million and $1.7 million of accretion in the three and six months ended June 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 account 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 to 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 $4.4 million remains to be amortized on the 2032 Notes as of June 30, 2015.

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

3.25% Convertible Senior Notes Due 2026

At June 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:

 

 

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 six months ended June 30, 2015 and 2014. 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 six months ended June 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 June 30, 2015.

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

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 six month periods ended June 30, 2015 and 2014.

 

 

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 June 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 $21.4 million in derivative fair value had our counterparties as a group been unable to fulfill their obligations as of June 30, 2015.

As of June 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:

 

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of June 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.

 

 

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 June 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 $48.0 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 common stock par value $0.20 per share. The warrants were issued pursuant to a Warrant Agreement dated March 12, 2015 (the “Warrant Agreement”), between us and American Stock Transfer & Trust Company LLC. Under the terms of the Warrant Agreement, the Second Lien Notes and the warrants will not be separately transferable until the earliest of (i) 365 days after the date on which the warrants are originally issued; (ii) the date on which a registration statement related to the resale of the warrants is declared effective; (iii) the date on which a registration statement with respect to a registered exchange offer for the Second Lien Notes is 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 is mailed to the holders of Second Lien Notes. At such time, the warrants will become exercisable upon payment of the exercise price of $4.664 or convertible on a cashless basis as set forth in the Warrant Agreement. Any warrants not exercised in ten years will expire. 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 Form S-3 was declared effective on June 4, 2015.

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

 

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

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 and paid for the first shipment and a $10.8 million commitment remains at June 30, 2015.

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

 

 

NOTE 9 – Subsequent Events

On July 24, 2015 we entered into a definitive agreement to sell our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale in LaSalle and Frio counties, Texas for $118 million. The effective date of the transaction is July 1, 2015 with an expected closing date on or before September 4, 2015.  We plan to use the proceeds from the sale to repay borrowings under our Senior Credit Facility and retain the residual cash proceeds for general corporate purposes.

 

 

 

 

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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.

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 TMS, Eagle Ford Shale Trend and Haynesville 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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Enhance financial flexibility. As of June 30, 2015, we had a borrowing base of $150 million under our $600 million Senior Credit Facility, on which we had $86 million drawn and $0.3 million in cash. In March 2015 we issued and sold $100 million aggregate principal amount of our Second Lien Notes, which was used to pay down the amount drawn on our Senior Credit Facility.  In March 2015 we also received net proceeds of $48 million from the sale of 12,000,000 shares of our common stock to the public. We have entered into a definitive agreement to sell our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale for $118 million, which is expected to close in early September 2015. We have historically funded growth through operating cash flow, debt, equity and equity-linked security issuances, divestments of non-core assets and entering into strategic joint ventures. In addition, we will continue to seek a joint venture partner to share in the cost to develop our acreage in the TMS.  We also actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including fixed price swaps, swaptions and costless collars. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy.

Overview of Second Quarter 2015 Results

Second Quarter 2015 financial and operating results included:

Primary Operating Areas

Tuscaloosa Marine Shale Trend

We held approximately 441,000 gross (307,000 net) acres in the TMS as of June 30, 2015. During the six months of 2015, we conducted drilling operations on 5 gross (3.9 net) wells in the TMS. As of June 30, 2015, we had 4 gross (3.4 net) TMS wells drilled and waiting on completion. Our net production volumes from our TMS wells represented approximately 28% of our total equivalent production on a Boe basis and approximately 56% of our total oil production for the second quarter of 2015.

During the first six months of 2015, we spent $54.6 million in the TMS, which included $2.7 million for leasehold costs.

Eagle Ford Shale Trend

We held approximately 42,000 gross (28,000 net) acres in La Salle and Frio counties, Texas as of June 30, 2015, all of which are either producing from or prospective for the Eagle Ford Shale Trend. Our net production volumes from our Eagle Ford Shale Trend wells represented approximately 29% of our total equivalent production on a Boe basis and approximately 44% of our total oil production for the second quarter of 2015. On July 24, 2015, we entered into a definitive agreement to sell our proved reserves and a portion of the associated leasehold in the Eagle Ford Shale for $118 million, subject to customary closing and post-closing adjustments.  The transaction is expected to close on or before September 4, 2015. We will retain approximately fifty-eight percent, or approximately 17,000 net acres, of its undeveloped leasehold in the Eagle Ford Shale play 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 We held approximately 54,000 gross (25,000 net) acres as of June 30, 2015 producing from and prospective for the Haynesville Shale Trend. Our net production volumes from our Haynesville Shale Trend wells represented approximately 41% of our total equivalent production on a Boe basis for the second quarter of 2015.

 

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Results of Operations

For the three months ended June 30, 2015, we reported net loss applicable to common stock of $39.1 million, or $0.68 per basic and diluted share, on total revenue of $26.1 million as compared to net loss applicable to common stock of $32.5 million, or $0.73 per basic and diluted share, on total revenue of $53.3 million for the three months ended June 30, 2014.

For the six months ended June 30, 2015, we reported net loss applicable to common stock of $67.6 million, or $1.27 per basic and diluted share, on total revenue of $50.1 million as compared to net loss applicable to common stock of $62.5 million, or $1.41 per basic and diluted share, on total revenue of $105.1 million for the six months ended June 30, 2014.

The items that had the most material financial effect on us in the three and six months ended June 30, 2015 compared to the same periods in 2014 were revenues and depreciation, depletion and amortization.  Revenues were down due to significantly lower realized oil and natural gas sales prices as well as lower 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.

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.

 

 

* - Not meaningful

Revenues from Operations

Revenues from operations decreased by $27.2 million for the three months ended June 30, 2015 compared to the same period in 2014, reflecting a decrease in natural gas production volumes and lower average realized natural gas, oil and condensate sales prices which decreased revenues by $27.2 million. We are focused on maintaining our oil production, which we are currently able to sell at a more favorable price relative to natural gas. For the three months ended June 30, 2015, 84% of our oil and natural gas revenue was attributable to oil sales compared to 72% for the three months ended June 30, 2014.

 

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Revenues from operations decreased by approximately $55.0 million for the six months ended June 30, 2015 compared to the same period in 2014, reflecting a decrease in natural gas production volumes and lower average realized natural gas, oil and condensate sales prices, which decreased revenues by $59.7 million partially offset by an increase in oil and condensate production volumes which increased revenues by $4.8 million. For the six months ended June 30, 2015, 83% of our oil and natural gas revenue was attributable to oil sales compared to 68% for the six months ended June 30, 2014.

The difference in our realized prices inclusive of the effect of the realized gains and losses on our derivatives between the three and six month periods ended June 30, 2015 and 2014 relates to our oil swap contracts. In the three and six months ended June 30, 2015, we had 3,500 Bbls of oil per day hedged at an average fixed price of $96.11 per Bbl and in the comparative periods of 2014, we had an average of 3,800 Bbls of oil per day hedged at an average fixed price of $93.65 per Bbl.

Operating Expenses

As described below, operating expenses decreased $19.9 million to $37.0 million in three months ended June 30, 2015 and decreased $36.3 million to $74.5 million in the six months ended June 30, 2015, each compared to the same periods in 2014.

 

 

Lease Operating Expense

Lease operating expense (“LOE’) during the three month period ended June 30, 2015 decreased compared to the three months ended June 30, 2014. The decrease was the result of a $1.6 million decrease in operating costs stemming from the sale of our non-core East Texas natural gas fields in December 2014.  In addition, a $0.8 million reduction in workover expense primarily associated with our wells in the Eagle Ford Shale Trend and TMS added to the LOE decrease. Workover expense in the second quarter of 2015 totaled $0.6 million which added $0.75 per Boe to unit expense compared to workover expense of $1.4 million in the second quarter of 2014 which added $1.31 per Boe to unit expense.

LOE for the six months ended June 30, 2015 decreased in comparison to the same period in 2014. The decrease was the result of a $4.3 million decrease in operating costs stemming from the sale of our non-core East Texas natural gas fields in December 2014.  Lower workover expense of $2.5 million in the Eagle Ford Shale Trend and TMS assisted with the decrease in LOE.  LOE in the first six months of 2015 included workover expense of $0.8 million which added $0.53 per Boe to unit expense compared to workover expense of $3.3 million in the first six months of 2014 which added $1.57 per Boe to unit expense.

Production and Other Taxes

Production and other taxes for the three months ended June 30, 2015 included production tax of $0.8 million and ad valorem tax of $0.6 million. During the comparable period in 2014, production and other taxes included production tax of $1.3 million and ad valorem tax of $0.6 million.

Production and other taxes for the six months ended June 30, 2015 included production tax of $1.4 million and ad valorem tax of $1.4 million. During the comparable period in 2014, production and other taxes included production tax of $3.1 million and ad valorem tax of $1.3 million.

Production and other taxes decreased in the second quarter of 2015 due to significantly lower crude oil prices during the three and six months ended June 30, 2015, lower oil production from our Eagle Ford Shale Trend wells and lower tax rates on the TMS wells drilled in the state of Mississippi after July 1, 2013. The State of Mississippi has enacted an exemption from the existing 6%

 

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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 six months ended June 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 six months ended June 30, 2015 compared to the same periods in 2014 is attributable to an increase in leasehold amortization costs related to expiring leases in our TMS and Eagle Ford Shale Trend acreage.  

 

 

* – Not meaningful.

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

DD&A expense for the three and six months ended June 30, 2015 decreased as compared to the same periods 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.

General and Administrative (“G&A”) Expense

G&A expense decreased in the three and six months ended June 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 25% from year-end 2014 levels.  The higher rate per Boe, for the six months ended June 30, 2015, reflects decreased natural gas production in 2015. Share-based compensation expense, which is a non-cash item, amounted to $1.9 million for the three months ended June 30, 2015, a $0.4 million decrease over the same period in 2014. For the six months ended June 30, 2015, share-based compensation totaled $3.8 million, a $0.8 million decrease over the same period in 2014.

Other Expense

Other expense for the three and six month period ended June 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.

 

 

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Other Income (Expense)

 

 

Interest Expense

Our interest expense increased in the three and six months ended June 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.  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 June 30, 2015 totaled $3.7 million, compared to $2.7 million in the same period in 2014. Non-cash interest of $5.8 million is included in the interest expense reported for the six month period in 2015 compared to $5.3 million in the 2014 comparative period.

Gain (loss) on Derivatives Not Designated as Hedges

Loss on derivatives not designated as hedges for the three months ended June 30, 2015 includes an unrealized loss of $17.1 million for the change of the fair value of our oil and natural gas derivative contracts and net cash receipts of $11.1 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 $17.1 million loss on our oil derivatives. The decrease in fair value of our oil derivatives reflects the realization of settled contracts.

Loss on derivatives not designated as hedges for the three months ended June 30, 2014 includes an unrealized loss of $6.7 million for the change of the fair value of our oil and natural gas derivative contracts and net cash payments of $3.1 million on the settlement of our oil derivatives. The unrealized loss consisted of a $6.0 million loss on our oil derivatives and a $0.7 million loss on our natural gas derivatives. The unrealized loss on oil and natural gas derivatives reflects the increase in futures prices for the period.

Loss on derivatives not designated as hedges for the six months ended June 30, 2015 includes an unrealized loss of $25.8 million for the change of the fair value of our oil and natural gas derivative contracts and net cash receipts of $24.3 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 $0.2 million gain on our natural gas derivatives and a $26.0 million loss on our oil derivatives. The unrealized loss on oil derivatives and the decrease in fair value of our oil derivatives reflects the roll off of settled oil derivative contracts during 2015.

Loss on derivatives not designated as hedges for the six months ended June 30, 2014 includes an unrealized loss of $12.5 million for the change of the fair value of our oil and natural gas derivative contracts and net cash payments of $5.8 million on the settlement of our oil and natural gas derivatives. The unrealized loss consisted of an $8.0 million loss on our oil derivatives and a $4.5 million loss on our natural gas derivatives. The unrealized loss on oil and natural gas derivatives reflects the increase in futures prices for the period.

We will continue to be exposed to volatility in earnings resulting from changes in the fair value of our commodity contracts as we do not designate these contracts as hedges.

Income Tax Benefit

We recorded no income tax benefit for the three and six months ended June 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 June 30, 2015.

 

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Adjusted EBITDAX (in thousands)

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 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 second quarter of 2015 were proceeds from our Second Lien Notes offering, proceeds from our common stock offering and cash flow from our operating activities. We used cash primarily to fund our capital spending program, repay bank borrowings, pay interest on outstanding debt and pay preferred stock dividends. We expect to finance our estimated capital expenditures for the remainder of 2015 through a combination of cash on hand, cash from operating activities, proceeds from asset sales and borrowings under our Senior Credit Facility.

We have in place a $600 million Senior Credit Facility, entered into with a syndicate of U.S. and international lenders. As of June 30, 2015, we had a $150 million borrowing base with $86 million in outstanding borrowings and $0.3 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 next borrowing base redetermination will occur on October 1, 2015.

Outlook

We are an exploration and production Company with interests in non-conventional oil 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.

 

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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:

In addition, to support 2015 cash flows, we have in place derivative positions covering 95% of our anticipated oil and condensate sales volumes for the rest of 2015. 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.

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, proceeds from asset sales and our available borrowing capacity under our Senior Credit Facility will be sufficient to meet our investing, financing, and working capital requirements through the middle of 2016. If we are not able to sell our other non-core properties at a favorable price or find joint venture partners and the current low commodity prices continue past the middle of 2016, it will be necessary to seek debt covenant relief, or if covenant relief is not received, restructure our debt.

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

 

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six months ended June 30, 2015 totaled $5.5 million, a decrease of $75.4 million from the six months ended June 30, 2014. Operating cash flows before working capital changes decreased $11.0 million for the six months ended June 30, 2015 compared to the same period in 2014 reflecting the absence of cash flows from natural gas properties sold in December 2014 and lower commodity prices.  The decrease in cash flows of $64.4 million from the change in working capital for the six months ended June 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 $88.2 million for the six months ended June 30, 2015, compared to $151.6 million for the six months ended June 30, 2014. While we booked capital expenditures of approximately $65.5 million in the six months ended June 30, 2015, we paid out cash amounts totaling $91.4 million in the six months ended June 30, 2015. The difference is attributed to $33.8 million accrued at December 31, 2014 and paid in the six months ended June 30, 2015 offset by $7.9 million in drilling and completion costs accrued at June 30, 2015. Capital expenditures in the first six months of 2015 were offset by the receipt of $3.2 million in net proceeds, primarily from the sale of non-core assets located in East Texas.

 

Financing activities: Net cash provided in financing activities for the six months ended June 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 $47.6 million partially offset by net repayments of borrowings under the Senior Credit Facility of $35 million, preferred stock dividends of $14.9 million and debt issuance cost of $3.3 million. We had $86 million in borrowings outstanding under our Senior Credit Facility as of June 30, 2015. In the six months ended June 30, 2014, net cash provided in financing activities consisted of net proceeds from borrowings under our Senior Credit Facility of $48.0 million, partially offset by preferred stock dividends of $14.9 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 six months ended June 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.

 

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Commodity Price Risk

Our most significant market risk relates to fluctuations in crude oil and natural gas prices. Management expects the prices of these commodities to remain volatile and unpredictable. As these prices decline or rise significantly, revenues and cash flow will also decline or rise significantly. In addition, a non-cash write-down of our oil and natural gas properties may be required if future commodity prices experience a sustained and significant decline. Below is a sensitivity analysis of our commodity-price-related derivative instruments.

As of June 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 June 30, 2015, we have a net asset derivative position of $21.1 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 $19.0 million, while a hypothetical 10% decrease in oil and natural gas prices would have increased our net derivative asset to $23.2 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 Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(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 Chief Financial Officer, based upon their evaluation as of June 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, 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.

 

Our stock price has recently declined below $1.00 per share.  If the average closing price of our common stock is less than $1.00 per share for a period of over 30 consecutive trading days, the NYSE could delist our common stock.

 

The NYSE requires that the average closing price of a listed company’s common stock not be less than $1.00 per share for a period of over 30 consecutive trading days. Under NYSE rules, a company can avoid delisting if, during the six month period following receipt of the NYSE notice and on the last trading day of any calendar month, a company’s common stock price per share and 30 trading-day average share price is at least $1.00. During this six month period, a company’s common stock will continue to be traded on the NYSE, subject to compliance with other continued listing requirements.

 

In the future, if our common stock ultimately were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our common stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.

 

 

 

 

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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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