UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended September 30, 2009

 

OR

 

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from to ____

 

Commission file number 000-21644

 

CRIMSON EXPLORATION INC.

(Exact name of Registrant as specified in its charter)

 

 

(713) 236-7400

(Registrant’s telephone number, including area code)

 

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 o

 

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 o No o

 

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 definition 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 o No x

 

On November 10, 2009, there were 6,421,564 shares outstanding of the Registrant’s Common Stock, par value $0.001.

 

FORM 10-Q

 

CRIMSON EXPLORATION INC.

 

INDEX

 

 

 

 

PART I.     FINANCIAL INFORMATION

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

 

 

The Notes to Consolidated Financial Statements are an integral part of these statements.

 

3

 

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

 

The Notes to Consolidated Financial Statements are an integral part of these statements

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The Notes to Consolidated Financial Statements are an integral part of these statements.

 

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

 

 

The Notes to Consolidated Financial Statements are an integral part of these statements.

 

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

 

Crimson Exploration Inc., together with its subsidiaries (“Crimson”, “we”, “our”, “us”), is an independent natural gas and crude oil company engaged in the acquisition, development, exploitation and exploration of natural gas and crude oil properties, primarily in the onshore U.S. Gulf Coast and South Texas regions.

 

Presentation – The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S.”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by U.S. generally accepted accounting principles (“GAAP”) for complete financial statements. The accompanying consolidated financial statements at September 30, 2009 (unaudited) and December 31, 2008 and for the three and nine months ended September 30, 2009 (unaudited) and 2008 (unaudited) contain all normally recurring adjustments considered necessary, in the opinion of management, for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. These unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2008.

The accompanying financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Southern G Holdings, LLC, acquired May 8, 2007, and merged with Crimson Exploration Operating, Inc. on January 1, 2008, Crimson Exploration Operating, Inc., formed January 5, 2006 and LTW Pipeline Co., formed April 19, 1999. All material intercompany transactions and balances are eliminated upon consolidation. Certain reclassifications were made to previously reported amounts to make them consistent with the current presentation format.

Accounting Standards Codification — On July 1, 2009, the Financial Accounting Standards Board (“FASB”) instituted a new referencing system, which codifies, but does not amend, previously existing nongovernmental GAAP. The FASBAccounting Standards Codification™ (“ASC”) is now the single authoritative source for GAAP. Although the implementation of ASC had no impact on our financial statements, certain references to authoritative GAAP literature within our footnotes have been changed to cite the appropriate content within the ASC.

Adoption of ASU 2009-05 — In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2009-05, Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value. ASU 2009-05 provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. We adopted ASU No. 2009-05 (FASB ASC 820-10) as of September 30, 2009. The adoption of this statement did not have an impact on our financial position or results of operations.

Subsequent Events — We adopted the Financial Accounting Standards Board (“FASB”) Statement No. 165, “Subsequent Events”, which is now incorporated into ASC Topic No. 855 (“ASC 855”) as of June 30, 2009. ASC 855 requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. The

 

 

adoption of this statement did not have a material impact on our financial position or results of operations. We completed our review and analysis of potential subsequent events, as of November 16, 2009, the date these financial statements were issued. See Note 11- “Subsequent Events” for additional disclosures.

Interim Disclosures about Fair Value of Financial Instrument — We adopted FSP SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments”, which is now incorporated into ASC Topic No. 825 (“ASC 825”) as of June 30, 2009. This statement increases the frequency of fair value disclosures to a quarterly instead of annual basis. The guidance relates to fair value disclosures for any financial instruments that are not currently reflected on the balance sheet at fair value. The adoption of this statement did not have a material impact on our financial position or results of operations.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly — We adopted the FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” which is now incorporated into ASC Topic No. 820 (“ASC 820”) as of June 30, 2009. ASC 820 provides guidelines for a broad interpretation of when to apply market-based fair value measures. It reaffirms management’s need to use judgment to determine when a market that was once active has become inactive and in determining fair values in markets that are no longer active.

Disclosure about Derivative Instruments and Hedging Activities — We adopted FASB Statement No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” which is now incorporated into ASC Topic No. 815 (“ASC 815”) as of January 1, 2009. ASC 815 amends and expands the disclosure requirements for derivative instruments and hedging activities with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. See Note 5 – “Derivative Instruments” for these additional disclosures. The adoption of this statement did not have an impact on our financial position or results of operations.

Business Combinations — We adopted SFAS No. 141 (Revised 2007) “Business Combinations” which is now incorporated into ASC Topic No. 805 (“ASC 805”) as of January 1, 2009. The revision broadens the definition of a business combination to include all transactions or other events in which control of one or more businesses is obtained. Further, this statement establishes principles and requirements for how an acquirer recognizes assets acquired, liabilities assumed and any non-controlling interests acquired. The adoption of this statement has not had an impact on our financial position or results of operations, because we have not yet had any business combinations in 2009.

Effective Date of FASB Statement No. 157 - We also adopted FSP SFAS 157-2, “Effective Date of FASB Statement No. 157”, which is also now incorporated into ASC Topic No. 820 as of January 1, 2009. The effective date was deferred for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. See Note 4 – “Fair Value Measurements” for additional disclosures. The adoption of this statement did not have a material impact on our financial position or results of operations.

 

Acquisition from Smith Production Inc.

In May 2008, we acquired four producing gas fields and undeveloped acreage in South Texas from Smith Production Inc. (“Smith”) for a purchase price of $65.0 million with an economic effective date of

 

 

January 1, 2008. After adjustment for the estimated results of operations, and other typical purchase price adjustments of approximately $7.4 million for the period between the effective date and the closing date, the cash consideration was approximately $57.6 million.

Fort Worth Barnett Shale Disposition

In January 2008, we and our operator-partner entered into a series of agreements to sell our interests in wells and undeveloped acreage in the Fort Worth Barnett Shale Play in Johnson and Tarrant counties, Texas to another industry participant active in that area. We owned a 12.5% non-operated working interest in the assets being sold and had 1.5 Bcfe in proved reserves at December 31, 2007. The final total consideration paid by the buyer was based on existing wells and undeveloped acreage owned by us and our partner at the time of the final closing. Our share of the consideration received was approximately $34.4 million. Proceeds received for our interest were primarily used to repay amounts outstanding under our senior secured revolving credit facility and to help finance our acquisition of the properties from Smith. Our net book value of these assets sold was $18.8 million, which resulted in a gain of $15.6 million.

We use a fair value hierarchy which prioritizes the inputs to valuation techniques for measuring fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value.

Certain of our assets and liabilities are reported at fair value in our consolidated balance sheets.  The following methods and assumptions were used to estimate the fair values for each class of financial instruments:

Cash, Cash Equivalents, Accounts Receivable and Accounts Payable. The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Our allowance for doubtful accounts as of September 30, 2009 and December 31, 2008 remains at $0.2 million.

Derivative Instruments. Our derivative instruments consist of variable to fixed price commodity swaps, costless collars and interest rate swaps. We value our derivative instruments utilizing estimates of present value as calculated by the respective counterparty financial institutions and reviewed by management. See Note 5 – “Derivative Instruments” for further information. Fair value information for assets and liabilities that are measured at fair value is as follows at September 30, 2009:

 

 

Asset Impairments – We review a proved oil and gas property for impairment when events and circumstances indicate a significant decline in the recoverability of the carrying value of such property. If events indicate a significant decline in the recoverability of such property, we estimate the future cash flows expected in connection with the property and compare such future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the

 

 

property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. We had no asset impairments in the nine months ended September 30, 2009.

Debt –The fair value of debt approximates the carrying amounts on such debt. Interest rates are based on Prime or LIBOR rates at the time the loans are renewed. See Note 6 – “Debt” for further information.

Asset Retirement Obligations – We estimate the fair values of asset retirement obligations (“AROs”) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates.

 

 

 

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our natural gas and crude oil production, to reduce our sensitivity to volatile commodity prices, and with respect to portions of our debt, to reduce our sensitivity to volatile interest rates. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price and interest rate fluctuations. However, derivative arrangements limit the benefit of increases in the prices of natural gas, crude oil and natural gas liquids sales and limit the benefit of decreases in interest rates. Moreover, our derivative arrangements apply only to a portion of our production and our debt and provide only partial protection against declines in commodity prices and increases in interest rates, respectively. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our hedging programs in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.

We use a mix of commodity swaps and costless collars and interest rate swaps to accomplish our hedging strategy. Derivative assets and liabilities with the same counterparty, subject to contractual terms which provides for net settlement, are reported on a net basis on our consolidated balance sheets. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry specifically with

 

 

members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility. We believe our counterparty risk is low because of the offsetting relationship we have with each of our counterparties. See Note 4 — “Fair Value Measurements” for further information.

The following derivative contracts were in place at September 30, 2009:

 

 

The total net fair value asset for derivative instruments at September 30, 2009 was approximately $16.9 million and at December 31, 2008 was approximately $34.2 million, which are shown as derivative instruments in assets and liabilities on the balance sheet.

The following table details the effect of derivative contracts on the Consolidated Statements of Operations:

 

 

 

 

 

On November 6, 2009, we entered into a second and third amendment to our senior secured revolving credit facility, dated May 31, 2007, as amended (“Senior Credit Agreement”). This facility provides cash availability for acquisitions of oil and gas properties and for general corporate cash requirements. The Senior Credit Agreement provides for aggregate borrowings of up to $400.0 million, with an initial borrowing base of $200.0 million that decreased to $140.0 million, effective November 2, 2009, and is subject to semi-annual redeterminations, although our lenders may elect to make one additional redetermination between scheduled redetermination dates (and have expressly reserved the right to do so between January 1, 2010 and May 1, 2010). The next borrowing base redetermination is scheduled for January 1, 2010. These amendments to the Senior Credit Agreement provide, among other things, for (i) a change in the voting percentages required for certain amendments or waivers from 50.1% to 60%, and (ii) a waiver of the current ratio and the leverage ratio for the quarter ended September 30, 2009. The Senior Credit Agreement matures on May 8, 2011. As of September 30, 2009, we had an outstanding loan balance of $141.5 million under our Senior Credit Agreement.

Also, on November 6, 2009, we issued an unsecured promissory note in an aggregate principal amount of $10.0 million to Wells Fargo Bank, National Association, the administrative agent and a lender under our Senior Credit Agreement. This promissory note bears interest at a per annum rate equal to two-month LIBOR plus 2% and matures on January 15, 2010; provided that upon an event of default resulting from the failure to make any payment of principal or interest under the promissory note, the interest rate per annum will increase to an amount equal to the lesser of the maximum rate of interest that may be charged under applicable law and LIBOR plus 4% or, if the promissory note has been assigned to any person other than any affiliate of Wells Fargo Bank, LIBOR plus 15%. All of the proceeds of the promissory note were used to repay indebtedness outstanding under the Senior Credit Agreement. As support for the obligations owed under the promissory note, OCM GW Holdings, LLC (“Oaktree Holdings”), our majority stockholder, has deposited $10.0 million in escrow for the benefit of Wells Fargo, which may, at its option, cause the note to be assigned to Oaktree Holdings and draw on the funds held in escrow.

As consideration for Oaktree Holdings’ agreement to deposit $10.0 million in escrow as described above, we issued an unsecured subordinated promissory note on November 6, 2009 in an aggregate principal amount of $2.0 million to Oaktree Holdings. The indebtedness under the promissory note bears interest at a rate equal to 8.0% per annum and matures on the later of (i) November 8, 2012 and (ii) the date six months after payment in full in cash of all Obligations (as such term is defined under each of the Senior Credit Agreement and the Second Lien Credit Agreement (defined below)), and the termination of all commitments to extend credit under the Senior Credit Agreement and the Second Lien Credit Agreement. The promissory note is subordinated in right of payment to the prior payment in full in cash of all obligations under the Senior Credit Agreement and the Second Lien Credit Agreement.

On July 31, 2009, we entered into the first amendment to our Senior Credit Agreement. This amendment to the Senior Credit Agreement provides, among other things, for (i) the leverage ratio to be not greater than 2.75 to 1.00 for each fiscal quarter, (ii) the current ratio to be not less than 1.00 to 1.00 for each fiscal quarter, (iii) an increased applicable margin on LIBOR loans to between 2.75% and 3.50%, and base rate loans to between 1.50% and 2.00%, depending on the percent of the borrowing base utilized at the time of the credit extension, and (iv) an increased commitment fee on unutilized commitments to 0.50%.

On November 6, 2009, we entered into a third amendment and waiver to our second lien credit agreement dated May 8, 2007, as amended (the “Second Lien Credit Agreement”), with lenders holding a majority of the then outstanding term loans under such agreement, which included an affiliate of Oaktree Holdings. The Second Lien Credit Agreement provides for a term loan in an aggregate principal amount

 

 

of $150.0 million, with a term of five years with all principal amounts, together with all accrued and unpaid interest, due and payable in full on May 8, 2012. The third amendment to our Second Lien Credit Agreement provided, among other things, for a waiver of the leverage ratio covenant for the quarter ended September 30, 2009.

The Senior Credit Agreement and the Second Lien Credit Agreement (the “Credit Agreements”) are secured by a lien on substantially all of our assets, as well as a security interest in the stock of our subsidiaries. The obligations under the Second Lien Credit Agreement are junior to those under the Senior Credit Agreement. Interest is payable on the Credit Agreements as borrowings mature and renew.

The Credit Agreements include usual and customary affirmative covenants for credit facilities of the respective types and sizes, as well as customary negative covenants, including, among others, limitations on liens, hedging, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, certain leases and investments outside of the ordinary course of business, as well as events of default. The Credit Agreements also contain certain financial and proved reserve covenants. See Note 10 of our 2008 Annual Report on Form 10-K for a more detailed description of our covenants under the Credit Agreements, other than those revised above. At September 30, 2009, we were in compliance with the aforementioned covenants, with the exception of the current ratio under the Senior Credit Agreement and the leverage ratio under both of the Credit Agreements. We obtained waivers of such noncompliance from our lenders under the Credit Agreements for the quarter ended September 30, 2009. However, without improvement in natural gas and crude oil prices, reduction in debt levels, improvement in production volumes and/or other measures, we may not be able to comply with certain covenants under our Credit Agreements for future quarters. We continue to pursue other public and private sources of capital which would positively affect our debt covenant ratios and we continue to work with our lenders on long term amendments to our covenants. If we are unable to comply with the covenants for future quarters, we believe that it is not probable that we would not be able to cure future covenant violations by obtaining additional capital or by obtaining waivers from our lenders to cure the defaults, although we can give no assurances that any such sources of capital will be available or that such amendments will be entered into, or on terms acceptable to us. If we were not able to comply with our covenants in the future, and we were not able to obtain waivers from our lenders to cure such defaults, our lenders would have the right to demand acceleration of payment on all amounts outstanding under our Credit Agreements.

 

 

In the nine months ended September 30, 2009, we issued approximately 0.6 million shares of common stock, par value $0.001 per share (“Common Stock”) subject to restricted stock awards to our employees under the performance-based Long-Term Incentive Plan (“LTIP”) for the 2008 plan year. We issued 48,586 shares of restricted stock to two members of our board of directors as compensation pursuant to the Director Compensation Plan. We also issued 6,300 shares of Common Stock in payment of dividends on Series H Preferred Stock valued at $20,370 based on the closing market price on the date the shares were issued. As a result of the vesting of 124,169 shares of restricted Common Stock, 40,713 shares of such stock were withheld by us to satisfy the employees’ withholding tax liability, as provided for in the restricted stock agreements, with the remaining shares being released to the associated employees.

 

 

The following table sets forth the accumulated value of undeclared dividends on our preferred stock at September 30, 2009 and December 31, 2008, respectively:

 

 

Until such time as the Board of Directors declares and pays dividends on our Series G Preferred Stock, dividends shall continue to accumulate. Dividends on our Series H Preferred Stock are declared quarterly by our Board of Directors, and are paid out in Common Stock the following quarter.

 

 

We have share-based compensation for employees and directors, which includes both stock option and restricted stock awards. The following table reflects share-based compensation expense, assuming a 35.0% effective tax rate for the periods ended:

 

 

In the nine months ended September 30, 2009, we awarded approximately 0.6 million shares of restricted Common Stock and 0.5 million shares in stock options to our employees under our LTIP for the 2008 plan year. We also issued 48,586 shares of restricted Common Stock to two members of our board of directors as compensation pursuant to the Director Compensation Plan.

In the nine months ended September 30, 2008, we issued 1,538 shares of restricted Common Stock to two members of our board of directors as compensation pursuant to the Director Compensation Plan. We also issued 533,350 shares of unvested Common Stock pursuant to restricted stock awards in exchange for the forfeiture of 1,066,700 substantially vested stock option grants. The fair value of the unvested Common Stock was calculated as $4.9 million on the issuance date. The fair value of the forfeited stock options, calculated using the Black-Scholes valuation model, was $4.3 million immediately prior to the forfeiture. The sum of the incremental value of the new award over the forfeited options, $0.6 million, and the unrecognized compensation cost for the original award as of the exchange date, $1.4 million, are being amortized using the straight line method over the new vesting period of five years, or approximately $32,000 a month.

Income tax benefit for the nine months ended September 30, 2009 was $9.1 million, compared to income tax expense of $15.1 million for the nine months ended September 30, 2008. The income tax benefit for the nine months ended September 30, 2009 was based on our estimate of the effective tax rate expected to be applicable for the full year. The effective tax rate and the federal statutory rate were 35% for the nine months ended September 30, 2009.

SEC 33-8995/34-59192. In December 2008, the SEC adopted Release No. 33-8995/34-59192, “Modernization of Oil and Gas Reporting” (“SEC 33-8995”). This release amends the oil and gas reporting disclosures that exist in their current form in Regulation S-K and Regulation S-X under the Securities Act of 1933 and the Securities Exchange Act of 1934 to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The new rules include changes for pricing used to estimate reserves; permitting disclosure of possible and probable reserves; ability to include non-traditional resources in reserves and the use of new technology for determining reserves. SEC 33-8995 is effective for fiscal years ending on or after December 31, 2009. Early adoption is not

 

 

permitted. We are currently evaluating the provisions of SEC 33-8995 and assessing the impact it may have on our financial reporting disclosures.

On November 6, 2009, we completed the second and third amendments to our Senior Credit Agreement, which changed the voting requirements for certain amendments or waivers and waived certain covenants for the quarter ended September 30, 2009. We also issued a $10.0 million promissory note with Wells Fargo Bank and a $2.0 million subordinated promissory note with Oaktree Holdings.

On November 6, 2009, we completed the third amendment to our Second Lien Credit Agreement, which waived the leverage ratio for the quarter ended September 30, 2009.

For a complete description of these events, see Note 6 – “Debt”.

 

 

CONDITION AND RESULTS OF OPERATIONS

 

Forward-looking statements

The following discussion should be read in conjunction with the consolidated financial statements and the notes thereto included in this quarterly report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis reported on our 2008 Annual Report on Form 10-K. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. There have been no material changes in the risk factors set forth in our 2008 Annual Report on Form 10-K.

These forward-looking statements include, but are not limited to, statements regarding:

We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For a discussion on risk factors affecting our business, see the information in “ITEM 1A. Risk Factors” contained in our most recent Annual Report filed on Form 10-K with the Securities and Exchange Commission.

Overview

We are an independent energy company engaged in the acquisition, development, exploitation and exploration of natural gas and crude oil properties. We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions. In late 2008 and early 2009, we acquired approximately 12,000 net acres in the Haynesville Shale/Bossier/James Lime play in East Texas, which we refer to as our East Texas resource plays. In 2009, we acquired approximately 2,800 net acres in the Edwards Trend in South Texas. Our focus is on growing our reserves and production by further exploiting our existing property base, through drilling opportunities identified in our new resource plays and our conventional inventory, and by opportunistic acquisitions of underdeveloped properties, including

 

 

leaseholds, in areas where we have specific operating expertise. Our gross revenues are derived from the following sources:

Recent Developments

In the second half of 2008 and early 2009, we obtained natural gas and crude oil leases from mineral interest owners covering approximately 17,000 gross (12,000 net) acres in the natural gas resource play in East Texas specifically in San Augustine, Sabine and Shelby Counties. We commenced our first well (the Kardell #1H), in which we owned a 52% working interest, in this play in late June 2009 and completed that well in October. The well was a successful test of the Haynesville Shale formation, which has a total measured depth of approximately 18,350 feet. The initial 24-hour production experienced from the Kardell #1H well in early November 2009 was 30.7 MMcfe/d (12.0 MMcfe/d to our interest). However, initial production rates in the Haynesville Shale tend to decline steeply in the first 12 months of production and are not necessarily indicative of sustained production rates. We plan to continue to pursue an active drilling program in this area for the next several years, targeting primarily the Haynesville Shale, the mid-Bossier and the James Lime formations. We financed this acquisition with cash flows from operations and from borrowings available under our revolving credit facility.

In May 2008, we acquired four producing gas fields and undeveloped acreage in South Texas from Smith Production Inc. (“Smith”) for a purchase price of $65.0 million with an economic effective date of January 1, 2008. After adjustment for the estimated results of operations, and other typical purchase price adjustments of approximately $7.4 million for the period between the effective date and the closing date, the cash consideration was approximately $57.6 million.

In January 2008, we and our operator-partner entered into a series of agreements to sell our interests in wells and undeveloped acreage in the Fort Worth Barnett Shale Play in Johnson and Tarrant counties, Texas to another industry participant active in that area. We owned a 12.5% non-operated working interest in the assets being sold and had 1.5 Bcfe in proved reserves at December 31, 2007. The total consideration paid by the buyer was based on existing wells and undeveloped acreage owned by us and our partner at the time of the final closing. Our share of the consideration received was approximately $34.4 million. Proceeds received for our interest were primarily used to repay amounts outstanding under our senior revolving credit facility and to help finance our acquisition of the properties from Smith. Our net book value of the assets sold was $18.8 million, which resulted in a gain of $15.6 million.

On November 6, 2009 we issued an unsecured promissory note in the aggregate principal amount of $10.0 million to Wells Fargo Bank, National Association and an unsecured subordinated promissory note in the aggregate principal amount of $2.0 million to our majority stockholder. See Note 6 – “Debt” to Consolidated Financial Statements and “—Liquidity and Capital Resources—Capital Resources.”

 

 

Results of Operations

The following is a discussion of our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our Consolidated Financial Statements and the Notes thereto contained elsewhere in this Form 10-Q.

Comparative results of operations for the periods indicated are discussed below.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues

 

 

Natural Gas, Crude Oil And Natural Gas Liquids Sales. Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our hedging instruments, were $26.7 million for the third quarter 2009 compared to $53.1 million for the third quarter 2008 due to an approximate 29% decrease in production and an approximate 29% decline in realized commodity prices.

 

 

Quarterly production was approximately 3.5 Bcfe for the third quarter 2009 compared to approximately 5.0 Bcfe for the third quarter 2008. On a daily basis, we produced an average of 38,271 Mcfe for the third quarter 2009 compared to an average of 54,126 Mcfe for the third quarter 2008. Production volumes decreased primarily due to natural field decline and limited production-enhancing capital expenditure activity during 2009. However, we did have approximately 364,000 mcfe of lost production and natural gas liquids not processed due to Hurricanes Gustav and Ike in the third quarter 2008.

 

 

 

 

 

 

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $1.6 million on our crude oil hedges and $8.8 million on our natural gas hedges in the third quarter 2009, compared to realized losses of $3.5 million for crude oil hedges and $2.2 million for natural gas hedges in the third quarter 2008.

Costs and Expenses

 

 

(1) Total general and administrative costs include share-based compensation on the Consolidated Statements of Operations.

(2)   Exclusive of impairments and sales.

 

 

(1)  Total general and administrative costs include share-based compensation on the Consolidated Statements of Operations.

 

Lease Operating Expenses. Lease operating expenses for the third quarter 2009 were $3.9 million, compared to $5.7 million in the third quarter 2008, a decrease resulting from the implementation of cost reduction initiatives during 2009 in response to the lower commodity price environment.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the third quarter 2009 were $1.6 million, compared to $4.8 million for the third quarter 2008, due to lower production and lower realized prices in 2009 and state tax credits, net to us, of $0.4 million as a result of our focus on maximizing allowable deductions and opportunities for tax relief for prior periods.

Exploration Expenses. Exploration expenses were $0.7 million in the third quarter 2009 compared to $1.0 million for the third quarter 2008. The decrease in exploration expenses was primarily due to lower geological and geophysical (“G&G”) costs and settled asset retirement costs, offset by higher lease rental and abandoned property costs incurred in the third quarter 2009.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the third quarter 2009 was $13.4 million compared to $13.2 million for the third quarter 2008, primarily due to a higher DD&A rate resulting from the effect of negative price-related reserve revisions offset by lower production in 2009.

Impairment of Oil and Gas Properties. Impairment expense for the third quarter 2009 was zero compared to $25.8 million for the third quarter 2008. The 2008 impairment relates primarily to our capital investment made in pursuing the Rodessa formation within the Madisonville Field. Negative performance-related reserve revisions, including the abandonment of the Rodessa formation in the Johnston 2U well, triggered an evaluation of the Madisonville Field for impairment purposes. Given the high original cost of drilling and developing the field and the high cost of producing and processing sour gas, combined with lower commodity prices, our evaluation resulted in the recorded costs of this field exceeding the estimated future undiscounted cash flow of the reserves as of the end of the third quarter 2008.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $3.8 million for the third quarter 2009 compared to $7.6 million for the third quarter 2008, which includes non-cash stock expense of $0.3 million ($0.10 per Mcfe) and $1.5 million ($0.29 per Mcfe) for the third quarter 2009 and 2008, respectively. The reduction in G&A expenses is primarily a result of the implementation of cost reduction initiatives during 2009.

Interest Expense. Interest expense was $6.6 million for the third quarter 2009, compared to $5.5 million for the third quarter 2008. Total interest expense increased primarily due to higher debt balances and higher interest rates on our second lien credit agreement. Total interest expense capitalized for the third quarter 2009 and 2008 was approximately $25,000 and $0.2 million, respectively.

Other Financing Costs. Other financing costs were $0.4 million for the third quarter 2009 compared with $0.3 million for the third quarter 2008. These expenses are comprised primarily of the amortization of capitalized costs associated with our credit facilities and to commitment fees related to the unused portion of the credit facilities.

Unrealized Gain (Loss) on Derivative Instruments. Unrealized gain or loss on derivative instruments is the change in the mark-to-market exposure under our commodity price hedging contracts and our interest rate swaps. This non-cash unrealized loss for the third quarter 2009 was $9.9 million compared with a non-cash unrealized gain of $88.9 million for the third quarter 2008. Unrealized gain or loss will vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities and interest rates being hedged.

Income Taxes. Our net loss before taxes was $13.4 million for the third quarter 2009 compared to net income before taxes of $78.7 million in the third quarter 2008. After adjusting for permanent tax

 

 

differences, we recorded an income tax benefit of $4.8 million for the third quarter 2009, compared to income tax expense of $28.5 million for the third quarter 2008.

Dividends on Preferred Stock. Dividends on preferred stock were $1.2 million for the third quarter 2009 compared with $1.1 million in the third quarter 2008. Dividends in the third quarter 2009 included approximately $1.1 million on the Series G Preferred Stock and $10,745 on the Series H Preferred Stock. Dividends in the third quarter 2008 included $1.1 million on the Series G Preferred Stock and $28,000 on the Series H Preferred Stock. Until such time as the Board of Directors declares and pays dividends on our Series G Preferred Stock, dividends shall continue to accumulate. Dividends on our Series H Preferred Stock are declared quarterly by our Board of Directors, and are paid out in Common Stock the following quarter.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues

 

 

Natural Gas, Crude Oil And Natural Gas Liquids Sales. Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our hedging instruments, were $85.7 million for the first nine months of 2009 compared to $151.0 million for the first nine months of 2008 due to an approximate 20% decrease in production and an approximate 29% decline in realized commodity prices.

 

 

 

 

Production was approximately 11.7 Bcfe for the first nine months of 2009 compared to approximately 14.6 Bcfe for the first nine months of 2008. On a daily basis, we produced an average of 42,980 Mcfe in the first nine months of 2009 compared to an average of 53,278 Mcfe in the first nine months of 2008. Production volumes decreased primarily due to natural field decline and limited production-enhancing capital expenditure activity in the first nine months of 2009.

 

 

 

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $7.6 million on our crude oil hedges and $23.2 million on our natural gas hedges in the first nine months of 2009, compared to realized losses of $9.4 million for crude oil hedges and $3.8 million for natural gas hedges in the first nine months of 2008.

 

 

Costs and Expenses

 

 

(1) Total general and administrative costs include share-based compensation on the Consolidated Statements of Operations

(2)   Exclusive of impairments and sales.

 

 

(1)  Total general and administrative costs include share-based compensation on the Consolidated Statements of Operations.

Lease Operating Expenses. Lease operating expenses for the first nine months of 2009 were $13.5 million, compared to $15.4 million in the first nine months of 2008, a decrease primarily due to the implementation of cost reduction initiatives in 2009 in response to the lower commodity price environment, offset by the incremental costs in 2009 related to producing properties acquired from Smith at the end of May 2008.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the first nine months of 2009 were $6.1 million, compared to $14.4 million for the first nine months of 2008, due to lower production and lower realized prices in 2009 and state tax credits, net to us, of $0.4 million as a result of our focus on maximizing allowable deductions and opportunities for tax relief for prior periods.

Exploration Expenses. Exploration expenses were $2.9 million in the first nine months of 2009 compared to $1.9 million for the first nine months of 2008. The increase in exploration expenses was primarily due to higher G&G, abandoned property, lease rentals and settled asset retirement costs incurred in the first nine months of 2009.

 

 

Depreciation, Depletion and Amortization . DD&A expense for the first nine months of 2009 was $41.6 million compared to $36.0 million for the first nine months of 2008, primarily due to a higher DD&A rate resulting from the effect of negative price related reserve revisions, partially offset by lower production in 2009.

Impairment of Oil and Gas Properties. Impairment expense for the first nine months of 2009 was zero compared to $25.8 million for the first nine months of 2008. The 2008 impairment relates primarily to our capital investment made in pursuing the Rodessa formation within the Madisonville Field. The impairment relates primarily to the capital investment in pursuing the Rodessa formation within the Madisonville Field. Negative performance-related reserve revisions, including the abandonment of the Rodessa formation in the Johnston 2U well, triggered an evaluation of the Madisonville Field for impairment purposes. Given the high original cost of drilling and developing the field and the high cost of producing and processing sour gas, combined with lower commodity prices, our evaluation resulted in the recorded costs of this field exceeding the estimated future undiscounted cash flow of the reserves as of the end of the third quarter 2008.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $13.4 million for the first nine months of 2009 compared to $17.8 million for the first nine months of 2008, which includes non-cash stock expense of $1.9 million ($0.16 per Mcfe) and $4.3 million ($0.30 per Mcfe) for the first nine months of 2009 and 2008, respectively. The reduction in G&A expenses is primarily a result of the implementation of cost reduction initiatives during 2009.

Gain on Sale of Assets. We sold minimal assets during the first nine months of 2009, while the gain on the sale of assets in the first nine months of 2008 was $15.3 million primarily due to the disposition of our interest in the Barnett Shale Play in January 2008.

Interest Expense. Interest expense was $16.3 million for the first nine months of 2009, compared to $15.9 million for the first nine months of 2008. Total interest expense increased primarily due to higher debt balances and higher interest rates on our second lien credit agreement. Total interest expense capitalized for the first nine months of 2009 and 2008 was approximately $25,000 and $0.8 million, respectively.

Other Financing Costs. Other financing costs were $1.1 million for the first nine months of 2009 compared with $1.2 million for the first nine months of 2008. These expenses are comprised primarily of the amortization of capitalized costs associated with our credit facilities and to commitment fees related to the unused portion of the credit facilities.

Unrealized Gain (Loss) on Derivative Instruments. Unrealized gain or loss on derivative instruments is the change in the mark-to-market exposure under our commodity price hedging contracts and our interest rate swaps. This non-cash unrealized loss for the first nine months of 2009 was $17.2 million compared with a non-cash unrealized gain of $1.7 million for the first nine months of 2008. Unrealized gain or loss will vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities and interest rates being hedged.

Income Taxes. Our net loss before taxes was $25.9 million for the first nine months of 2009 compared to net income before taxes of $40.4 million in the first nine months of 2008. After adjusting for permanent tax differences, we recorded income tax benefit of $9.1 million for the first nine months of 2009, compared to income tax expense of $15.1 million for the first nine months of 2008.

Dividends on Preferred Stock. Dividends on preferred stock were $3.4 million for the first nine months of 2009 compared with $3.2 million in the first nine months of 2008. Dividends in the first nine months of 2009 included approximately $3.3 million on the Series G Preferred Stock and $19,565 on the

 

 

Series H Preferred Stock. Dividends in the first nine months of 2008 included $3.1 million on the Series G Preferred Stock, and $78,000 on the Series H Preferred Stock. Until such time as the Board of Directors declares and pays dividends on our Series G Preferred Stock, dividends shall continue to accumulate. Dividends on our Series H Preferred Stock are declared quarterly by our Board of Directors, and as such, are paid out in Common Stock, the following period.

Liquidity and Capital Resources

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our credit facilities. To the extent our cash requirements exceed our sources of liquidity we will be required to fund our cash requirements through other means, such as through debt and equity financing activities and/or asset monetization, and/or curtail capital expenditures.

Liquidity and cash flow

 

During the last year there has been volatility and disruption in the equity and debt markets. The volatility and disruptions have created conditions and/or business strategies that have adversely affected the financial condition of some of our lenders, the counterparties to our derivative instruments, our insurers and our oil and natural gas purchasers. While, in recent months market conditions have stabilized, continued economic uncertainty may limit our ability to access the equity and debt markets. In addition, though a substantialportion of our production is hedged, we are still subject to commodity price risk and our liquidity may be adversely affected if commodity prices were to decline.

Our working capital deficit was $11.9 million as of September 30, 2009, compared to a working capital deficit of $37.6 million as of December 31, 2008. Current assets decreased $16.8 million, primarily due to the decrease in accounts receivable related to lower revenues and the decrease in the mark to market value of our current net derivatives. Current liabilities, primarily accounts payable and accrued liabilities, decreased $42.6 million due to our reduced capital expenditure activity for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008.

The table below summarizes certain measures of liquidity and capital expenditures, as well as our internal and external sources of capital, for the nine months ended September 30, 2009 and 2008, respectively:

 

		Nine Months Ended September 30,
		2009		2008
Financial Measures		(in millions)
Net cash provided by operating activities	$	2.8		$            96.9
Net cash used in investing activities		(16.0	)	(105.7	)
Net cash provided by financing activities		13.3		14.3
Cash and cash equivalents		—		10.4
Capital expenditures, including acquisitions		16.1		140.6

 

Net cash provided by operating activities was $2.8 million for the nine months ended September 30, 2009, compared to $96.9 million for the nine months ended September 30, 2008, a change resulting primarily from the reduction in revenues, accounts payable and accrued liabilities as well as the change in the mark to market value of our derivatives during the nine months ended September 30, 2009.

 

 

During the first nine months of 2009, the net cash provided by operating activities, before changes in working capital, was $36.4 million. Net cash provided by operating activities, before changes in working capital, was $89.3 million for the first nine months of 2008.

Net cash used in investing activities was $16.0 million for the nine months ended September 30, 2009 compared to $105.7 million for the nine months ended September 30, 2008. Net cash used for investing activities during the nine months ended September 30, 2009 were primarily capital expenditures for the development or maintenance of our proved reserves and the development of our Haynesville Shale natural gas resource play in East Texas. Net cash used in investing activities during the first nine months of 2008 was primarily for the Smith acquisition and capital expenditures for the development of our Southeast Texas properties, offset primarily by proceeds from the sale of our interest in the Barnett Shale Play.

Net cash provided by financing activities was $13.3 million for the first nine months of 2009 compared to $14.3 million for the first nine months of 2008. Net cash provided by financing activities during the first nine months of 2009 was primarily the result of net borrowings under our senior secured revolving credit facility to satisfy the fourth quarter 2008 balance in current liabilities related to our active drilling program in 2008. Net cash provided by financing activities for the first nine months of 2008 was primarily the result of borrowings on debt to fund the Smith acquisition and normal drilling expenditures, offset by repayments of debt from proceeds from the sale of our interest in the Barnett Shale Play and internally generated cash flow from operations.

See the Consolidated Statements of Cash Flows for further details.

Capital resources

 

On November 6, 2009, we entered into a second and third amendment to our senior secured revolving credit facility, dated May 31, 2007, as amended (“Senior Credit Agreement”). This facility provides cash availability for acquisitions of oil and gas properties and for general corporate cash requirements. The Senior Credit Agreement provides for aggregate borrowings of up to $400.0 million, with an initial borrowing base of $200.0 million that decreased to $140.0 million, effective November 2, 2009, and is subject to semi-annual redeterminations, although our lenders may make elect to make one additional redetermination between scheduled redetermination dates (and have expressly reserved the right to do so between January 1, 2010 and May 1, 2010). The next borrowing base redetermination is scheduled for January 1, 2010. These amendments to the Senior Credit Agreement provide, among other things, for (i) a change in the voting percentages required for certain amendments or waivers from 50.1% to 60%, and (ii) a waiver of the current ratio and the leverage ratio for the quarter ended September 30, 2009. The Senior Credit Agreement matures on May 8, 2011. As of September 30, 2009, we had an outstanding loan balance of $141.5 million under our Senior Credit Agreement.

Also, on November 6, 2009, we issued an unsecured promissory note in an aggregate principal amount of $10.0 million to Wells Fargo Bank, National Association, the administrative agent and a lender under our Senior Credit Agreement. This promissory note bears interest at a per annum rate equal to two-month LIBOR plus 2% and matures on January 15, 2010; provided that upon an event of default resulting from the failure to make any payment of principal or interest under the promissory note, the interest rate per annum will increase to an amount equal to the lesser of the maximum rate of interest that may be charged under applicable law and LIBOR plus 4% or, if the promissory note has been assigned to any person other than any affiliate of Wells Fargo Bank, LIBOR plus 15%. All of the proceeds of the promissory note were used to repay indebtedness outstanding under the Senior Credit Agreement. As support for the obligations owed under the promissory note, OCM GW Holdings, LLC (“Oaktree Holdings”), our majority stockholder, has deposited $10.0 million in escrow for the benefit of Wells Fargo, which may, at its option, cause the note to be assigned to Oaktree Holdings and draw on the funds held in escrow.

 

 

As consideration for Oaktree Holdings’ agreement to deposit $10.0 million in escrow as described above, we issued an unsecured subordinated promissory note on November 6, 2009 in aggregate principal amount of $2.0 million to Oaktree Holdings. The indebtedness under the promissory note bears interest at a rate equal to 8.0% per annum and matures on the later of (i) November 8, 2012 and (ii) the date six months after payment in full in cash of all Obligations (as such term is defined under each of the Senior Credit Agreement and the Second Lien Credit Agreement (defined below)), and the termination of all commitments to extend credit under the Senior Credit Agreement and the Second Lien Credit Agreement. The promissory note is subordinated in right of payment to the prior payment in full in cash of all obligations under the Senior Credit Agreement and the Second Lien Credit Agreement.

On July 31, 2009, we entered into the first amendment to our Senior Credit Agreement. This amendment to the Senior Credit Agreement provides, among other things, for (i) the leverage ratio to be not greater than 2.75 to 1.00 for each fiscal quarter, (ii) the current ratio to be not less than 1.00 to 1.00 for each fiscal quarter, (iii) an increased applicable margin on LIBOR loans to between 2.75% and 3.50%, and base rate loans to between 1.50% and 2.00%, depending on the percent of the borrowing base utilized at the time of the credit extension, and (iv) an increased commitment fee on unutilized commitments to 0.50%.

On November 6, 2009, we entered into a third amendment and waiver to our second lien credit agreement dated May 8, 2007, as amended (the “Second Lien Credit Agreement”), with lenders holding a majority of the then outstanding term loans under such agreement, which included an affiliate of Oaktree Holdings. The Second Lien Credit Agreement provides for a term loan in an aggregate principal amount of $150.0 million, with a term of five years with all principal amounts, together with all accrued and unpaid interest, due and payable in full on May 8, 2012. The third amendment to our Second Lien Credit Agreement provided, among other things, for a waiver of the leverage ratio covenant for the quarter ended September 30, 2009.

The Senior Credit Agreement and the Second Lien Credit Agreement (the “Credit Agreements”) are secured by a lien on substantially all of our assets, as well as a security interest in the stock of our subsidiaries. The obligations under the Second Lien Credit Agreement are junior to those under the Senior Credit Agreement. Interest is payable on the Credit Agreements as borrowings mature and renew.

The Credit Agreements include usual and customary affirmative covenants for credit facilities of the respective types and sizes, as well as customary negative covenants, including, among others, limitations on liens, hedging, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, certain leases and investments outside of the ordinary course of business, as well as events of default. The Credit Agreements also contain certain financial and proved reserve covenants. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” of our 2008 Annual Report on Form 10-K for a more detailed description of our covenants under the Credit Agreements, other than those revised above. At September 30, 2009, we were in compliance with the aforementioned covenants, with the exception of the current ratio under the Senior Credit Agreement and the leverage ratio under both of the Credit Agreements. We obtained waivers of such noncompliance from our lenders under the Credit Agreements for the quarter ended September 30, 2009. However, without improvement in natural gas and crude oil prices, reduction in debt levels, improvement in production volumes and/or other measures, we may not be able to comply with certain covenants under our Credit Agreements for future quarters. We continue to pursue other public and private sources of capital which would positively affect our debt covenant ratios and we continue to work with our lenders on long term amendments to our covenants. If we are unable to comply with the covenants for future quarters, we believe that it is not probable that we would not be able to cure future covenant violations by obtaining additional capital or by obtaining waivers from our lenders to cure the defaults, although we can give no assurances that any such sources of capital will be available or that such amendments will be entered into, or on terms acceptable to us. If we were not

 

 

able to comply with our covenants in the future, and we were not able to obtain waivers from our lenders to cure such defaults, our lenders would have the right to demand acceleration of payment on all amounts outstanding under our Credit Agreements. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. See Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2008.

At November 10, 2009, we had $129.5 million outstanding under the Senior Credit Agreement and $150.0 million outstanding under the Second Lien Credit Agreement, with availability under the Senior Credit Agreement of $10.5 million. As discussed above, we also had $10.0 million outstanding under a promissory note with Wells Fargo Bank, a lender under the Senior Credit Agreement and a $2.0 million subordinated promissory note with Oaktree Holdings.

Future capital requirements

 

Our future natural gas, crude oil and natural gas liquids reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We intend to grow our reserves and production by further exploiting our existing property base, through drilling opportunities identified in our new resource plays in East and South Texas and in our conventional inventory. We expect to focus much of our drilling activity over the next several years on continued development of our East Texas resource plays while we continue the development and exploitation of our core legacy properties in the South Texas and Gulf Coast areas. We anticipate that acquisitions, including undeveloped leasehold interests, will continue to play a significant role in our business strategy as those opportunities periodically arise from time to time. While there are currently no unannounced agreements for the acquisition of any material businesses or assets, such transactions can be effected quickly and could occur at any time.

 

We believe that our internally generated cash flow, combined with access to our Senior Credit Agreement will be sufficient to meet the liquidity requirements necessary to fund our daily operations, limited capital development and existing debt service requirements for the next 12 months. Our ability to execute on our growth strategy will be determined, in large part, by the availability of debt and equity capital at that time, and we continuously evaluate our financing opportunities. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors. Our ability to meet our liquidity requirements and execute on our growth strategy can be impacted by economic conditions outside of our control, such as the recent disruption in the capital and credit markets, as well as continued commodity price volatility, which could, among other things, lead to a decline in the borrowing base under our Senior Credit Agreement in connection with a borrowing base redetermination. In addition, if we fail to maintain compliance with our financial covenants under either Credit Agreement as of the end of any fiscal quarter, this failure would be an event of default under the Senior Credit Agreement that would permit participating banks to restrict our ability to access the revolving facility under the Senior Credit Agreement, and could accelerate repayment of any outstanding amounts under the Credit Agreements, unless waived by our lenders or those provisions are amended. In such cases, we may be required to seek other sources of capital earlier than anticipated, although the restrictions in our Credit Agreements and in our agreements with our majority shareholder may impair our ability to access other sources of capital, and access to additional capital may not be available on terms acceptable to us or at all. See Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2008.

 

 

Recent Accounting Pronouncements

SEC 33-8995/34-59192. In December 2008, the SEC adopted Release No. 33-8995/34-59192, “Modernization of Oil and Gas Reporting” (“SEC 33-8995”). This release amends the oil and gas reporting disclosures that exist in their current form in Regulation S-K and Regulation S-X under the Securities Act of 1933 and the Securities Exchange Act of 1934 to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The new rules include changes for pricing used to estimate reserves; permitting disclosure of possible and probable reserves; ability to include non-traditional resources in reserves and the use of new technology for determining reserves. SEC 33-8995 is effective for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. We are currently evaluating the provisions of SEC 33-8995 and assessing the impact it may have on our financial reporting disclosures.

 

The following market rate disclosures should be read in conjunction with our financial statements and notes thereto beginning on Page F-1 of our 2008 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. All of our financial instruments are for purposes other than trading. Hypothetical changes in interest rates and prices chosen for the following simulated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates and product prices. Accordingly, these hypothetical changes may not be an indicator of probable future fluctuations. See Note 5 — “Derivative Instruments” to our consolidated financial statements included herein for further information.

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates. To manage this risk and reduce our sensitivity to volatile interest rates, we have entered into interest rate swap agreements with a total notional amount of $200.0 million related to our Senior Credit Agreement. However these interest rate swap agreements limit the benefit of decreases in interest rates. Moreover, these swap agreements apply only to a portion of our debt and provide only partial protection against increases in interest rates. Under these agreements, we receive interest at a floating rate equal to one-month LIBOR and pay interest at a fixed rate of 1.50% on $50.0 million in outstanding debt and pay interest at 2.90% on $150.0 million in outstanding debt, effectively setting our base LIBOR rate at 2.6%. As of September 30, 2009, the interest rate swaps had an estimated net fair value liability of $5.2 million. Assuming our current level of borrowings and considering the effect of the interest rate swap agreements, a 100 basis point increase in the interest rate we pay under our Senior Credit Agreement would not have had a material impact on our interest expense for the nine months ended September 30, 2009.

Commodity Price Risk

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our natural gas, crude oil and natural gas liquids production, to reduce our sensitivity to volatile commodity prices. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and reduce our exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of natural gas, crude oil and natural gas liquids sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. We expect that the monthly volume of derivative arrangements will vary from time to time. We continuously reevaluate our price

 

 

hedging program in light of increases in production, market conditions, commodity price forecasts, capital spending and debt service requirements.

Counterparty Risk

We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. We believe our counterparty risk related to our derivatives is low because of the offsetting relationships we have with each of our counterparties. In addition, we also have exposure to financial institutions within our credit facilities. If any lender under our senior credit facility is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under that credit facility.

 

 

Our President and Chief Executive Officer and our Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by this Form 10-Q, that our disclosure controls and procedures, as defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, are effective to ensure that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that our disclosure controls and procedures are effective to ensure that information we are required to disclose in such reports is accumulated and communicated to management, including our President and Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

During the period covered by this report, there has been no change to our internal controls over financial reporting that materially affected, or is reasonably likely to materially affect, these controls.

 

 

PART II.     OTHER INFORMATION

 

 

During the second quarter of 2009, holders of oil and gas leases in East Texas (Haynesville Shale) filed two causes of action against us alleging breach of contract for not paying lease bonuses on certain oil and gas leases taken by our leasing agent.  The damages alleged are approximately $2.8 million, and together with approximately $300,000 in written demands from other holders of leases in this area that we believe may contemplate legal proceedings, are greater than 10% of our current assets as of September 30, 2009. Prior to this period, it did not represent greater than 10% of current assets.  We are vigorously defending these lawsuits, which we believe are completely without merit.  We believe that the plaintiffs’ probability of success is remote and do not believe that these claims will have a material adverse affect on our business, financial position, results of operations or cash flows, although we cannot guarantee that a material adverse effect will not occur.

 

 

We withheld the following shares of Crimson common stock to satisfy tax withholding obligations during the third quarter 2009 from the distributions described below. These shares may be deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this item.

 

 

(1)  Shares were withheld from employees to satisfy certain tax withholding obligations due in connection with grants of stock under our 2005 Stock Incentive Plan. The 2005 Stock Incentive Plan provides from the withholding of shares to satisfy tax obligations.

 

 

 

 

 

 

 

 

 

 

SIGNATURES

 

Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

CRIMSON EXPLORATION INC.

(Registrant)