FORM 10-Q

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

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

THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended September 30, 2008

 

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 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 7, 2008, there were 5,795,632 shares outstanding of the Registrant’s Common Stock, par value $0.001.

 

 

FORM 10-Q

 

CRIMSON EXPLORATION INC.

 

FOR THE QUARTER ENDED SEPTEMBER 30, 2008

 

 

 

 

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.

 

 

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

SEPTEMBER 30, 2008 AND 2007

(UNAUDITED)

 

Crimson Exploration Inc., together with its subsidiaries, (“Crimson”, “we”, “our”, “us”) is an independent energy company engaged in the acquisition, development, exploitation and production of crude oil, natural gas and natural gas liquids, principally in the onshore gulf coast regions of Texas and Louisiana and in Colorado.

 

 

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, 2008 (unaudited) and December 31, 2007 and for the three and nine months ended September 30, 2008 and 2007 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three and nine month periods ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. These 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, 2007.

 

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.

 

Adoption of SFAS 157 – We adopted Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“SFAS 157”) as of January 1, 2008. SFAS 157 establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. Adoption did not have a significant impact on our consolidated financial statements. See Note 4 – Derivative Instruments.

 

Adoption of SFAS 159 – We adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”) as of January 1, 2008. SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. Adoption had no effect on our consolidated financial statements as we made no elections to report selected financial assets or liabilities at fair value.

 

 

3.              OIL AND GAS PROPERTIES

Impairment of Madisonville Field

In September 2008, we recorded non-cash impairment expense of $25.8 million related to our Madisonville Field in Central Texas. 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 quarter. Pursuant to the provisions of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we recorded as an impairment expense the excess of the unamortized capitalized costs of this field over the field’s estimated fair value. The field’s estimated fair value was calculated using various fair value calculation methods including a $/Mcfe valuation and the discounted present value of the field’s remaining cash flows.

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 $65.0 million in cash with an effective date of January 1, 2008. The assets acquired consist of a 25% non-operated working interest in Samano Field located in Starr and Hidalgo counties, a 100% operated working interest in North Bob West Field in Zapata County and 100% operated working interests in Brushy Creek and Hope Fields in DeWitt County. Crimson acquired an interest in over 16,000 gross acres with these fields, most of which is held by production.

After adjustment for the estimated results of operations, and other typical purchase price adjustments of approximately $8.2 million for the period between the effective date and the closing date the cash consideration was $56.8 million, subject to final adjustment, if any, by January 2009.

Including the proved reserves from the Smith Acquisition, our pro forma total proved reserves at January 1, 2008 would have been approximately 152 bcfe. Production from the acquired assets was averaging approximately 7 mmcfe per day at closing, which resulted in a 13% increase in our then current net daily production.

The $56.8 million adjusted price, with adjustment of the reserves for approximately one bcfe of production for the interim operations between the effective date and closing, represented a purchase cost of $2.76 per mcfe for approximately 21 bcfe of proved reserves and $8,100 per mcfe of current average daily production. We financed this acquisition with cash flows from operations, proceeds from the sale of assets and from borrowings available under the Senior Credit Agreement (defined below).

For the nine months ended September 30, 2008, four months of revenues and expenses, $7.9 million and $1.7 million, respectively, were included in our financial results of operations.

Sale of Barnett Shale Interests

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 Credit Agreement (defined below) and to help finance the Smith Acquisition. Our net book value of these assets sold was $18.8 million, which resulted in a gain of $15.6 million.

Acquisition from EXCO Resources Inc.

On May 8, 2007, we entered into a purchase agreement with EXCO Resources, Inc. (“EXCO”) and Southern G Holdings, LLC (“SGH”) (the “EXCO Purchase Agreement”), pursuant to which we acquired, for $285.0 million in cash (excluding adjustments) and 750,000 shares of Common Stock, par value $0.001 per share (“Common Stock”) certain oil and natural gas properties and related assets in the South Texas and Gulf Coast areas of Louisiana and Texas (the “STGC Properties”) held by SGH immediately before the closing of the acquisition. After considerations for typical closing adjustments, $229.0 million of the purchase price was allocated to proved properties and $28.6 million was allocated to unproved properties. EXCO acquired the properties and assets as part of a larger property package on May 4, 2007, from Anadarko Petroleum Corporation and certain of its affiliates. The properties acquired include approximately 215 producing wells in over 30 fields. We have an average 65% working interest in the properties and operate more than 80% of the value acquired. The major producing fields acquired reside in Liberty and Lavaca counties of the Upper Texas Gulf Coast, Brooks County of South Texas and Calcasieu Parish of South Louisiana. The properties and related assets were acquired through the conveyance of 100% of the membership interests of SGH from EXCO to us. The consolidated statements of operations include the results of operations of the STGC Properties from May 2007 to December 2007 and the full year 2008.

The unaudited pro forma results presented below for the nine months ended September 30, 2007 have been prepared to give effect to the STGC Properties acquisition described above on our results of operations as if it had been consummated on January 1, 2007. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if this acquisition had been completed on such date or project our results of operations for any future date or period.

 

		Nine Months Ended
		September 30, 2007
		(unaudited) (in thousands, except per share data)
Pro forma:
Operating revenues		$	113,738
Income from operations		$	47,360
Net income		$	19,810
Basic earnings per share		$	3.79
Diluted earnings per share		$	2.07

 

 

 

 

4.             DERIVATIVE INSTRUMENTS

 

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our oil and natural gas 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. 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 crude oil and natural gas 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.

 

We account for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and all derivative instruments are reflected at fair value on our consolidated balance sheets. We elected not to designate our derivative instruments as cash flow hedges. We recognize all gains and losses on such instruments in earnings during the period in which they occur.

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 and debt service requirements.

 

 

 

 

The total net liability for derivative instruments at September 30, 2008 and December 31, 2007 was $13.6 million and $15.3 million, respectively. As a result of these agreements, we recorded an unrealized, non-cash gain, for unsettled contracts, of $88.9 million and $1.7 million for the three and nine months ended September 30, 2008, respectively and an unrealized, non-cash gain of $0.6 million and an unrealized non-cash charge of $0.3 million for the three and nine months ended September 30, 2007, respectively. The estimated change in fair value of the derivatives is reported in Other Income (Expense) as unrealized gain (loss) on derivative instruments.

For oil and gas derivatives settled during 2008, we realized losses, reflected in operating revenues, of $5.7 million and $13.2 million for the three and nine months ended September 30, 2008, respectively. For oil and gas derivatives settled during 2007, we realized gains of $3.4 million and $3.7 million for the three and nine months ended September 30, 2007, respectively. For interest rate swaps, we realized losses, included in interest expense, of $1.3 million and $2.9 million for the three and nine months ended September 30, 2008, respectively. We realized gains, included in interest expense, of $0.1 million and $0.2 million from interest rate swaps for the three and nine months ended September 30, 2007, respectively.

Adoption of SFAS 157

Effective January 1, 2008, we adopted SFAS 157, as discussed in Note 2, which, among other things, requires enhanced disclosures about financial assets and liabilities carried at fair value. As defined in SFAS 157, fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and lowest priority to unobservable inputs (Level 3). The three levels of fair value hierarchy defined by SFAS 157 are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves and, therefore, are considered Level 2.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At September 30, 2008, we had no Level 3 measurements.

 

 

The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis, as set forth in SFAS 157 as of September 30, 2008 (in thousands):

 

On May 8, 2007, we entered into a $400.0 million amended and restated credit agreement (the “Senior Credit Agreement”) with Wells Fargo Bank, National Association, as agent, which amended and restated our then existing senior secured revolving credit facility dated July 15, 2005, as amended. On May 8, 2007, we borrowed $122.7 million pursuant to the Senior Credit Agreement to pay the consideration under the EXCO Purchase Agreement and to refinance certain existing indebtedness.

 

Borrowings under the Senior Credit Agreement are subject to a borrowing base limitation based on our proved oil and gas reserves. The borrowing base was reaffirmed at $200.0 million on November 1, 2008 and is subject to semi-annual redeterminations. The Senior Credit Agreement has a term of four years and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on May 8, 2011. We also constructively fixed the base LIBOR rate on $200.0 million of our variable rate debt through July 8, 2009 by entering into interest rate swaps at a swap price of 5.02%.

 

In addition, on May 8, 2007, we entered into a second lien credit agreement (the “Second Lien Credit Agreement”) with Credit Suisse, as agent, which provides for term loans to be made to us in a single draw in an aggregate principal amount of $150.0 million. On May 8, 2007, we borrowed $150.0 million pursuant to the Second Lien Credit Agreement to pay the consideration under the EXCO Purchase Agreement and to refinance certain existing indebtedness. The Second Lien Credit Agreement replaced our then existing $150.0 million subordinate credit facility, which was paid off in full and terminated at closing. The Second Lien Credit Agreement has a term of five years and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on May 8, 2012.

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 subordinate and junior to those under the Senior Credit Agreement. Interest is payable on the Credit Agreements as borrowings mature and renew. At September 30, 2008, we were in compliance with the Credit Agreements' covenants.

At September 30, 2008, we had $124.0 million outstanding under the Senior Credit Agreement and $150.0 million outstanding under the Second Lien Credit Agreement.

In the third quarter 2008, we issued 56,000 shares of our Common Stock, in conjunction with the exercise of employee stock options. We issued 14,286 shares of Common Stock in conjunction with the conversion of 100 shares of Series H Preferred Stock. We issued 4,400 shares of Common Stock in payment of dividend on Series H Preferred Stock valued at approximately $53,900 based on the closing market price on the date the shares were issued. We issued 1,538 shares of Common Stock pursuant to

 

 

restricted stock awards to two members of our board of directors as compensation pursuant to the Director Compensation Plan.

 

In the third quarter 2008, 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. Under SFAS 123R, 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.

 

In the second quarter 2008, we issued 17,000 shares of Common Stock in conjunction with the exercise of employee stock options.

 

 

In the first quarter 2008, we issued 34,821 shares of Common Stock in conjunction with the conversion of 500 shares of Series G Preferred Stock of which 7,043 shares were for accrued dividends. We issued 2,200 shares of Common Stock in payment of dividends on Series H Preferred Stock valued at approximately $21,000 based on the closing market price on the date the shares were issued. We also issued 2,000 shares of Common Stock in conjunction with the exercise of stock options.

Dividends on all classes of our preferred stock are cumulative until declared as payable by our Board of Directors. Series G Preferred Stock accumulates at 8% per annum, compounded quarterly, payable in cash and Series H Preferred Stock accumulates at 4 shares of our Common Stock per share of the Series H Preferred Stock per annum, payable quarterly as declared.

The following table sets forth the accumulated value of undeclared dividends of our preferred stock:

 

 

 

The Series G Preferred Stock dividends are convertible to our Common Stock at $9.00 per common share. The Series H Preferred Stock has no conversion feature for unpaid dividends. These dividends call for payment of one share of Common Stock per quarter for each preferred share.

 

Compensation Expense

 

The following table reflects share based compensation expense currently outstanding, assuming a 36.5% effective tax rate (in millions, except per share data):

 

 

 

In the third quarter 2008, our Board of Directors formally adopted an amendment to one performance based bonus plan and adopted a new performance based bonus plan for the benefit of all employees - the Crimson Cash Incentive Bonus Plan (“CIBP”) and the Crimson Long-Term Incentive Plan (“LTIP”), respectively. Both plans and specific targeted performance measures for the fiscal year 2008 were previously approved by the Compensation Committee. Upon achieving the established performance levels, bonus awards will be calculated as a percentage of base salary for the plan year. The plan awards will be disbursed in the first quarter of 2009. Employees must be employed by us at the time that final plan awards are dispersed to be eligible.

 

The CIBP will pay awards out in cash (“Cash Awards”). The performance targets will be evaluated on a quarterly basis and used to estimate the approximate expense earned to date. Approximately $2.2 million was recognized in the third quarter, after formal adoption, as compensation expense related to the Cash Awards for the nine months ended September 30, 2008.

 

The LTIP bonus awards will be paid half in the form of restricted Common Stock and half in the form of stock options (“Stock Awards”). The Stock Awards will vest 25% per year, over the first through fourth anniversaries from the date of grant, at which time 100% of all Stock Awards will be vested. The number of shares of restricted Common Stock and the number of shares underlying the stock options to be granted as Stock Awards will be determined based upon the fair market value of the Common Stock on the date of the grants in the first quarter 2009. The fair value of the stock options to be awarded as part of this plan will be determined through use of the Black-Scholes valuation model. The Stock Awards to be granted pursuant to this plan will be granted under the existing amended and restated 2005 Stock Option Plan. The Board of Directors, and a majority of the Common Stock equivalents entitled to vote, has approved an increase in the number of available shares of Common Stock issuable under the amended and restated 2005 Stock Option Plan by 1,000,000 shares, which will accommodate any Stock Awards to be awarded under the LTIP.

 

 

9.           INCOME TAXES

 

Income tax expense for the nine months ended September 30, 2008 was $15.1 million, of which $9.7 million was current tax expense and $5.5 million was deferred.  The income tax expense of $5.5 million for the nine months ended September 30, 2007 was all deferred.  The effective statutory tax rate was 36.8% for the nine months ended September 30, 2008.

Deferred tax assets at September 30, 2008 and December 31, 2007 are shown net of a $3.4 million valuation allowance. The valuation allowance was recorded because we expect we will not be able to use net operating loss carryforwards of approximately $9.1 million due to the limitations of Internal Revenue Code Section 382.

 

Haynesville Acreage Acquisition

We acquired during the third and fourth quarters of 2008 approximately 10,000 net undeveloped acres in Sabine, Shelby and San Augustine counties Texas on which we will target the Haynesville Shale, James Lime, and Travis Peak. We are currently developing a drilling strategy for this acreage, including unit and well spacing, with the expectation that we will commence our first vertical test during the first quarter of 2009. We will continue to acquire additional acreage that complements our existing position for the remainder of the year, and expect to have an active drilling program in this area by mid-year 2009.

 

SFAS 162 - In May 2008, the Financial Accounting Standards Board (“FASB”) issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Prior to the issuance of SFAS 162, GAAP hierarchy was defined in the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. SFAS 162 is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. We believe that the adoption of this statement will not have a material impact on our financial statements.

SFAS 161 - In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133 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 under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the provisions of SFAS 161 and assessing the impact it may have on our financial reporting disclosures.

SFAS 141(R) - In December 2007, the FASB issued a revision to SFAS 141 “Business Combinations” (“SFAS 141(R)”). 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,

 

 

the statement establishes principles and requirements for how an acquirer recognizes assets acquired, liabilities assumed and any non-controlling interests acquired. SFAS 141(R) is effective for business combination transactions for which the acquisition date is on or after the beginning of the first reporting period beginning on or after December 15, 2008. Early adoption is prohibited. We are currently evaluating the provisions of SFAS 141(R) and assessing the impact it may have on our financial position and results of operations.

 

SFAS 157-2 - In September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (“SFAS 157”). We adopted SFAS 157 effective January 1, 2008 only for our financial assets and financial liabilities. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This standard provides guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The adoption of SFAS 157, as it applied to our financial assets and financial liabilities did not have a material impact on our consolidated financial statements. In February 2008, FASB issued Staff Position (“FSP”) No. SFAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-2 defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, 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). An entity that has issued interim or annual financial statements reflecting the application of the measurement and disclosure provisions of SFAS 157 prior to February 12, 2008, must continue to apply all provisions of SFAS 157. We are currently evaluating the provisions of FSP 157-2 and assessing the impact it may have on our financial position, results of operations and reporting disclosures.

 

 

ITEM 2.       MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

 

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 2007 Annual Report on Form 10-K. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties.

 

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 primarily engaged in the acquisition, development, exploitation and production of crude oil and natural gas, primarily in the onshore producing regions of the United States. Our focus is on increasing production from our existing properties through further exploitation, development and exploration, and on acquiring additional interests in undeveloped crude oil and natural gas properties. Our gross revenues are derived from the following sources:

 

1.  Oil, gas and natural gas liquids sales that are proceeds from the sale of crude oil and natural gas production to midstream purchasers. This represents over 99% of our gross revenues.

 

 

2.  Operating overhead and other incomethat consists primarily of administrative fees received for operating crude oil and natural gas properties for other working interest owners and for marketing and transporting natural gas for those owners.

 

Acquisition

 

In May 2008, we acquired four producing gas fields and undeveloped acreage in South Texas from Smith Production Inc. (“Smith”) for $65.0 million in cash with an effective date of January 1, 2008. The assets acquired consist of a 25% non-operated working interest in Samano Field located in Starr and Hidalgo counties, a 100% operated working interest in North Bob West Field in Zapata County and 100% operated working interests in Brushy Creek and Hope fields in DeWitt County. Crimson acquired an interest in over 16,000 grossacres with these fields, most of which is held by production.

After adjustment for the estimated results of operations, and other typical purchase price adjustments, of approximately $8.2 million for the period between the effective date and the closing date, the cash consideration was $56.8 million, subject to final adjustment, if any, by January 2009.

Including the proved reserves from the Smith Acquisition, our pro forma total proved reserves at January 1, 2008 would have been approximately 152 bcfe. Production from the acquired assets was averaging approximately 7 mmcfe per day at closing, which resulted in a 13% increase in our then current net daily production.

The $56.8 million adjusted price, with adjustment of the reserves for approximately one bcfe of production for the interim operations between the effective date and closing, represented a purchase cost of $2.76 per mcfe for approximately 21 bcfe of proved reserves and $8,100 per mcfe of current average daily production. We financed this acquisition with cash flows from operations, proceeds from the sale of assets and from borrowings available under the Senior Credit Agreement (defined below).

For the nine months ended September 30, 2008, four months of revenues and expenses, $7.9 million and $1.7 million, respectively, were included in our financial results of operations.

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 Credit Agreement (defined below) and to help finance our acquisition of Smith. Our net book value of these assets sold was $18.8 million, which resulted in a gain of $15.6 million.

Subsequent Event

We acquired during the third and fourth quarters of 2008 approximately 10,000 net undeveloped acres in Sabine, Shelby and San Augustine counties Texas on which we will target the Haynesville Shale, James Lime, and Travis Peak. We are currently developing a drilling strategy for this acreage, including unit and well spacing, with the expectation that we will commence our first vertical test during the first quarter of 2009. We will continue to acquire additional acreage that complements our existing position for the remainder of the year, and expect to have an active drilling program in this area by mid-year 2009.

 

 

Results of Operations

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

 

Three-Months Ended September 30, 2008 compared to Three-Months Ended September 30 2007.

 

Revenues

 

Oil, Gas 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, increased by 40% to $53.1 million in the third quarter 2008, compared to $37.9 million in the third quarter 2007. The increase in net revenues was primarily due to increases in net realized commodity prices, the success of our drilling program, the effect of the South Texas acquisition from Smith, offset by lost production and natural gas liquids not processed due to Hurricanes Gustav and Ike.

 

Our third quarter 2008 sales volumes were 123,080 barrels of crude oil, 3,494,392 mcf of natural gas and 124,460 barrels of natural gas liquids, or 4,979,632 natural gas equivalents (mcfe), an increase of approximately 8%, compared to 129,824 barrels of crude oil, 3,196,683 mcf of natural gas and 108,969 barrels of natural gas liquids, or 4,629,441 mcfe produced in the third quarter 2007. We had approximately 364,000 mcfe of lost production and natural gas liquids not processed due to Hurricanes Gustav and Ike in the third quarter 2008. On a daily basis, we produced an average of 54,126 mcfe in the third quarter 2008 compared to an average of 50,320 mcfe in the third quarter 2007.

 

Oil and gas prices are reported net of the realized effects of our hedging agreements. Prices realized in the third quarter 2008 were $92.54 per barrel of oil, $9.68 per mcf of natural gas and $63.49 per barrel of natural gas liquids compared to $66.47 per barrel of oil, $7.60 per mcf of natural gas and $45.17 per barrel of natural gas liquids in the third quarter 2007. Prices before the realized effects of the hedging agreements were $120.88 per barrel of oil, $10.32 per mcf of natural gas and $63.49 per barrel of natural gas liquids in the third quarter 2008 compared to $73.97 per barrel of oil, $6.24 per mcf of natural gas and $45.17 per barrel of natural gas liquids in the third quarter 2007.

 

We realized losses of $3.5 million on our oil hedges and $2.2 million on our gas hedges, in the third quarter 2008, compared to a realized loss of $1.0 million for oil hedges and a gain of $4.3 million for gas hedges in the third quarter 2007.

 

Operating Overhead and Other Income. Revenues from working interest partners increased to approximately $0.6 million in the third quarter 2008 compared with $0.2 million in the third quarter 2007 due to the increase in administrative overhead fees charged to our partners on the operated acquired properties and a one-time catch up on overhead billings due to the increase in COPAS rates.

 

Costs and Expenses

 

Lease Operating Expenses. Lease operating expenses for the third quarter 2008 were $10.5 million, compared to $6.6 million in the third quarter 2007. The increase in lease operating expenses was primarily due to the addition of the South Texas properties from the Smith acquisition, higher production taxes on higher prices and volumes, and increased expense workovers. On a per unit basis, lease operating expenses increased to $2.10 per mcfe for the third quarter 2008 from $1.42 per mcfe for the third quarter 2007, primarily due to the minimal change in volumes.

 

Exploration Expense. Exploration expense was $0.7 million for the third quarter 2008 compared to $0.9 million in the third quarter 2007. Geological and geophysical costs were $0.7 million and lease

 

 

rentals were minimal for the third quarter 2008. Geological and geophysical costs were $0.8 million and lease rentals were $0.1 million for the third quarter 2007. We intend to continue to invest capital in seismic data and lease rental costs as we develop and expand our internal exploratory prospect generation capability.

 

Depreciation, Depletion and Amortization (DD&A). DD&A expense for the third quarter 2008 was $13.0 million compared to $11.7 million for the third quarter 2007. On a per unit basis, DD&A expense increased to $2.61 per mcfe for the third quarter 2008, compared to $2.52 per mcfe in the third quarter 2007.

 

Impairment of Oil and Gas Properties. In September 2008, we recorded a non-cash impairment expense of $25.8 million related to our Madisonville Field in Central Texas. 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 quarter.

 

Asset Retirement Obligations (ARO). ARO expense for the third quarter 2008 was $0.5 million compared to $0.1 million for the third quarter 2007. Accretion was $0.2 million and $0.1 million for the third quarters 2008 and 2007, respectively. Settled ARO was $0.3 million and zero for the third quarters 2008 and 2007, respectively.

 

General and Administrative (G&A) Expenses. G&A expenses were $7.6 million for the third quarter 2008 compared to $3.8 million for the third quarter 2007. Included in G&A expense is a non-cash stock expense of $1.4 million ($0.28 per mcfe) for the third quarter 2008 and $1.2 million ($0.26 per mcfe) for the third quarter 2007. Also in G&A expense for the third quarter 2008 is a the accrual of $2.2 million estimated for the nine months period ended September 30, pursuant to the final adoption of our annual bonus plan by the Board of Directors during the quarter. On a per unit basis, G&A expense increased to $1.52 per mcfe in the third quarter 2008 from $0.82 per mcfe in the third quarter 2007, due to higher personnel costs, information technology costs and professional fees in expanding our infrastructure.

 

Gain on Sale of Assets. We had no sale of assets for the third quarter 2008. The gain on the sale of assets for the third quarter 2007 was $0.7 million.

 

Interest Expense. Interest expense was $5.5 million for the third quarter 2008, compared to $6.0 million for the third quarter 2007. Interest expense decreased primarily as a result of lower interest rates. Total interest expense capitalized in the third quarters of both 2008 and 2007 was $0.2 million and $0.2 million, respectively.

 

Other Financing Costs. Other financing costs were $0.3 million for the third quarter 2008 compared with $0.4 million for the third quarter 2007. These expenses are comprised primarily of the amortization of capitalized costs associated with our credit facilities in place at the time and to commitment fees related to the unused portion of the credit facilities.

 

Unrealized Gain on Derivative Instruments. Unrealized gain or loss on derivative instruments is the change in the quarter in the mark-to-market exposure under our commodity price hedging instruments and our interest rate swap. This non-cash unrealized gain for the third quarter 2008 was $88.9 million compared with the non-cash unrealized gain of $0.6 million for the third quarter 2007. This amount will

 

 

vary period to period, and will be a function of the hedges in place, the strike prices of those hedges, and the forward curve pricing of the commodities and interest rates being hedged.

 

Income Taxes. Our net income before taxes was $78.7 million for the third quarter 2008 compared to $9.9 million for the third quarter 2007. After adjusting for permanent tax differences, we recorded an income tax expense of $28.5 million for the third quarter 2008 compared to $3.8 million for the third quarter 2007.

 

Dividends on Preferred Stock. Dividends on preferred stock were $1.1 million for the third quarter 2008 compared with $1.7 million for the third quarter 2007. Dividends for the third quarter 2008 included $1.1 million on the Series G Preferred Stock and $28,000 on the Series H Preferred Stock. Dividends for the third quarter 2007 included $1.7 million on the Series G Preferred Stock, $17,000 on the Series H Preferred Stock.

 

Nine-month Period Ended September 30, 2008 compared to Nine-month Period Ended September 30, 2007.

 

Revenues

 

Oil, Gas 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, increased by 119%, to $150.9 million in the first nine months of 2008 compared to $69.0 million in the first nine months of 2007. The increase in net revenues was primarily due to increases in net realized commodity prices, the success experienced in our drilling program, the full-year effect of the STGC properties acquisition and the four-month effect of the South Texas acquisition with Smith, offset by lost production and natural gas liquids not processed due to Hurricanes Gustav and Ike.

 

For the first nine months of 2008, sales volumes were 385,458 barrels of crude oil, 9,752,667 mcf of natural gas and 422,107 barrels of natural gas liquids, or 14,598,057 natural gas equivalents (mcfe), an increase of approximately 72% compared to 261,117 barrels of crude oil, 6,032,848 mcf of natural gas and 143,875 barrels of natural gas liquids, or 8,462,800 natural gas equivalents (mcfe) produced in the first nine months of 2007. We had approximately 364,000 mcfe of lost production and natural gas liquids not processed due to Hurricanes Gustav and Ike in the third quarter 2008. On a daily basis we produced an average of 53,278 mcfe in the first nine months of 2008 compared to an average of 30,999 mcfe in the first nine months of 2007.

 

Oil and gas prices are reported net of the realized effect of our hedging agreements. Prices realized in the first nine months of 2008 were $88.60 per barrel of oil, $9.44 per mcf of natural gas and $58.49 per barrel of natural gas liquids compared to $64.61 per barrel of oil, $7.57 per mcf of natural gas and $44.71 per barrel of natural gas liquids in the first nine months of 2007. Prices before the realized effects of the hedging agreements were $112.98 per barrel of oil, $9.83 per mcf of natural gas and $58.49 per barrel of natural gas liquids in the first nine months of 2008 compared to $67.38 per barrel of oil, $6.84 per mcf of natural gas and $44.71 per barrel of natural gas liquids in the first nine months of 2007.

 

We realized losses of $9.4 million on our oil hedges and $3.8 million on our gas hedges in the first nine months of 2008, compared to losses of $0.8 million for oil and a gain of $4.5 million for gas in the first nine months of 2007.

 

Operating Overhead and Other Income. Revenues from working interest partners increased to $0.9 million in the first nine months of 2008 compared to $0.2 million in the first nine months of 2007

 

 

due to the increase in administrative overhead fees charged to our partners on the operated acquired properties and the one-time catch up on overhead billings due to the increase in COPAS rates.

 

Costs and Expenses

 

Lease Operating Expenses. Lease operating expenses for the first nine months of 2008 were $29.7 million, compared to $13.6 million in the first nine months of 2007. The increase in lease operating expenses was primarily due to the addition of the STGC properties and the South Texas properties from the Smith acquisition, higher production taxes on higher prices and volumes, and increased expense workovers. On a per unit basis, lease operating expenses increased to $2.04 per mcfe for the first nine months of 2008 from $1.61 per mcfe for the first nine months of 2007, also as a result of our acquisitions and higher vendor costs and production taxes due to higher commodity prices.

 

Exploration Expense. Exploration expense was $1.3 million in the first nine months of 2008 compared to $1.5 million in the first nine months of 2007. Geological and geophysical costs were $1.2 million and lease rentals were $62,000 for the first nine months of 2008. Geological and geophysical costs were $0.8 million, dry hole and abandoned property costs were $0.5 million and lease rentals were $0.1 million for the first nine months of 2007. We intend to continue to invest capital in seismic data and lease rental costs as we develop and expand our internal exploratory prospect generation capability.

 

Depreciation, Depletion and Amortization (DD&A). DD&A expense for the first nine months of 2008 was $35.6 million compared to $20.7 million in the first nine months of 2007, as a result of higher production volumes during the quarter. On a per unit basis, DD&A expense remained flat at $2.44 per mcfe in the first nine months of 2008 compared to the first nine months of 2007.

Impairment of Oil and Gas Properties. In September 2008, we recorded non-cash impairment expense of $25.8 million related to our Madisonville Field in Central Texas. 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 quarter.

 

Asset Retirement Obligations (ARO). ARO expense for the first nine months of 2008 was $1.0 million compared to $0.3 million for the first nine months of 2007. Accretion was $0.4 million and $0.3 million for the first nine months of 2008 and 2007, respectively. Settled ARO was $0.6 million and $12,000 for the first nine months of 2008 and 2007, respectively.

 

General and Administrative (G&A) Expenses. Our G&A expenses were $17.8 million for the first nine months of 2008 compared to $8.8 million in the first nine months of 2007. Included in G&A expense is a non-cash stock expense of $4.1 million ($0.28 per mcfe) and $3.3 million ($0.39 per mcfe) for the first nine months of 2008 and 2007, respectively. G&A expenses increased primarily due to higher personnel costs, including salaries, bonuses and employee benefits, higher professional fees and higher office rent expense related to expanding our infrastructure. On a per unit basis, G&A expense increased to $1.22 per mcfe for the first nine months of 2008 from $1.04 per mcfe in the first nine months of 2007, due to higher personnel costs, information technology costs and professional fees in expanding our infrastructure.

 

Gain on Sale of Assets. Gain on the sale of assets for the first nine months of 2008 was $15.3 million. The gain on the sale of assets was due to the disposition of our interest in the Barnett Shale

 

 

Play in the first quarter 2008. The gain on the sale of assets in the first nine months of 2007 was $0.7 million.

 

Interest Expense. Interest expense was $15.9 million for the first nine months of 2008, up from $9.4 million in the first nine months of 2007. Total interest expense increased primarily as a result of higher outstanding loan balances on our credit facilities related to our acquisition activity. Total interest expense capitalized for the first nine months of 2008 and 2007 was $0.8 million and $0.9 million, respectively.

 

Other Financing Costs. Other financing costs were $1.2 million for the first nine months of 2008 compared with $1.0 million for the first nine months of 2007. These expenses are comprised primarily of the amortization of capitalized costs associated with our current and former 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 year-to-date period in the mark-to-market exposure under our commodity price hedging instruments and our interest rate swap. This non-cash unrealized gain for the first nine months of 2008 was $1.7 million compared with a non-cash unrealized charge of $0.3 million for the first nine months of 2007. This amount will vary period to period, and will be a function of the hedges in place, the strike prices of those hedges, and the forward curve pricing of the commodities and interest rates being hedged.

 

Income Taxes. Our net income before taxes was $40.4 million for the first nine months of 2008 compared to $14.3 million in the first nine months of 2007. After adjusting for permanent tax differences, we recorded income tax expense of $15.1 million for the first nine months of 2008, of which $9.7 million was current tax expense and $5.4 million was deferred. The income tax expense of $5.5 million for the nine months ended September 30, 2007 was all deferred.

 

Dividends on Preferred Stock. Dividends on preferred stock were $3.2 million for the first nine months of 2008 compared with $3.4 million in the first nine months of 2007. Dividends in 2008 included $3.1 million on the Series G Preferred Stock and $78,000 on the Series H Preferred Stock. Dividends in 2007 included $3.3 million on the Series G Preferred Stock, $69,000 on the Series H Preferred Stock and $0.1 million on the Series E Preferred Stock. The Series E Preferred Stock was converted to Common Stock in May 2007.

 

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 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, or we will be required to curtail our expenditures.

 

Liquidity and cash flow

 

In recent months there has been extreme volatility and disruption in the capital and credit markets. The volatility and disruptions have created conditions that may adversely affect the financial condition of the lenders in our senior revolving credit facility, the counterparties to our derivative instruments, our insurers and our oil and natural gas purchasers. While these market conditions persist, our ability to access the capital and credit markets may be adversely affected. In addition, while a substantial portion

 

 

of our production is hedged, we are still subject to commodity price risk and our liquidity may be adversely affected if commodity prices continue to decline.

 

Our working capital deficit was $25.2 million as of September 30, 2008, compared to a working capital deficit of $12.4 million as of December 31, 2007. Current assets increased $4.0 million, primarily due to an increase in cash and cash equivalents of $5.5 million, offset by a decrease in trade accounts receivable, net of $2.0 million. Current liabilities increased $16.8 million, primarily due to an increase in accrued liabilities of $13.0 million and income tax payable of $9.7 million, offset by a decrease in trade accounts payable of $6.7 million.

 

Net cash provided by operating activities was $96.9 million for the nine months ended September 30, 2008, compared to $46.0 million for the nine months ended September 30, 2007. During the nine months ended September 30, 2008, the net cash provided by operating activities, before changes in working capital of $7.6 million, was $89.3 million. During the nine months ended September 30, 2007, the net cash provided by operating activities, before changes in working capital of $6.5 million, was $39.5 million.

 

Net cash used in investing activities was $105.7 million for the nine months ended September 30, 2008 compared to $283.5 million for the nine months ended 2007. Net cash used in investing activities during the nine months ended September 30, 2008 was primarily used for the acquisition of the South Texas Properties ($56.8 million) and capital expenditures ($82.6 million) primarily for the development of our Texas onshore properties, offset primarily by proceeds from the sale of our interest in the Barnett Shale Play ($34.4 million). Net cash used in investing activities during the nine months ended September 30, 2007 was primarily for the acquisition of the STGC Properties of $257.6 million.

 

Net cash provided by financing activities was $14.3 million for the nine months ended September 30, 2008 compared to $253.0 million for the nine months ended September 30, 2007. Net cash provided by financing activities for the nine months ended September 30, 2008 was primarily the result of borrowings on debt to fund the $56.8 million acquisition of the Smith Properties and normal drilling expenditures, offset by repayments of debt from the sale proceeds of our interest in the Barnett Shale Play and internally generated cash flow from operations. Net cash used in financing activities during the nine months ended September 30, 2007 was primarily the result of net borrowings on debt to fund the $257.6 million acquisition of the STGC Properties.

 

See the Consolidated Statements of Cash Flows for further details.

 

Capital resources

 

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association, as agent (the “Senior Credit Agreement”), to provide for acquisitions of oil and gas properties and for general corporate purposes. The Senior Credit Agreement provides for aggregate borrowings of up to $400.0 million, with a current borrowing base reaffirmed at $200.0 million on November 1, 2008, subject to semi-annual redeterminations, and maturing on May 8, 2011. Although our borrowing base is redetermined semi-annually and is subject to one unscheduled redetermination between scheduled redeterminations, which may lead to a decrease in our borrowing base, we do not currently anticipate a change in our borrowing base.

 

We also constructively fixed the base LIBOR rate on $200.0 million of our variable rate debt through July 8, 2009 by entering into interest rate swaps at a swap price of 5.02%. As of September 30, 2008, we had an outstanding loan balance of $124.0 million under our Senior Credit Agreement, resulting in an available borrowing capacity on such date of approximately $76.0 million.

 

 

 

We also maintain a second lien credit agreement (the “Second Lien Credit Agreement”) with Credit Suisse, as agent, which provides for term loans to be made to us in a single draw in an aggregate principal amount of $150.0 million. The Second Lien Credit Agreement has a term of five years and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on May 8, 2012. As of September 30, 2008, we had an outstanding loan balance of $150.0 million under our Second Lien Credit Agreement, with an interest rate of 8.498%.

 

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 subordinate and 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 5 of our Annual Report on Form 10-K for a more detailed description of our covenants under the Credit Agreements. At September 30, 2008, we were in compliance with the aforementioned covenants.

 

Future capital requirements

 

We anticipate that acquisitions of oil and natural gas producing properties will continue to play an important role in our business strategy. Another important component of our growth strategy is the addition to proved reserves through exploitation drilling for probable and possible reserves on acquired properties and lower risk exploration drilling in our core areas of focus. While there are currently no unannounced agreements, or ongoing negotiations for the acquisition of any material businesses or assets other than those discussed herein, such transactions can be effected quickly and may occur at any time. We currently estimate that we will make capital expenditures, exclusive of acquisitions and divestitures, and including acreage in the Haynesville Shale Play, of approximately $95 to $105 million during 2008.

 

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, planned capital development and debt service requirements for at least the next 12 months. However, our ability to maintain our Senior Credit Agreement and our internally generated cash flow can be impacted by economic conditions outside of our control such as the current disruption in the capital and credit markets as well as continued commodity price volatility. Capital expenditures for lower-risk exploitation and exploration activity will be a function of availability of appropriate capital.

 

The continuation of our acquisition strategy will require substantial capital. We currently intend to finance future acquisitions through issuances of equity or debt securities and through borrowings under our credit facilities. Using debt to complete acquisitions could substantially limit our operational and financial flexibility and using stock could dilute the ownership interests of our existing shareholders. The extent to which we will be able or are willing to use our Common Stock to make acquisitions will depend on its market value from time to time and the willingness of potential sellers to accept it as full or partial payment. If we are unable to obtain additional capital on acceptable terms, we may be unable to grow through acquisitions.

 

 

Recent Accounting Pronouncements

SFAS 162 - In May 2008, the Financial Accounting Standards Board (“FASB”) issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles ("GAAP") for nongovernmental entities. Prior to the issuance of SFAS 162, GAAP hierarchy was defined in the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. SFAS 162 is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. We believe that the adoption of this statement will not have a material impact on our financial statements.

SFAS 161 - In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133 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 under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the provisions of SFAS 161 and assessing the impact it may have on our financial reporting disclosures.

SFAS 141(R) - In December 2007, the FASB issued a revision to SFAS 141 “Business Combinations” (“SFAS 141(R)”). 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, the statement establishes principles and requirements for how an acquirer recognizes assets acquired, liabilities assumed and any non-controlling interests acquired. SFAS 141(R) is effective for business combination transactions for which the acquisition date is on or after the beginning of the first reporting period beginning on or after December 15, 2008. Early adoption is prohibited. We are currently evaluating the provisions of SFAS 141(R) and assessing the impact it may have on our financial position and results of operations.

SFAS 157-2 - In September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (“SFAS 157”). We adopted SFAS 157 effective January 1, 2008 only for our financial assets and financial liabilities. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This standard provides guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The adoption of SFAS 157, as it applied to our financial assets and financial liabilities, did not have a material impact on our consolidated financial statements. In February 2008, FASB issued Staff Position (“FSP”) No. SFAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-2 defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, 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). An entity that has issued interim or annual financial statements reflecting the application of the measurement and disclosure provisions of SFAS 157 prior to February 12, 2008, must continue to apply all provisions of SFAS 157. We are currently evaluating the provisions of our adoption of FSP 157-2 and assessing the impact it may have on our financial position, results of operations and reporting disclosures.

 

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2007 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 derivative financial instruments are for purposes other than trading. We only enter into derivative financial instruments in conjunction with our oil and gas price and interest rate hedging activities.

 

Hypothetical changes in commodity prices and interest rates chosen for the following stimulated 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 commodity prices and interest rates. Accordingly, these hypothetical changes may not be an indicator of probable future fluctuations.

 

Interest Rate Risk

 

We are exposed to interest rate risk on debt with variable interest rates. To manage this risk, we have entered into interest rate swap agreements with a total notional amount of $200.0 million related to our Senior Credit Agreement. As of September 30, 2008, the interest rate swap had an estimated net fair value liability of $3.1 million. Under these agreements, we receive interest at a floating rate equal to one-month LIBOR plus the applicable spread under our Senior Credit Agreement and pay interest at a fixed rate of 5.02% plus the applicable spread under our Senior Credit Agreement. 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 a material impact on our interest expense for the nine months ended September 30, 2008.

 

CommodityPrice Risk

 

We hedge a portion of price risk associated with our oil and natural gas sales through contractual arrangements which are classified as derivative instruments. As of September 30, 2008, these derivative instruments had an estimated net fair value liability of $10.5 million. A change in oil and gas prices would have an effect on oil and gas futures prices, which are used to estimate the fair value of our derivative instruments. Considering the highly volatile nature of energy commodity prices in the near and long term consideration of attributes impacting them, it is not practicable to estimate the resulting change.

 

Credit Risk

 

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries, as described under “Item 1. Business – Marketing Arrangements” in our Annual Report on Form 10-K for the year ended December 31, 2007. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future.

 

 

ITEM 4T.   CONTROLS AND PROCEDURES

 

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

 

 

In addition to 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, 2007 which could materially affect our business, financial condition and future results, as well as the following risk factors.

 

Recent changes in the financial and credit markets may impact economic growth and oil and gas prices may continue to be adversely affected by general economic conditions.

 

Based on a number of economic indicators, it appears that growth in global economic activity has slowed substantially. At the present time, the rate at which the global economy will slow has become increasingly uncertain. A continued slowing of global economic growth, and, in particular, in the United States, will likely continue to reduce demand for oil and natural gas. A reduction in the demand for, and the resulting lower prices of, oil and natural gas could adversely affect our results of operations.

 

The impairment of financial institutions could adversely affect us.

 

We have exposure to different counterparties, and we have entered into transactions 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 counterparty. We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. 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.

 

 

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On July 11, 2008 we issued 14,286 shares of Common Stock in conjunction with the conversion of 100 shares of Series H Preferred Stock held by two holders in transactions exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933, as amended.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

          On August 28, 2008, one of the Company’s stockholders holding more than a majority of the voting power of the Company’s outstanding shares of Common Stock, Series G Preferred Stock and Series H Preferred Stock, voting on an as-if converted to Common Stock basis, executed a written consent with respect to its shares of Series G Preferred Stock and Series H Preferred Stock (as of August 18, 2008, the record date, the stockholder was entitled to vote an aggregate of 7,822,404 “as converted” shares of Common Stock, including accumulated dividends on the Series G Preferred Stock of 1,278,538 equivalent shares of Common Stock) approving an amendment to the Company’s 2005 Stock Incentive Plan (the “Plan”). This consent was executed following approval of the actions by the Company’s Board of Directors on August 15, 2008. The purpose of the amendment was to:

 

 

 

 

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)