Edgar Filing: CRIMSON EXPLORATION INC.

form10q.htm

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 June 30, 2010

( ) 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 001-12108

CRIMSON EXPLORATION INC.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation)		20-3037840 (IRS Employer Identification No.)

717 Texas Avenue, Suite 2900 Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

(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.

Large accelerated filer o	Accelerated filer o	Non-accelerated filer o	Smaller reporting company x
		(Do not check if smaller reporting company)

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 July 30, 2010, there were 38,822,859 shares outstanding of the registrant’s Common Stock, par value $0.001.

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED JUNE 30, 2010


	Page

Part I: Financial Information

Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	3
Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2010 and 2009	4
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2010	5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	6
Notes to the Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 4. Controls and Procedures	24

Part II: Other Information

Item 1A. Risk Factors	25

Item 6. Exhibits	26

Signatures	28

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	June 30,			December 31,
	2010			2009
	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Accounts receivable, net of allowance of $411,324 and $411,324, respectively		13,389,207			14,773,246
Prepaid expenses		7,965			—
Derivative instruments		10,591,197			9,937,697
Total current assets		23,988,369			24,710,943

PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method of accounting)		581,157,914			559,565,531
Other property and equipment		3,375,348			3,679,515
Accumulated depreciation, depletion and amortization		(190,752,108	)		(170,117,319	)
Total property and equipment, net		393,781,154			393,127,727

NONCURRENT ASSETS
Deposits		104,697			104,697
Debt issuance cost		3,475,818			4,347,298
Derivative instruments		2,712,934			2,513,369
Total noncurrent assets		6,293,449			6,965,364

TOTAL ASSETS	$	424,062,972		$	424,804,034

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	4,898		$	19,014
Accounts payable		26,802,549			20,263,343
Income taxes payable		253,726			250,931
Accrued liabilities		10,348,338			8,852,310
Asset retirement obligations		717,748			330,287
Derivative instruments		1,300,627			872,849
Deferred tax liability, net		2,929,811			2,897,300
Total current liabilities		42,357,697			33,486,034

NONCURRENT LIABILITIES
Long-term debt, net of current portion		193,032,149			192,749,751
Asset retirement obligations		8,944,780			9,372,366
Derivative instruments		185,166			1,284,105
Deferred tax liability, net		1,449,274			4,471,023
Other noncurrent liabilities		699,189			709,867
Total noncurrent liabilities		204,310,558			208,587,112

Total liabilities		246,668,255			242,073,146

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Common stock (par value $0.001; 200,000,000 shares authorized; 38,832,478 and 38,516,658 shares issued and outstanding, respectively)		38,919			38,578
Additional paid-in capital		210,652,026			209,738,513
Retained deficit		(32,823,926	)		(26,661,891	)
Treasury stock (at cost, 86,973 and 61,546 shares, respectively)		(472,302	)		(384,312	)
Total stockholders’ equity		177,394,717			182,730,888

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	424,062,972		$	424,804,034

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

OPERATING REVENUES
Natural gas sales	$	13,542,484		$	18,060,669		$	28,016,215		$	38,708,891
Crude oil sales		4,975,157			7,375,787			9,691,852			14,808,962
Natural gas liquids sales		2,753,942			2,990,577			6,048,103			5,472,564
Operating overhead and other income		181,360			192,904			306,632			360,387
Total operating revenues		21,452,943			28,619,937			44,062,802			59,350,804

OPERATING EXPENSES
Lease operating expenses		3,953,646			4,186,290			7,836,497			9,638,043
Production and ad valorem taxes		1,477,963			2,022,377			3,180,827			4,497,119
Exploration expenses		187,279			1,455,664			683,116			2,185,642
Depreciation, depletion and amortization		10,514,130			14,347,397			20,937,682			28,199,283
General and administrative		4,486,375			4,326,799			9,395,695			9,545,088
Loss on sale of assets		430,819			18,925			430,819			18,925
Total operating expenses		21,050,212			26,357,452			42,464,636			54,084,100

INCOME FROM OPERATIONS		402,731			2,262,485			1,598,166			5,266,704

OTHER INCOME (EXPENSE)
Interest expense		(5,245,563	)		(5,336,589	)		(10,602,839	)		(9,715,658	)
Other financing cost		(844,927	)		(426,535	)		(1,573,030	)		(727,646	)
Unrealized (loss) gain on derivative instruments		(3,917,809	)		(16,874,919	)		1,524,225			(7,307,962	)
Total other income (expense)		(10,008,299	)		(22,638,043	)		(10,651,644	)		(17,751,266	)

LOSS BEFORE INCOME TAXES		(9,605,568	)		(20,375,558	)		(9,053,478	)		(12,484,562	)

Income tax benefit		3,234,718			7,110,484			2,891,443			4,254,101

NET LOSS		(6,370,850	)		(13,265,074	)		(6,162,035	)		(8,230,461	)

Dividends on preferred stock (Paid 2010 — $0; 2009 — $11,970)		—			(1,115,258	)		—			(2,196,987	)

NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(6,370,850	)	$	(14,380,332	)	$	(6,162,035	)	$	(10,427,448	)

NET LOSS PER SHARE
Basic	$	(0.16	)	$	(2.24	)	$	(0.16	)	$	(1.67	)
Diluted	$	(0.16	)	$	(2.24	)	$	(0.16	)	$	(1.67	)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		38,635,725			6,421,225			38,571,300			6,228,730
Diluted		38,635,725			6,421,225			38,571,300			6,228,730

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)

	NUMBER OF SHARES
	COMMON STOCK			COMMON STOCK		ADDITIONAL PAID-IN CAPITAL		RETAINED DEFICIT			TREASURY STOCK			TOTAL STOCKHOLDERS’ EQUITY
BALANCE, DECEMBER 31, 2009		38,516,658		$	38,578	$	209,738,513	$	(26,661,891	)	$	(384,312	)	$	182,730,888
Current period net loss		—			—		—		(6,162,035	)		—			(6,162,035	)
Share-based compensation		334,348			334		896,962		—			—			897,296
Stock options exercised		6,899			7		16,551		—			—			16,558
Treasury stock		(25,427	)		—		—		—			(87,990	)		(87,990	)
BALANCE, JUNE 30, 2010		38,832,478		$	38,919	$	210,652,026	$	(32,823,926	)	$	(472,302	)	$	177,394,717

The Notes to the Consolidated Financial Statements are an integral part of this statement.

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,162,035	)	$	(8,230,461	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		20,937,682			28,199,283
Asset retirement obligations		(139,102	)		(309,543	)
Stock compensation expense		897,296			1,521,989
Amortization of debt issuance cost		1,337,891			568,994
Discount on notes payable		37,097			—
Deferred charges		—			842,054
Deferred income taxes		(2,923,125	)		(4,909,845	)
Dry holes, abandoned property, impaired assets		236,457			44,013
Loss on sale of assets		430,819			18,925
Unrealized (gain) loss on derivative instruments		(1,524,225	)		7,307,962
Changes in operating assets and liabilities:
Decrease in accounts receivable, net		1,822,789			6,759,886
Increase in prepaid expenses		(7,965	)		(28,994	)
Increase (decrease) in accounts payable and accrued liabilities		7,259,238			(45,103,719	)
Net cash provided by (used in) operating activities		22,202,817			(13,319,456	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(21,755,129	)		(11,777,088	)
Acquisition of oil and gas properties		—			482,166
Sale of assets		(141,029	)		—
Net cash used in investing activities		(21,896,158	)		(11,294,922	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt		(39,602,202	)		(57,324,340	)
Proceeds from debt		39,833,386			83,128,718
Debt issuance expenditures		(466,411	)		(1,190,000	)
Proceeds from stock option exercises		16,558			—
Purchase of treasury stock		(87,990	)		—
Net cash (used in) provided by financing activities		(306,659	)		24,614,378

INCREASE IN CASH AND CASH EQUIVALENTS		—			—

CASH AND CASH EQUIVALENTS,
Beginning of period		—			—

CASH AND CASH EQUIVALENTS,
End of period	$	—		$	—

Cash paid for interest	$	13,655,847		$	9,161,379
Cash paid for income taxes	$	95,000		$	690,500

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND NATURE OF OPERATIONS

Crimson Exploration Inc., together with its subsidiaries, (“Crimson”, “we”, “our”, “us”) is an independent energy company engaged in the acquisition, exploitation, exploration and development of natural gas and crude oil properties. We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions, which are generally characterized by high rates of return in known, prolific producing trends. We have recently expanded our strategic focus to include longer reserve life resource plays in East Texas and South Texas that we believe provide significant long-term reserve and production growth potential from multiple formations.

2. BASIS OF PRESENTATION

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 Rule 8-03 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 annual financial statements. The accompanying consolidated financial statements at June 30, 2010 (unaudited) and December 31, 2009 and for the three and six months ended June 30, 2010 (unaudited) and 2009 (unaudited) 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 six months ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. 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, 2009.

The accompanying consolidated financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Crimson Exploration Operating, Inc., formed January 5, 2006 and LTW Pipeline Co., formed April 19, 1999 (inactive). All material intercompany transactions and balances are eliminated upon consolidation.

Use of Estimates in the Preparation of Financial Statements

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates included in the consolidated financial statements are: (1) natural gas, crude oil and natural gas liquids revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes and accounts receivables; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations and (7) valuation of derivative instruments. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates.

3.	FAIR VALUE MEASUREMENTS

Accounting guidance 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. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities.

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 and Cash Equivalents, Accounts Receivable and Accounts Payable. The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

Derivative Instruments. Our derivative instruments consist of variable to fixed price commodity swaps, costless collars and interest rate swaps. The fair value measurement of our unrealized natural gas, crude oil and interest rate swaps and collars were obtained from financial institutions and such fair value was evaluated and determined to be reasonable, using our crude oil, natural gas and interest rate swap and collar agreements and future commodity and interest rate curves. See Note 4 – “Derivative Instruments” for further information.

Impairments. We review our oil and gas properties for impairment, at least annually, and quarterly if events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the expected future cash flows from the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs are typically not observable, we classify impairments of long-lived assets as a level 3 fair value measure. We had no asset impairments in the second quarter 2010.

Debt. The fair value of floating-rate debt is estimated to be equivalent to the carrying amounts because the interest rates paid on such debt are set for periods of three months or less. See Note 6 - “Debt” for further information.

Fair value information for assets and (liabilities) that are measured at fair value was as follows at June 30, 2010:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Crude oil swaps and collars	$	38,293		$	—	$	38,293		$	—
Natural gas swaps and collars		15,120,406			—		15,120,406			—
Interest rate swaps		(3,340,361	)		—		(3,340,361	)		—
Total	$	11,818,338		$	—	$	11,818,338		$	—

Fair value information for assets and (liabilities) that are measured at fair value was as follows at December 31, 2009:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Crude oil swaps and collars	$	(1,332,084	)	$	—	$	(1,332,084	)	$	—
Natural gas swaps and collars		16,236,665			—		16,236,665			—
Interest rate swaps		(4,610,469	)		—		(4,610,469	)		—
Total	$	10,294,112		$	—	$	10,294,112		$	—

FASB guidance established a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure 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. There were no transfers between fair value hierarchy levels in the first six months of 2010.

4. DERIVATIVE INSTRUMENTS

At the end of each reporting period we record on our balance sheet the mark-to-market valuation of our derivative instruments. We recorded net assets for derivative instruments of $11.8 million and $10.3 million at June 30, 2010 and December 31, 2009, respectively. The change in estimated fair value of the derivatives during the period is reported in other income (expense) as unrealized gain or loss on derivative instruments. Realized gain (loss) on derivative instruments is included in natural gas and crude oil sales for our commodity price hedges and in interest expense for our interest rate swaps.

The following table details the location and effect of the Company’s derivative contracts on the Consolidated Statements of Operations for realized and unrealized gains:

Contract Type	Location of Gain or (Loss) Recognized in Income		Amount of Gain or (Loss) Recognized in Income
			Three months ended June 30,						Six months ended June 30,
			2010			2009			2010			2009

Natural gas contracts	Operating revenues	$	5,470,364		$	8,457,497		$	9,051,799		$	14,494,721
Crude oil contracts	Operating revenues		454,725			2,297,838			856,278			5,945,913
Interest rate contracts	Interest expense		1,143,135			(1,080,565	)		2,292,777			(2,083,723	)
	Realized gain	$	7,068,224		$	9,674,770		$	12,200,854		$	18,356,911

Natural gas contracts	Other income (expense)	$	(6,786,412	)	$	(8,520,803	)	$	(1,116,260	)	$	4,063,292
Crude oil contracts	Other income (expense)		1,846,587			(9,577,707	)		1,370,377			(12,166,716	)
Interest rate contracts	Other income (expense)		1,022,016			1,223,591			1,270,108			795,462
	Unrealized gain (loss)	$	(3,917,809	)	$	(16,874,919	)	$	1,524,225		$	(7,307,962	)

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 potential

commodity price declines, and with respect to portions of our debt, to reduce our sensitivity to potential increases in 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 may limit the benefit of increases in commodity prices or limit the benefit of decreases in interest rates. Moreover, our derivative arrangements apply only to a portion of our production and our debt, and therefore, provide only partial protection against declines in commodity prices and increases in interest rates, respectively. 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. 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, and 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 agreement is unable to fund their commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit agreement. We believe our counterparty risk is low in part because of the offset option we have with each of our counterparties in our revolving credit agreement and various hedge contracts. See Note 3 — “Fair Value Measurements” for further information.

The following derivative contracts were in place at June 30, 2010:

Crude Oil		Volume/Month	Price/Unit		Fair Value
Jul 2010-Dec 2010 (2)	Swap	4,250 Bbls	$72.32	$	(117,384	)
Jul 2010-Dec 2010 (2)	Collar	9,000 Bbls	$65.28-$70.60		(402,654	)
Jul 2010-Dec 2010 (2)	Collar	7,667 Bbls (1)	$110.00-$181.25		1,787,647
Jan 2011-Dec 2011	Swap	3,300 Bbls	$70.74		(347,422	)
Jan 2011-Dec 2011	Collar	7,000 Bbls	$64.50-$69.50		(971,084	)
Jan 2011-Mar 2011	Swap	2,000 Bbls	$86.15		45,402
Apr 2011-Jun 2011	Swap	1,500 Bbls	$86.78		32,866
Jul 2011-Sep 2011	Swap	500 Bbls	$87.32		10,922

Natural Gas
Jul 2010-Dec 2010 (2)	Swap	29,000 Mmbtu	$7.88		531,727
Jul 2010-Dec 2010 (2)	Collar	351,000 Mmbtu	$7.57-$9.05		5,776,086
Jul 2010-Dec 2010 (2)	Collar	85,867 Mmbtu (1)	$9.00-$15.25		2,142,154
Jan 2011-Dec 2011	Collar	266,000 Mmbtu	$7.32-$8.70		6,670,439
		Commodity price derivative instruments			15,158,699

Interest rate		Notional Amount	Fixed LIBOR Rate
Jul 2010-Dec 2010 (2)	Swap	$50,000,000	1.50%		(260,049	)
Jul 2010- May 2011 (2)	Swap	$150,000,000	2.90%		(3,080,312	)
Interest rate derivative instruments					(3,340,361	)
Total net fair value asset of derivative instruments				$	11,818,338

(1) Average volume per month for the remaining contract term

(2) Remaining contract period

5. ASSET RETIREMENT OBLIGATIONS

We estimate the fair values of asset retirement obligations ("AROs") based on historical experience of plug and abandonment costs by field, and 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.

Asset Retirement Obligations Rollforward

Beginning January 1, 2010 liability	$	9,702,653
Additions		—
Accretion expense		302,894
Revisions		—
Properties sold		(203,917	)
Plugging and abandonment activity		(139,102	)
Ending June 30, 2010 liability	$	9,662,528

6. DEBT

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent (the “Senior Credit Agreement”), and the lender parties thereto that currently provides for a $100.0 million borrowing base, based on our current proved crude oil and natural gas reserves. The borrowing base is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates. The next borrowing base redetermination under our Senior Credit Agreement is scheduled for November 1, 2010. The Senior Credit Agreement’s outstanding principal amounts, together with all accrued and unpaid interest, will be due and payable in full on January 8, 2012. As of June 30, 2010, we had an outstanding loan balance of $41.2 million under our Senior Credit Agreement.

On June 9, 2010, we entered into a fifth amendment to our Senior Credit Agreement. This amendment provided, among other things, for an extension of the maturity date to January 8, 2012 and the redetermination of the borrowing base to $100.0 million. Until we enter into additional hedging agreements that would add an incremental $3.0 million in discounted present value to our reserve base, a maximum of $95.0 million of the $100.0 million borrowing base may be utilized.

We also maintain a second lien credit agreement dated May 8, 2007 (the “Second Lien Credit Agreement”) with our lenders, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder. The Second Lien Credit Agreement provides for a maximum loan amount of $150.0 million which we borrowed in a single draw at closing and is due and payable in full at maturity on May 8, 2012. As of June 30, 2010, we had an outstanding loan balance of $150.0 million under our Second Lien Credit Agreement.

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 individual borrowings mature and renew.

The Credit Agreements include usual and customary affirmative covenants for credit facilities of similar type and size, 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. The Credit Agreements also contain certain financial and proved reserve covenants. See Note 10 of our Annual Report on Form 10-K for the year ended December 31, 2009 for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements. At June 30, 2010, we were in compliance with all covenants under our Credit Agreements.

As consideration for Oaktree Holdings’ agreement to deposit $10.0 million in escrow on November 6, 2009, to collateralize a $10.0 million unsecured promissory note between Crimson and Wells Fargo Bank, which was subsequently repaid on December 22, 2009, we issued an unsecured subordinated promissory note on November 6, 2009 for the principal amount of $2.0 million to Oaktree Holdings, a related party. The indebtedness under the $2.0 million promissory note bears interest at a per annum rate equal to 8.0% 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 our Credit Agreements) and the termination of all commitments to extend credit under our Credit Agreements. The promissory note is subordinated in right of payment to the prior payment in full in cash of all obligations under our Credit Agreements. At June 30, 2010, the carrying fair value of this debt was calculated as $1.8 million, net of discount, using the estimated market value interest rate at the time of issuance.

7.	STOCKHOLDERS’ EQUITY

In the six months ended June 30, 2010, we issued approximately 0.3 million shares of unvested restricted Common Stock to certain employees under the 2005 Stock Incentive Plan. We issued 31,646 shares of unvested restricted Common Stock to two members of our board of directors as compensation pursuant to the Director Compensation Plan.

In the six months ended June 30, 2010, approximately 0.2 million shares of previously issued restricted Common Stock vested, of which 25,427 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, as provided for in the restricted stock agreement, with the remaining shares being released to the employees and directors. We also had 27,657 unvested shares of restricted Common Stock forfeited due to employee terminations. We also issued 6,899 shares of Common Stock pursuant to employee stock option exercises in the six months ended June 30, 2010.

8. INCOME TAXES

Income tax benefit for the six months ended June 30, 2010 was $2.9 million, compared to $4.3 million for the six months ended June 30, 2009. The year-to-date income tax expense is based on our estimate of the effective tax rate expected to be applicable for the full year.

9. RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Not Yet Adopted

There were no recently issued standards that were applicable to us that have not yet been adopted.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

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 in our Annual Report on Form 10-K for the year ended December 31, 2009. 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:

·	estimates of proved reserve quantities and net present values of those reserves;

·	reserve potential;

·	business strategy;

·	estimates of future commodity prices;

·	amounts, timing and types of capital expenditures and operating expenses;

·	expansion and growth of our business and operations;

·	expansion and development trends of the oil and gas industry;

·	acquisitions of natural gas and crude oil properties;

·	production of natural gas and crude oil reserves;

·	exploration prospects;

·	wells to be drilled and drilling results;

·	operating results and working capital;

·	results of borrowing base redeterminations under our revolving credit facility; and

·	future methods and types of financing.

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, exploitation, exploration and development of natural gas and crude oil properties. We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions, which are generally characterized by high rates of return in known, prolific producing trends. We have recently expanded our strategic focus to include longer reserve life resource plays in East Texas and South Texas that we believe provide significant long-term reserve and production growth potential from multiple formations. Our gross revenues are derived from the following sources:

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

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

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 included in this Quarterly Report on Form 10-Q.

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

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Revenues

Natural Gas, Crude Oil and Natural Gas Liquids Sales

	Three months ended June 30,
	2010		2009		Change			Percent Change
Product revenues:	(in millions, except percentages)
Natural gas sales	$	13.5	$	18.0	$	(4.5	)		-25.0	%
Crude oil sales		5.0		7.4		(2.4	)		-32.4	%
Natural gas liquids sales		2.8		3.0		(0.2	)		-6.7	%
Product revenues	$	21.3	$	28.4	$	(7.1	)		-25.0	%

Revenues from the sale of natural gas, crude oil and natural gas liquids, net of the realized effects of our commodity price hedging instruments, were $21.3 million for the second quarter 2010 compared to $28.4 million for the second quarter 2009. The decrease in revenue was due to lower production, offset in part by a slight increase in realized commodity prices.

Production

	Three months ended June 30,
	2010		2009		Change			Percent Change
Sales volumes:
Natural gas (Mcf)		1,961,247		2,692,534		(731,287	)		-27.2	%
Crude oil (Bbl)		58,766		91,489		(32,723	)		-35.8	%
Natural gas liquids (Bbl)		70,637		109,269		(38,632	)		-35.4	%
Natural gas equivalents (Mcfe)		2,737,665		3,897,082		(1,159,417	)		-29.8	%

Quarterly production was approximately 2.7 Bcfe for the second quarter 2010 compared to approximately 3.9 Bcfe for the second quarter 2009. On a daily basis, we produced an average of 30,084 Mcfe for the 2010 quarter compared to an average of 42,825 Mcfe for the 2009 quarter. Lower production volumes are primarily attributed to three factors: i) the sale of our Southwest Louisiana properties in December 2009 (approximately 350,000 Mcfe for the second quarter 2009); ii) the loss of approximately 161,000 Mcfe resulting from the shut-in of our Liberty County fields for seven days in mid-June 2010 due to a pipeline rupture experienced by the purchaser and the scheduled plant maintenance for two weeks in April 2010 by the purchaser and iii) natural field decline as a result of limited capital expenditure activity in 2009 and early 2010 (approximately 649,000 Mcfe).

Average Sales Prices

	Three months ended June 30,
	2010		2009		Change		Percent Change
Average sales prices (before hedging):
Natural gas (Mcf)	$	4.12	$	3.57	$	0.55		15.4	%
Crude oil (Bbl)		76.92		55.50		21.42		38.6	%
Natural gas liquids (Bbl)		38.99		27.37		11.62		42.5	%
Natural gas equivalents (Mcfe)		5.61		4.53		1.08		23.8	%

	Three months ended June 30,
	2010		2009		Change		Percent Change
Average sales prices (after hedging):
Natural gas (Mcf)	$	6.91	$	6.71	$	0.20		2.9	%
Crude oil (Bbl)		84.66		80.62		4.04		5.0	%
Natural gas liquids (Bbl)		38.99		27.37		11.62		42.5	%
Natural gas equivalents (Mcfe)		7.77		7.29		0.48		6.5	%

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $0.5 million on our crude oil hedges and $5.5 million on our natural gas hedges in the second quarter 2010, compared to realized gains of $2.3 million for crude oil hedges and $8.5 million for natural gas hedges in the second quarter 2009, which were included in our natural gas and crude oil sales revenues on our Consolidated Statements of Operations.

Costs and Expenses

	Three months ended June 30,
	2010		2009		Change			Percent Change
Certain Operating Expenses:	(in millions, except percentages)
Lease operating expenses	$	4.0	$	4.2	$	(0.2	)		-4.8	%
Production and ad valorem taxes		1.5		2.0		(0.5	)		-25.0	%
Exploration expenses		0.2		1.5		(1.3	)		-86.7	%
General and administrative(1)		4.1		3.7		0.4			10.8	%
Operating expenses		9.8		11.4		(1.6	)		-14.0	%
Depreciation, depletion & amortization		10.5		14.3		(3.8	)		-26.6	%
Share-based compensation		0.4		0.6		(0.2	)		-33.3	%
Certain operating expenses	$	20.7	$	26.3	$	(5.6	)		-21.3	%

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

	Three months ended June 30,
	2010		2009		Change			Percent Change
Selected Costs ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	1.44	$	1.08	$	0.36			33.3	%
Production and ad valorem taxes		0.54		0.52		0.02			3.8	%
Exploration expenses		0.07		0.37		(0.30	)		-81.1	%
General and administrative(1)		1.50		0.97		0.53			54.6	%
Operating expenses		3.55		2.94		0.61			20.7	%
Depreciation, depletion & amortization		3.84		3.68		0.16			4.3	%
Share-based compensation		0.14		0.14		—			—
Selected costs	$	7.53	$	6.76	$	0.77			11.4	%

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

Lease Operating Expenses. Lease operating expenses for the second quarter 2010 were $4.0 million, compared to $4.2 million in the second quarter 2009, a decrease resulting from the implementation of cost reduction initiatives during 2009 and the reduction in costs due to the sale of the Southwest Louisiana properties in December 2009, offset in part by higher workover expenses. The increase in the cost per Mcfe during the second quarter 2010 was primarily due to the lower production.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the second quarter 2010 were $1.5 million, compared to $2.0 million for the second quarter 2009, due to lower production in the second quarter 2010 and the sale of the Southwest Louisiana properties in December 2009, offset in part by higher sales prices in the second quarter of 2010.

Exploration Expenses. Exploration expenses were $0.2 million in the second quarter 2010, compared to $1.5 million for the second quarter 2009. The decrease in exploration expenses was primarily due to lower geological and geophysical (“G&G”) acquisition costs and lower settled asset retirement costs in the second quarter 2010.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the second quarter 2010 was $10.5 million compared to $14.3 million for the second quarter 2009, a decrease primarily due to lower production and the sale of the Southwest Louisiana properties in December 2009.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $4.5 million for the second quarter 2010 compared to $4.3 million for the second quarter 2009. Included in G&A expense is a non-cash stock expense of $0.4 million ($0.14 per Mcfe) and $0.6 million ($0.14 per Mcfe) for the second quarters 2010 and 2009, respectively. G&A expenses for the second quarter 2010 were higher primarily due to approximately $0.6 million in legal fees incurred in successfully defending a lawsuit related to the 2005 recapitalization. The increase in per unit costs was primarily a result of the legal fees and lower production.

Loss on Sale of Assets. The loss on sale of assets during the second quarter 2010 was $0.4 million, primarily related to final purchase price adjustments on the sale of our Southwest Louisiana properties.

Interest Expense. Interest expense was $5.2 million for the second quarter 2010, compared to $5.3 million for the second quarter 2009. Total interest expense decreased primarily due to the decrease

in the outstanding debt on our revolving credit agreement, offset by the increase in the interest rate on our second lien agreement in May 2009.

Other Financing Costs. Other financing costs were $0.8 million for the second quarter 2010, compared to $0.4 million for the second quarter 2009. These expenses consist primarily of the amortization of deferred costs associated with our credit facilities.

Unrealized Gain on Derivative Instruments. The non-cash unrealized loss on derivative instruments for the second quarter 2010 was $3.9 million, compared to $16.9 million for the second quarter 2009. Unrealized gain or loss is the change in the fair value of our commodity price hedging contracts and our interest rate swaps during the period. Unrealized gain or loss 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 loss before taxes was $9.6 million for the second quarter 2010, compared to $20.4 million in the second quarter 2009. After adjusting for permanent tax differences, we recorded an income tax benefit of $3.2 million for the second quarter 2010, compared to $7.1 million for the second quarter 2009.

Dividends on Preferred Stock. Dividends on preferred stock were zero for the second quarter 2010, compared with $1.1 million in the second quarter 2009. All of the Series G and Series H Preferred Stock, including accrued dividends, were converted to Common Stock in December 2009 in conjunction with our Common Stock offering. Dividends in the second quarter 2009 included approximately $1.1 million on the Series G Preferred Stock and $4,445 on the Series H Preferred Stock.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Revenues

Natural Gas, Crude Oil and Natural Gas Liquids Sales

	Six months ended June 30,
	2010		2009		Change			Percent Change
Product revenues:	(in millions, except percentages)
Natural gas sales	$	28.0	$	38.7	$	(10.7	)		-27.6	%
Crude oil sales		9.7		14.8		(5.1	)		-34.5	%
Natural gas liquids sales		6.1		5.5		0.6			10.9	%
Product revenues	$	43.8	$	59.0	$	(15.2	)		-25.8	%

Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our hedging instruments, were $43.8 million for the first six months of 2010 compared to $59.0 million for the first six months of 2009, a decrease due primarily to lower production, offset in part by higher realized commodity prices.

Production

	Six months ended June 30,
	2010		2009		Change			Percent Change
Sales volumes:
Natural gas (Mcf)		4,041,415		5,768,648		(1,727,233	)		-29.9	%
Crude oil (Bbl)		115,070		187,794		(72,724	)		-38.7	%
Natural gas liquids (Bbl)		141,867		219,511		(77,644	)		-35.4	%
Natural gas equivalents (Mcfe)		5,583,037		8,212,478		(2,629,441	)		-32.0	%

Production was approximately 5.6 Bcfe for the first six months of 2010 compared to 8.2 Bcfe for the first six months of 2009. On a daily basis, we produced an average of 30,846 Mcfe in the first six months of 2010 compared to an average of 45,373 Mcfe in the first six months of 2009. Lower production volumes are primarily attributed to three factors: i) the sale of our Southwest Louisiana properties in December 2009 (approximately 647,000 Mcfe for the first six months of 2009); ii) the loss of approximately 161,000 Mcfe resulting from the shut-in of our Liberty County fields for seven days in mid-June 2010 due to a pipeline rupture experienced by the purchaser and the scheduled plant maintenance for two weeks in April 2010 by the purchaser and iii) natural field decline as a result of limited capital expenditure activity in 2009 and early 2010 (approximately 1,821,000 Mcfe).

Average Sales Prices

	Six months ended June 30,
	2010		2009		Change		Percent Change
Average sales prices (before hedging):
Natural gas (Mcf)	$	4.69	$	4.20	$	0.49		11.7	%
Crude oil (Bbl)		76.78		47.20		29.58		62.7	%
Natural gas liquids (Bbl)		42.63		24.93		17.70		71.0	%
Natural gas equivalents (Mcfe)		6.06		4.69		1.37		29.2	%

	Six months ended June 30,
	2010		2009		Change		Percent Change
Average sales prices (after hedging):
Natural gas (Mcf)	$	6.93	$	6.71	$	0.22		3.3	%
Crude oil (Bbl)		84.23		78.86		5.37		6.8	%
Natural gas liquids (Bbl)		42.63		24.93		17.70		71.0	%
Natural gas equivalents (Mcfe)		7.84		7.18		0.65		9.1	%

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $0.9 million on our crude oil hedges and $9.0 million on our natural gas hedges in the first six months of 2010, compared to realized gains of $5.9 million on our crude oil hedges and $14.5 million on our natural gas hedges in the first six months of 2009, which were included in our natural gas and crude oil sales revenues on our Consolidated Statements of Operations.

Costs and Expenses

	Six months ended June 30,
	2010		2009		Change			Percent Change
Certain Operating Expenses:	(in millions, except percentages)
Lease operating expenses	$	7.8	$	9.6	$	(1.8	)		-18.8	%
Production and ad valorem taxes		3.2		4.5		(1.3	)		-28.9	%
Exploration expenses		0.7		2.2		(1.5	)		-68.2	%
General and administrative(1)		8.5		8.0		0.5			6.3	%
Operating expenses		20.2		24.3		(4.1	)		-16.9	%
Depreciation, depletion & amortization		20.9		28.2		(7.3	)		-25.9	%
Share-based compensation		0.9		1.5		(0.6	)		-40.0	%
Certain operating expenses	$	42.0	$	54.0	$	(12.0	)		-22.2	%

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

	Six months ended June 30,
	2010		2009		Change			Percent Change
Selected Costs ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	1.40	$	1.17	$	0.23			19.7	%
Production and ad valorem taxes		0.57		0.55		0.02			3.6	%
Exploration expenses		0.12		0.27		(0.15	)		-55.6	%
General and administrative(1)		1.52		0.98		0.54			55.1	%
Operating expenses		3.61		2.97		0.64			21.5	%
Depreciation, depletion & amortization		3.75		3.43		0.32			9.3	%
Share-based compensation		0.16		0.19		(0.03	)		-15.8	%
Selected costs	$	7.52	$	6.59	$	0.93			14.1	%

(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 six months of 2010 were $7.8 million, compared to $9.6 million in the first six months of 2009, a decrease resulting from the implementation of cost reduction initiatives during 2009 and the reduction in costs due to the sale of the Southwest Louisiana properties in December 2009, offset in part by higher workover expenses. The increase in the cost per Mcfe during the first six months of 2010 was primarily due to the lower production.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the first six months of 2010 were $3.2 million, compared to $4.5 million for the first six months of 2009, due to lower production in the first six months of 2010 and the sale of the Southwest Louisiana properties in December 2009, offset in part by higher sales prices in the first six months of 2010.

Exploration Expenses. Exploration expenses were $0.7 million in the first six months of 2010 compared to $2.2 million for the first six months of 2009. The decrease in exploration expenses was primarily due to lower G&G costs and settled asset retirement costs incurred in the first six months of 2010 compared to the first six months of 2009.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the first six months of 2010 was $20.9 million compared to $28.2 million for the first six months of 2009, a decrease primarily due to lower production and the sale of the Southwest Louisiana properties in December 2009.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $9.4 million for the first six months of 2010 compared to $9.5 million for the first six months of 2009, which includes non-cash stock expense of $0.9 million ($0.16 per Mcfe) and $1.5 million ($0.19 per Mcfe) for the first six months of 2010 and 2009, respectively. G&A expenses decreased primarily due to the result of the cost reduction initiatives during 2009, partially offset by higher incentive compensation and higher legal fees for the first six months of 2010.

Loss on Sale of Assets. The loss on sale of assets during the first six months of 2010 was $0.4 million, due primarily to the final purchase price adjustments on the sale of our Southwest Louisiana properties.

Interest Expense. Interest expense was $10.6 million for the first six months of 2010, compared to $9.7 million for the first six months of 2009, an increase primarily due to the increase in the interest rate on our second lien agreement in May 2009, offset by the repayment of outstanding debt under our revolving credit agreement with proceeds from our equity offering in December 2009.

Other Financing Costs. Other financing costs were $1.6 million for the first six months of 2010 compared with $0.7 million for the first six months of 2009. These expenses are comprised primarily of the amortization of deferred costs associated with our credit facilities.

Unrealized Loss on Derivative Instruments. The non-cash unrealized gain for the first six months of 2010 was $1.5 million compared with a non-cash unrealized loss of $7.3 million for the first six months of 2009. Unrealized gain or loss on derivative instruments is the change in the fair value of our commodity price hedging contracts and our interest rate swaps during the period. 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 $9.1 million for the first six months of 2010 compared to $12.5 million for the first six months of 2009. After adjusting for permanent tax differences, we recorded an income tax benefit of $2.9 million for the first six months of 2010, compared to $4.3 million for the first six months of 2009.

Dividends on Preferred Stock. Dividends on preferred stock were zero for the first six months of 2010 compared with $2.2 million for the first six months of 2009. All of the Series G and Series H Preferred Stock, including accrued dividends, were converted to Common Stock in December 2009 in conjunction with our Common Stock offering. Dividends in the first six months of 2009 included approximately $2.2 million on the Series G Preferred Stock and $8,820 on the Series H Preferred Stock.

Liquidity and Capital Resources

Our primary cash requirements during the year 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 revolving credit facility. 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, asset monetizations or curtailment of capital expenditures.

Liquidity and Cash Flow

During 2009 there was uncertainty, volatility and disruption in the equity and debt markets, all of which adversely affected the financial condition and/or business strategies of some of our lenders, the counterparties to our derivative instruments, our insurers and our crude oil and natural gas purchasers, which then created uncertainty for ourselves and our industry. 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 substantial portion of our production is hedged, we are still subject to commodity price risk on the unhedged portion of our production, therefore our liquidity may be adversely affected if commodity prices were to decline.

Our working capital deficit was $18.4 million as of June 30, 2010, compared to a working capital deficit of $8.8 million as of December 31, 2009.

The following table provides the components and changes in working capital as of June 30, 2010 and December 31, 2009.

	June 30, 2010			December 31, 2009			Change
Current assets
Accounts receivable, net	$	13,389,207		$	14,773,246		$	(1,384,039	)
Prepaid expenses		7,965			—			7,965
Derivative instruments		10,591,197			9,937,697			653,500
Total current assets		23,988,369			24,710,943			(722,574	)

Current liabilities
Current portion of long-term debt		4,898			19,014			(14,116	)
Accounts payable and accrued liabilities		37,150,887			29,115,653			8,035,234
Income tax payable		253,726			250,931			2,795
Asset retirement obligations		717,748			330,287			387,461
Derivative instruments		1,300,627			872,849			427,778
Deferred tax liability, net		2,929,811			2,897,300			32,511
Total current liabilities		42,357,697			33,486,034			8,871,663

Working capital (deficit)	$	(18,369,328	)	$	(8,775,091	)	$	(9,594,237	)

The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from internal and external sources, for the six months ended June 30, 2010 and 2009, respectively.

		Six months ended June 30,
		2010			2009
Financial Measures		(in millions)
Net cash provided by (used in) operating activities	$	22.2		$	(13.3	)
Net cash used in investing activities		(21.9	)		(11.3	)
Net cash (used in) provided by financing activities		(0.3	)		24.6
Cash and cash equivalents		—			—

Net cash provided by operating activities was $22.2 million for the six months ended June 30, 2010, compared to net cash used in operating activities of $13.3 million for the six months ended June 30, 2009. During the first six months of 2010, the net cash provided by operating activities, before changes in

working capital, decreased to $13.1 million, from $25.1 million for the six months of 2009, primarily due to lower revenue on lower production.

Net cash used in investing activities, which consists primarily of capital expenditures on oil and gas drilling projects and leasehold acquisitions, was $21.9 million for the six months ended June 30, 2010, compared to $11.3 million for the six months ended June 30, 2009.

Net cash used in financing activities, which consists primarily of net borrowings/repayments on our revolving credit agreement, was $0.3 million for the six months ended June 30, 2010, compared to net cash provided by financing activities of $24.6 million for the six months ended June 30, 2009. In the first six months of 2010, we borrowed a net $0.2 million under our revolving credit agreement, while we borrowed a net $25.8 million in the first six months of 2009 primarily to satisfy the fourth quarter 2008 balance in current liabilities related to the active drilling program in the fourth quarter of 2008.

See the Consolidated Statements of Cash Flows for further details.

Capital resources

We have a revolving credit agreement with Wells Fargo Bank, National Association(“Wells Fargo Bank”), as agent, and the lender parties thereto that currently provides for a $100.0 million borrowing base, based on our current proved crude oil and natural gas reserves. The borrowing base is periodically determined by our banks based primarily upon an evaluation of our oil and gas reserves position, which can be impacted by changes in commodity prices including hedged positions, drilling costs and results, production, and other revisions, additions and sales of reserves. The borrowing base is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates. The next borrowing base redetermination under our Senior Credit Agreement is scheduled for November 1, 2010. The revolving credit agreement has a term of four and one-half years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on January 8, 2012. The credit agreement also provides for the issuance of letters-of-credit up to a $5.0 million sub-limit. Although this agreement contains restrictions on our ability to incur debt, we may issue up to $200.0 million in senior unsecured notes. Any such issuance of senior unsecured notes may reduce our borrowing base by 25% of the net proceeds from such issuance in excess of $150.0 million.

Advances under our revolving credit agreement are in the form of either base rate loans or LIBOR loans. The interest rate on the base rate loans fluctuates based upon the higher of the lender’s “prime rate” and the Federal Funds rate. The interest rate on the LIBOR loans fluctuates based upon the rate at which Eurodollar deposits in the LIBOR market are quoted for the maturity selected. Pursuant to an amendment to our revolving credit agreement, dated July 31, 2009, the applicable margin was increased from between 1.25% and 2.00% to between 2.75% and 3.50%, for LIBOR loans, and from zero and 0.50% to between 1.50% and 2.00%, for base rate loans. The specific applicable interest margin is determined by, in each case, the percent of the borrowing base utilized at the time of the credit extension. LIBOR loans of one, two, three and six months may be selected. Pursuant to that same amendment, the commitment fee payable on the unused portion of our borrowing base was increased from 0.375% to 0.50%, which fee accrues and is payable quarterly in arrears.

We also have a second lien credit agreement with Credit Suisse, as agent, and the lender parties thereto that provided for term loans, made to us in a single draw, in an aggregate principal amount of $150.0 million, which matures on May 8, 2012.

Advances under our second lien credit agreement are in the form of either base rate loans or LIBOR loans. The interest rate on the base rate loans fluctuates based upon the higher of (i) the “prime rate”, (ii) the Federal Funds Effective Rate plus ½ of 1% and (iii) the LIBO rate for a one month interest period plus 1.50%. The applicable margin for base rate loans is 6.0%, unless we fail to meet certain leverage and PV-10 ratios, in which case the applicable margin will be 7.0%. The interest rate on the LIBOR loans fluctuates based upon the higher of (i) 3.0% per annum and (ii) the LIBOR rate per annum. The applicable margin for LIBOR loans is 7.0%, unless we fail to meet certain leverage and PV-10 ratios, in which case the applicable margin will be 8.0%.

Our revolving credit agreement and second lien credit agreement are secured by liens on substantially all of our assets, including the capital stock of our subsidiaries. The liens securing the obligations under our second lien credit agreement are junior to those under our revolving credit agreement. Unpaid interest is payable under our credit agreements as borrowings mature and renew.

As consideration for OCM GW Holdings, LLC’s (“Oaktree Holdings”) agreement to deposit $10.0 million in escrow on November 6, 2009 to collateralize a $10.0 million unsecured promissory note between Crimson and Wells Fargo Bank, which was subsequently repaid on December 22, 2009, we issued an unsecured subordinated promissory note on November 6, 2009 for the principal amount of $2.0 million to Oaktree Holdings, a related party. The indebtedness under the $2.0 million promissory note bears interest at a per annum rate equal to 8.0% 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 our credit agreements), and the termination of all commitments to extend credit under our credit agreements. The promissory note is subordinated in right of payment to the prior payment in full in cash of all obligations under our credit agreements. At June 30, 2010, the carrying fair value of this debt was calculated as $1.8 million, net of discount, using the estimated market value interest rate at the time of issuance.

We utilize financial commodity price hedge instruments to minimize exposure to declining prices on our natural gas, crude oil and natural gas liquids production. As of June 30, 2010, we had 3.6 Bcfe and 4.0 Bcfe of equivalent production hedged for 2010 and 2011, respectively, consisting of 2.9 Bcf and 3.2 Bcf of natural gas hedges in place and 125 MBbl and 136 MBbl of crude oil hedges in place for 2010 and 2011, respectively. We used a series of swaps and costless collars to accomplish our commodity hedging position. We also constructively fixed the base LIBOR on $200.0 million and $150.0 million of our variable rate debt by entering into interest rate swaps at a weighted average swap price of 2.6% and 2.9% for 2010 and 2011, respectively.

At July 30, 2010, we had $42.0 million outstanding under our revolving credit agreement and $150.0 million outstanding under our second lien credit agreement, with availability under our revolving credit agreement of $53.0 million.

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 the majority of our drilling activity over the next several years on continued development of our East Texas and South 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 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 revolving credit agreement, will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next 12 months. Our ability to execute on our growth strategy will be determined, in large part, by our cash flow and the availability of debt and equity capital at that time. 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 continue 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 revolving credit agreement in connection with a borrowing base redetermination. In such case, we may be required to seek other sources of capital earlier than anticipated. Restrictions in our credit agreements 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, 2009.

Recent Accounting Pronouncements

There were no recently issued standards that were applicable to us that have not yet been adopted.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure 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.

Changes in Internal Control and Procedures

During the period covered by this report, there has been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A. RISK FACTORS

Except as disclosed below, there are no material changes from risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

If our internal controls over financial reporting do not comply with the requirements of the Sarbanes-Oxley Act, our business and stock price could be adversely affected.

Section 404 of the Sarbanes-Oxley Act of 2002 currently requires us to evaluate the effectiveness of our internal controls over financial reporting at the end of each fiscal year and to include a management report assessing the effectiveness of our internal controls over financial reporting in all annual reports.

In July 2010, Congress passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which was subsequently signed into law. Included in the act is a provision that permanently exempts small public companies that qualify as either a Non-Accelerated Filer or Smaller Reporting Company from the auditor attestation requirement of Section 404(b) of the Sarbanes-Oxley Act of 2002. For our fiscal year ending December 31, 2010, we currently expect to be exempt from such requirement; however, to the extent we do not qualify as a Non-Accelerated Filer or Smaller Reporting Company in

subsequent fiscal years, we will be subject to such auditor attestation requirement. In such an event, we may not be able to complete the work required for such attestation on a timely basis, and even if we timely complete such requirements, our independent registered public accounting firm may still conclude that our internal controls over financial reporting are not effective.

Our management, including our CEO and CFO, does not expect that our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been or will be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Over time, our controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

ITEM 6. EXHIBITS


Number		Description

3.1		Certificate of Incorporation of Crimson Exploration Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed July 5, 2005)

3.2		By-laws of Crimson Exploration Inc. (incorporated by reference to Exhibit 3.7 to the Company’s Current Report on Form 8-K filed July 5, 2005)

4.1		Form of Common Stock Certificate (incorporated by reference to Exhibit 3.7 to the Company’s Current Report on Form 8-K filed July 5, 2005)

4.2		Letter Agreement by and among GulfWest Energy Inc., a Texas corporation, GulfWest Oil & Gas Company and the investors listed on the signature page thereof, dated April 22, 2004 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 10, 2004)

4.3		Shareholders Rights Agreement between GulfWest Energy Inc. and OCM GW Holdings, LLC dated February 28, 2005 (incorporated by reference to Exhibit 99(e) of the Schedule 13D, Reg. No. 005-54301, filed on March 10, 2005)

4.4		Omnibus and Release Agreement among GulfWest Energy Inc., OCM GW Holdings, LLC and those signatories set forth on the signature page thereto, dated as of February 28, 2005 (incorporated by reference to Exhibit 99(f) of the Schedule 13D, Reg. No. 005-54301, filed on March 10, 2005)

Number		Description

4.5		Waiver, Consent and First Amendment to the Shareholders Rights Agreement, dated as of December 7, 2009, between Crimson Exploration Inc. and OCM GW Holdings, LLC (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed December 10, 2009)

4.6		Termination Agreement, dated as of December 7, 2009, between Crimson Exploration Inc. and OCM GW Holdings, LLC (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed December 10, 2009)

10.1		Fifth Amendment dated as of June 9, 2010, to the Amended and Restated Credit Agreement, dated as of May 31, 2007, by and among Crimson Exploration Inc., as borrower, the Guarantors party thereto, the Lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 14, 2010).

*#10.2		Employment Agreement between Carl Isaac and Crimson Exploration Inc., dated May 10, 2010.

*31.1		Certification of Chief Executive Officer pursuant to Exchange Rule13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of Chief Financial Officer pursuant to Exchange Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**32.1		Certification of Chief Executive Officer pursuant to 18.U.S.C Section 1350 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2		Certification of Chief Financial Officer pursuant to 18.U.S.C Section 1350 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

		* Filed herewith.
		** Furnished herewith
		# Management contract or compensatory plan or arrangement

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)

Date:	August 5, 2010	By:	/s/ Allan D. Keel
			Allan D. Keel
			President and Chief Executive Officer

Date:	August 5, 2010	By:	/s/ E. Joseph Grady
			E. Joseph Grady
			Senior Vice President and Chief Financial Officer