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 September 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 November 5, 2010, there were 43,033,083 shares outstanding of the registrant’s Common Stock, par value $0.001.

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED SEPTEMBER 30, 2010


	Page

Part I: Financial Information

Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	3
Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2010 and 2009	4
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2010	5
Consolidated Statements of Cash Flows for the Nine Months Ended September 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	14

Item 4. Controls and Procedures	25

Part II: Other Information

Item 1A. Risk Factors	26

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	26

Item 6. Exhibits	27

Signatures	29

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	September 30,			December 31,
	2010			2009
	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Accounts receivable, net of allowance of $411,324 and $411,324, respectively		15,835,972			14,773,246
Prepaid expenses		9,000			—
Derivative instruments		11,063,206			9,937,697
Total current assets		26,908,178			24,710,943

PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method of accounting)		597,364,843			559,565,531
Other property and equipment		3,375,348			3,679,515
Accumulated depreciation, depletion and amortization		(202,647,649	)		(170,117,319	)
Total property and equipment, net		398,092,542			393,127,727

NONCURRENT ASSETS
Deposits		104,697			104,697
Debt issuance cost		2,892,264			4,347,298
Derivative instruments		1,688,931			2,513,369
Deferred tax asset, net		476,374			—
Total noncurrent assets		5,162,266			6,965,364

TOTAL ASSETS	$	430,162,986		$	424,804,034

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	1,662		$	19,014
Accounts payable		33,290,306			20,263,343
Income taxes payable		—			250,931
Accrued liabilities		11,049,163			8,852,310
Asset retirement obligations		766,427			330,287
Derivative instruments		2,040,208			872,849
Deferred tax liability, net		2,824,145			2,897,300
Total current liabilities		49,971,911			33,486,034

NONCURRENT LIABILITIES
Long-term debt, net of current portion		196,274,986			192,749,751
Asset retirement obligations		9,068,117			9,372,366
Derivative instruments		151,917			1,284,105
Deferred tax liability, net		—			4,471,023
Other noncurrent liabilities		682,737			709,867
Total noncurrent liabilities		206,177,757			208,587,112

Total liabilities		256,149,668			242,073,146

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Common stock (par value $0.001; 200,000,000 shares authorized; 38,785,570 and 38,516,658 shares issued and outstanding, respectively)		38,881			38,578
Additional paid-in capital		211,114,212			209,738,513
Retained deficit		(36,643,834	)		(26,661,891	)
Treasury stock (at cost, 95,146 and 61,546 shares, respectively)		(495,941	)		(384,312	)
Total stockholders’ equity		174,013,318			182,730,888

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	430,162,986		$	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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

OPERATING REVENUES
Natural gas sales	$	15,474,237		$	16,426,246		$	43,490,452		$	55,135,137
Crude oil sales		5,404,136			6,709,774			15,095,988			21,518,736
Natural gas liquids sales		3,529,359			3,616,522			9,577,462			9,089,086
Operating overhead and other income		128,175			147,862			434,807			508,249
Total operating revenues		24,535,907			26,900,404			68,598,709			86,251,208

OPERATING EXPENSES
Lease operating expenses		3,583,572			3,879,621			11,420,069			13,517,664
Production and ad valorem taxes		1,399,292			1,563,460			4,580,119			6,060,579
Exploration expenses		1,311,678			687,613			1,994,794			2,873,255
Depreciation, depletion and amortization		12,035,848			13,400,031			32,973,530			41,599,314
General and administrative		4,501,413			3,836,194			13,897,108			13,381,282
(Gain) loss on sale of assets		(10,453	)		—			420,366			18,925
Total operating expenses		22,821,350			23,366,919			65,285,986			77,451,019

INCOME FROM OPERATIONS		1,714,557			3,533,485			3,312,723			8,800,189

OTHER INCOME (EXPENSE)
Interest expense		(5,785,042	)		(6,633,642	)		(16,387,881	)		(16,349,300	)
Other financing cost		(776,137	)		(382,159	)		(2,349,167	)		(1,109,805	)
Unrealized (loss) gain on derivative instruments		(1,258,326	)		(9,929,947	)		265,899			(17,237,909	)
Total other income (expense)		(7,819,505	)		(16,945,748	)		(18,471,149	)		(34,697,014	)

LOSS BEFORE INCOME TAXES		(6,104,948	)		(13,412,263	)		(15,158,426	)		(25,896,825	)

Income tax benefit		2,285,040			4,826,137			5,176,483			9,080,238

NET LOSS		(3,819,908	)		(8,586,126	)		(9,981,943	)		(16,816,587	)

Dividends on preferred stock (Paid 2010 — $0; 2009 — $20,370)		—			(1,156,163	)		—			(3,353,150	)

NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(3,819,908	)	$	(9,742,289	)	$	(9,981,943	)	$	(20,169,737	)

NET LOSS PER SHARE
Basic	$	(0.10	)	$	(1.51	)	$	(0.26	)	$	(3.20	)
Diluted	$	(0.10	)	$	(1.51	)	$	(0.26	)	$	(3.20	)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		38,819,780			6,444,013			38,655,038			6,301,280
Diluted		38,819,780			6,444,013			38,655,038			6,301,280

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 NINE MONTHS ENDED SEPTEMBER 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		—			—		—			(9,981,943	)		—			(9,981,943	)
Share-based compensation		287,749			288		1,353,056			—			—			1,353,344
Stock options exercised		14,763			15		35,416			—			—			35,431
Common stock issuance costs		—			—		(12,773	)		—			—			(12,773	)
Treasury stock		(33,600	)		—		—			—			(111,629	)		(111,629	)
BALANCE, SEPTEMBER 30, 2010		38,785,570		$	38,881	$	211,114,212		$	(36,643,834	)	$	(495,941	)	$	174,013,318

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)

	Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(9,981,943	)	$	(16,816,587	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		32,973,530			41,599,314
Asset retirement obligations		(150,512	)		(361,239	)
Stock compensation expense		1,353,344			1,869,400
Amortization of debt issuance cost		2,049,205			945,313
Discount on notes payable		56,854			—
Deferred charges		—			1,324,907
Deferred income taxes		(5,020,552	)		(9,595,940	)
Dry holes, abandoned property, impaired assets		1,202,033			221,960
Loss on sale of assets		420,366			18,925
Unrealized (gain) loss on derivative instruments		(265,899	)		17,237,909
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, net		(1,062,726	)		8,675,339
(Increase) decrease in prepaid expenses		(9,000	)		73,444
Increase (decrease) in accounts payable and accrued liabilities		14,945,755			(42,440,824	)
Net cash provided by operating activities		36,510,455			2,751,921

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(38,903,315	)		(16,545,051	)
Acquisition of oil and gas properties		—			493,532
Sale of assets		(375,026	)		24,327
Net cash used in investing activities		(39,278,341	)		(16,027,192	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt		(69,259,844	)		(76,578,082	)
Proceeds from debt		72,710,872			91,373,659
Debt issuance expenditures		(594,171	)		(1,387,195	)
Common stock issuance costs		(12,773	)		—
Proceeds from stock option exercises		35,431			—
Purchase of treasury stock		(111,629	)		(133,111	)
Net cash provided by financing activities		2,767,886			13,275,271

INCREASE IN CASH AND CASH EQUIVALENTS		—			—

CASH AND CASH EQUIVALENTS,
Beginning of period		—			—

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

Cash paid for interest	$	19,823,842		$	14,484,741
Cash paid for income taxes	$	95,000		$	539,671

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 September 30, 2010 (unaudited) and December 31, 2009 and for the three and nine months ended September 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 nine months ended September 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 three and nine months ended September 30, 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 September 30, 2010:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Crude oil swaps and collars	$	(1,642,043	)	$	—	$	(1,642,043	)	$	—
Natural gas swaps and collars		14,730,612			—		14,730,612			—
Interest rate swaps		(2,528,557	)		—		(2,528,557	)		—
Total	$	10,560,012		$	—	$	10,560,012		$	—

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 nine 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 approximately $10.6 million and $10.3 million at September 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 and losses:

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

Natural gas contracts	Operating revenues	$	4,758,796		$	8,743,868		$	13,810,595		$	23,238,589
Crude oil contracts	Operating revenues		576,588			1,625,058			1,432,867			7,570,971
Interest rate contracts	Interest expense		(1,145,628	)		(1,158,810	)		(3,438,406	)		(3,242,533	)
	Realized gain	$	4,189,756		$	9,210,116		$	11,805,056		$	27,567,027

Natural gas contracts	Other income (expense)	$	(389,793	)	$	(8,693,933	)	$	(1,506,052	)	$	(4,630,639	)
Crude oil contracts	Other income (expense)		(1,680,336	)		(891,655	)		(309,959	)		(13,058,373	)
Interest rate contracts	Other income (expense)		811,803			(344,359	)		2,081,910			451,103
	Unrealized gain (loss)	$	(1,258,326	)	$	(9,929,947	)	$	265,899		$	(17,237,909	)

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 September 30, 2010:

Crude Oil		Volume/Month		Price/Unit		Fair Value
Oct 2010-Dec 2010 (2)	Swap	4,250 Bbls		$72.32	$	(112,931	)
Oct 2010-Dec 2010 (2)	Collar	9,000 Bbls		$65.28-$70.60		(293,917	)
Oct 2010-Dec 2010 (2)	Collar	7,667 Bbls	(1)	$110.00-$181.25		662,682
Jan 2011-Dec 2011	Swap	3,300 Bbls		$70.74		(555,783	)
Jan 2011-Dec 2011	Collar	7,000 Bbls		$64.50-$69.50		(1,372,441	)
Jan 2011-Mar 2011	Swap	2,000 Bbls		$86.15		17,030
Apr 2011-Jun 2011	Swap	1,500 Bbls		$86.78		10,381
Jul 2011-Sep 2011	Swap	500 Bbls		$87.32		2,936

Natural Gas
Oct 2010-Dec 2010 (2)	Swap	29,000 Mmbtu		$7.88		342,464
Oct 2010-Dec 2010 (2)	Collar	351,000 Mmbtu		$7.57-$9.05		3,831,230
Oct 2010-Dec 2010 (2)	Collar	85,867 Mmbtu	(1)	$9.00-$15.25		1,305,231
Jan 2011-Dec 2011	Collar	266,000 Mmbtu		$7.32-$8.70		9,251,687
		Commodity price derivative instruments				13,088,569

Interest rate		Notional Amount		Fixed LIBOR Rate
Oct 2010-Dec 2010 (2)	Swap	$50,000,000		1.50%		(141,892	)
Oct 2010- May 2011 (2)	Swap	$150,000,000		2.90%		(2,386,665	)
Interest rate derivative instruments						(2,528,557	)
Total net fair value asset of derivative instruments					$	10,560,012

(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		43,119
Accretion expense		443,202
Revisions		—
Properties sold		(203,918	)
Plugging and abandonment activity		(150,512	)
Ending September 30, 2010 liability	$	9,834,544

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 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. We are currently working with our bank group on finalizing the November 2010 scheduled redetermination of our borrowing base and believe that it will be determined at an amount that is reasonably comparable with our current borrowing base. 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 September 30, 2010, we had an outstanding loan balance of $44.5 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 million. Until we enter into additional hedging agreements that would add an incremental $3 million in discounted present value to our reserve base, a maximum of $95 million of the $100 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 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 September 30, 2010, we had an outstanding loan balance of $150 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 September 30, 2010, we were in compliance with all covenants under our Credit Agreements.

As consideration for Oaktree Holdings’ agreement to deposit $10 million in escrow on November 6, 2009, to collateralize a $10 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 million to Oaktree Holdings, a related party. The indebtedness under the $2 million promissory note bears interest at a per annum rate equal to 8% and matures on the later of (i) November 8, 2012 and (ii) the date nine 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 September 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 nine months ended September 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 nine months ended September 30, 2010, approximately 0.3 million shares of previously issued restricted Common Stock vested, of which 33,600 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 74,256 unvested shares of restricted Common Stock forfeited due to employee terminations. We also issued 14,763 shares of Common Stock pursuant to employee stock option exercises in the nine months ended September 30, 2010.

8. INCOME TAXES

Income tax benefit for the three and nine months ended September 30, 2010 was $2.3 million and $5.2 million, respectively, compared to $5.2 million and $9.1 million, respectively, for the three and nine months ended September 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. SUBSEQUENT EVENT

deposit was recorded in accounts payable at September 30, 2010. We also issued a 60-day option by which ACEC may acquire an additional 1,750,000 shares of Series I Convertible Preferred Stock, par value $0.01 per share, a newly created series of preferred stock at $5.00 per share, for additional consideration of $8.75 million. If the preferred stock is issued upon exercise of the option, ACEC, as holder of preferred stock, would have the right to appoint a director to our board of directors. The preferred stock will automatically convert into an equal number of shares of Common Stock upon the earlier of (i) the exercise of the ACEC’s right to appoint a director and (ii) December 31, 2010. If the option is exercised and the preferred shares are converted, ACEC will have been issued an aggregate of 6.0 million shares of common stock, or approximately 13.4% of the outstanding shares of Common Stock. We intend to use the net proceeds from the private placement for general corporate purposes, including the continued development of our significant inventory of drilling prospects.

10. RECENT ACCOUNTING PRONOUNCEMENTS

New Accounting Standards Adopted in 2010

In April 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-14, Accounting for Extractive Industries—Oil and Gas (Topic 932): Amendments to Paragraph 932-10-S99-1 (“ASU 2010-14”). ASU 2010-14 incorporates updated text changes to Rule 4-10 of the Securities and Exchange Commission (“SEC”) Regulation S-X into the FASB’s Accounting Standards Codification (“ASC”). The amendments reflect changes to fossil fuel exploration and production definitions, and addresses issues associated with new technology implemented over the past several decades. Specifically, the additional text added to FASB ASC 932-10-S99-1 reflects changes previously included in SEC Final Rulemaking Release No. 33-8995, Modernization of Oil and Gas Reporting, which became effective on January 1, 2010. The adoption of this ASU did not have a material impact on our financial position, results of operations or cash flows.

In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements (“ASU 2010-09”). ASU 2010-09 amends Subtopic 855-10 to remove some contradictions between the requirements of U.S. GAAP and the SEC’s filing rules. As a result, public companies will no longer have to disclose the date through which subsequent events have been evaluated. We adopted these amendments as of February 24, 2010, with the issuance of this ASU. The adoption of this ASU did not have a material impact on our financial position, results of operations or cash flows.

We adopted FASB ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements(“ASU 2010-06”) on January 1, 2010. ASU 2010-06 requires, among other items, reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by FASB ASC 820. The adoption of this ASU did not have a material impact on our financial position, results of operations or cash flows.

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 Annual Report on Form 10-K for the year ended December 31, 2009 and our Quarterly Report on Form 10-Q for the period ended June 30, 2010, as filed 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 September 30, 2010 Compared to Three Months Ended September 30, 2009

Revenues

Natural Gas, Crude Oil and Natural Gas Liquids Sales

	Three months ended September 30,
	2010		2009		Change			Percent Change
Product revenues:	(in millions, except percentages)
Natural gas sales	$	15.5	$	16.4	$	(0.9	)		-5.5	%
Crude oil sales		5.4		6.7		(1.3	)		-19.4	%
Natural gas liquids sales		3.5		3.6		(0.1	)		-2.8	%
Product revenues	$	24.4	$	26.7	$	(2.3	)		-8.6	%

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 $24.4 million for the third quarter 2010 compared to $26.7 million for the third quarter 2009. The decrease in revenue was due to lower production and lower realized commodity prices.

Production

	Three months ended September 30,
	2010		2009		Change			Percent Change
Sales volumes:
Natural gas (Mcf)		2,390,868		2,373,940		16,928			0.7	%
Crude oil (Bbl)		63,755		76,376		(12,621	)		-16.5	%
Natural gas liquids (Bbl)		101,992		114,792		(12,800	)		-11.2	%
Natural gas equivalents (Mcfe)		3,385,350		3,520,948		(135,598	)		-3.9	%

Quarterly production was approximately 3.4 Bcfe for the third quarter 2010 compared to approximately 3.5 Bcfe for the third quarter 2009 and 2.7 Bcfe for the second quarter of 2010. On a daily basis, we produced an average of 36,797 Mcfe for the 2010 third quarter compared to an average of 38,271 Mcfe for the 2009 quarter and 30,084 Mcfe per day for the second quarter of 2010. Included in the 2009 quarter was approximately 259,000 Mcfe from our Southwest Louisiana properties that were sold in December 2009. Higher normalized production volumes, exclusive of the sale of our Southwest Louisiana properties, are a result of production from new wells drilled and workovers completed in 2010.

Average Sales Prices

	Three months ended September 30,
	2010		2009		Change		Percent Change
Average sales prices (before hedging):
Natural gas (Mcf)	$	4.48	$	3.24	$	1.24		38.3	%
Crude oil (Bbl)		75.72		66.57		9.15		13.7	%
Natural gas liquids (Bbl)		34.60		31.51		3.09		9.8	%
Natural gas equivalents (Mcfe)		5.63		4.65		0.98		21.1	%

	Three months ended September 30,
	2010		2009		Change			Percent Change
Average sales prices (after hedging):
Natural gas (Mcf)	$	6.47	$	6.92	$	(0.45	)		-6.5	%
Crude oil (Bbl)		84.76		87.85		(3.09	)		-3.5	%
Natural gas liquids (Bbl)		34.60		31.51		3.10			9.8	%
Natural gas equivalents (Mcfe)		7.21		7.60		(0.39	)		-5.1	%

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $0.6 million on our crude oil hedges and $4.8 million on our natural gas hedges in the third quarter 2010, compared to realized gains of $1.6 million for crude oil hedges and $8.8 million for natural gas hedges in the third quarter 2009, all of which were included in our natural gas and crude oil sales revenues on our Consolidated Statements of Operations.

Costs and Expenses

	Three months ended September 30,
	2010		2009		Change			Percent Change
Certain Operating Expenses:	(in millions, except percentages)
Lease operating expenses	$	3.6	$	3.9	$	(0.3	)		-7.7	%
Production and ad valorem taxes		1.4		1.6		(0.2	)		-12.5	%
Exploration expenses		1.3		0.7		0.6			85.7	%
General and administrative(1)		4.0		3.5		0.5			14.3	%
Operating expenses		10.3		9.7		0.6			6.2	%
Depreciation, depletion & amortization		12.0		13.4		(1.4	)		-10.4	%
Share-based compensation(1)		0.5		0.3		0.2			66.7	%
Certain operating expenses	$	22.8	$	23.4	$	(0.6	)		-2.6	%

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

	Three months ended September 30,
	2010		2009		Change			Percent Change
Selected Costs ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	1.06	$	1.10	$	(0.04	)		-3.6	%
Production and ad valorem taxes		0.41		0.44		(0.03	)		-6.8	%
Exploration expenses		0.39		0.20		0.19			95.0	%
General and administrative(1)		1.20		0.99		0.21			21.2	%
Operating expenses		3.06		2.73		0.33			12.1	%
Depreciation, depletion & amortization		3.56		3.81		(0.25	)		-6.6	%
Share-based compensation(1)		0.13		0.10		0.03			30.0	%
Selected costs	$	6.75	$	6.64	$	0.11			1.7	%

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

Lease Operating Expenses. Lease operating expenses for the third quarter 2010 were $3.6 million, compared to $3.9 million in the third quarter 2009, a slight increase over the $3.2 million incurred in the third quarter 2009 after adjustment for the sale of the Southwest Louisiana properties in December 2009.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the third quarter 2010 were $1.4 million, compared to $1.6 million for the third quarter 2009, due to lower production, offset in part by higher sales prices in the third quarter of 2010.

Exploration Expenses. Exploration expenses were $1.3 million in the third quarter 2010, compared to $0.7 million for the third quarter 2009. Exploration expenses resulted primarily from lease expiration on certain conventional prospects in South Texas during the third quarter 2010, and from geological and geophysical costs in the third quarter 2009.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the third quarter 2010 was $12 million compared to $13.4 million for the third quarter 2009, a decrease primarily due to lower production.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $4.5 million for the third quarter 2010 compared to $3.8 million for the third quarter 2009. Included in G&A expense is non-cash stock expense of $0.5 million ($0.13 per Mcfe) and $0.3 million ($0.10 per Mcfe) for the third quarters 2010 and 2009, respectively. G&A expenses for the third quarter 2010 were higher primarily due to higher estimated incentive compensation and higher legal fees.

Interest Expense. Interest expense was $5.8 million for the third quarter 2010, compared to $6.6 million for the third quarter 2009. Total interest expense decreased primarily due to the decrease in the outstanding debt on our revolving credit agreement, offset in part 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 third quarter 2010, compared to $0.4 million for the third quarter 2009. These expenses consist primarily of the amortization of deferred debt issuance costs associated with our credit facilities.

Unrealized Loss on Derivative Instruments. The non-cash unrealized loss on derivative instruments for the third quarter 2010 was $1.3 million, compared to $9.9 million for the third 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 $6.1 million for the third quarter 2010, compared to $13.4 million in the third quarter 2009. After adjusting for permanent tax differences, we recorded an income tax benefit of $2.3 million for the third quarter 2010, compared to $4.8 million for the third quarter 2009.

Dividends on Preferred Stock. Dividends on preferred stock were zero for the third quarter 2010, compared with $1.2 million in the third 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 third quarter 2009 included approximately $1.1 million on the Series G Preferred Stock and $10,745 on the Series H Preferred Stock.

Nine months Ended September 30, 2010 Compared to Nine months Ended September 30, 2009

Revenues

Natural Gas, Crude Oil and Natural Gas Liquids Sales

	Nine months ended September 30,
	2010		2009		Change			Percent Change
Product revenues:	(in millions, except percentages)
Natural gas sales	$	43.5	$	55.1	$	(11.6	)		-21.1	%
Crude oil sales		15.1		21.5		(6.4	)		-29.8	%
Natural gas liquids sales		9.6		9.1		0.5			5.5	%
Product revenues	$	68.2	$	85.7	$	(17.5	)		-20.4	%

Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our hedging instruments, were $68.2 million for the first nine months of 2010 compared to $85.7 million for the first nine months of 2009, a decrease due primarily to lower production, offset in part by higher realized commodity prices.

Production

	Nine months ended September 30,
	2010		2009		Change			Percent Change
Sales volumes:
Natural gas (Mcf)		6,432,283		8,142,588		(1,710,305	)		-21.0	%
Crude oil (Bbl)		178,825		264,170		(85,345	)		-32.3	%
Natural gas liquids (Bbl)		243,859		334,303		(90,444	)		-27.1	%
Natural gas equivalents (Mcfe)		8,968,387		11,733,426		(2,765,039	)		-23.6	%

Production was approximately 9.0 Bcfe for the first nine months of 2010 compared to 11.7 Bcfe for the first nine months of 2009. On a daily basis, we produced an average of 32,851 Mcfe in the first nine

months of 2010 compared to an average of 42,980 Mcfe in the first nine months of 2009. Production for the first nine months of 2009 included approximately 906,000 Mcfe from our Southwest Louisiana properties that were sold in December 2009.

Average Sales Prices

	Nine months ended September 30,
	2010		2009		Change		Percent Change
Average sales prices (before hedging):
Natural gas (Mcf)	$	4.61	$	3.92	$	0.69		17.6	%
Crude oil (Bbl)		76.40		52.80		23.60		44.7	%
Natural gas liquids (Bbl)		39.27		27.19		12.08		44.4	%
Natural gas equivalents (Mcfe)		5.90		4.68		1.22		26.1	%

	Nine months ended September 30,
	2010		2009		Change			Percent Change
Average sales prices (after hedging):
Natural gas (Mcf)	$	6.76	$	6.77	$	(0.01	)		-0.1	%
Crude oil (Bbl)		84.42		81.46		2.96			3.6	%
Natural gas liquids (Bbl)		39.27		27.19		12.09			44.5	%
Natural gas equivalents (Mcfe)		7.60		7.31		0.29			4.0	%

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $1.4 million on our crude oil hedges and $13.8 million on our natural gas hedges in the first nine months of 2010, compared to realized gains of $7.6 million on our crude oil hedges and $23.2 million on our natural gas hedges in the first nine months of 2009, which were included in our natural gas and crude oil sales revenues on our Consolidated Statements of Operations.

Costs and Expenses

	Nine months ended September 30,
	2010		2009		Change			Percent Change
Certain Operating Expenses:	(in millions, except percentages)
Lease operating expenses	$	11.4	$	13.5	$	(2.1	)		-15.6	%
Production and ad valorem taxes		4.6		6.1		(1.5	)		-24.6	%
Exploration expenses		2.0		2.9		(0.9	)		-31.0	%
General and administrative(1)		12.5		11.5		1.0			8.7	%
Operating expenses		30.5		34.0		(3.5	)		-10.3	%
Depreciation, depletion & amortization		33.0		41.6		(8.6	)		-20.7	%
Share-based compensation		1.4		1.9		(0.5	)		-26.3	%
Certain operating expenses	$	64.9	$	77.5	$	(12.6	)		-16.3	%

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

	Nine months ended September 30,
	2010		2009		Change			Percent Change
Selected Costs ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	1.27	$	1.15	$	0.12			10.4	%
Production and ad valorem taxes		0.51		0.52		(0.01	)		-1.9	%
Exploration expenses		0.22		0.24		(0.02	)		-8.3	%
General and administrative(1)		1.40		0.98		0.42			42.9	%
Operating expenses		3.40		2.89		0.51			17.6	%
Depreciation, depletion & amortization		3.68		3.55		0.13			3.7	%
Share-based compensation		0.15		0.16		(0.01	)		-6.3	%
Selected costs	$	7.23	$	6.60	$	0.63			9.5	%

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

Lease Operating Expenses. Lease operating expenses for the first nine months of 2010 were $11.4 million, compared to $13.5 million in the first nine months of 2009, a slight increase over the $11.2 million incurred in the nine months 2009 after adjustment for the Southwest Louisiana properties sold in December 2009.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the first nine months of 2010 were $4.6 million, compared to $6.1 million for the first nine months of 2009, due to lower production, offset in part by higher sales prices in the first nine months of 2010.

Exploration Expenses. Exploration expenses were $2.0 million in the first nine months of 2010 compared to $2.9 million for the first nine months of 2009. Exploration expenses resulted primarily from lease expirations on certain conventional prospects in South Texas in the first nine months of 2010, and from geological and geophysical costs in the first nine months of 2009.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the first nine months of 2010 was $33 million compared to $41.6 million for the first nine months of 2009, a decrease primarily due to lower production.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $13.9 million for the first nine months of 2010 compared to $13.4 million for the first nine months of 2009, which includes non-cash stock expense of $1.4 million ($0.15 per Mcfe) and $1.9 million ($0.16 per Mcfe) for the first nine months of 2010 and 2009, respectively. G&A expenses increased primarily due to higher estimated incentive compensation and higher legal fees for the first nine months of 2010.

Loss on Sale of Assets. The loss on sale of assets during the first nine 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 $16.4 million for the first nine months of 2010, compared to $16.3 million for the first nine 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 $2.3 million for the first nine months of 2010 compared with $1.1 million for the first nine months of 2009. These expenses are comprised primarily of the amortization of deferred debt issuance costs associated with our credit facilities.

Unrealized Gain (Loss) on Derivative Instruments. The non-cash unrealized gain for the first nine months of 2010 was $0.3 million compared with a non-cash unrealized loss of $17.2 million for the first nine 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 $15.2 million for the first nine months of 2010 compared to $25.9 million for the first nine months of 2009. After adjusting for permanent tax differences, we recorded an income tax benefit of $5.2 million for the first nine months of 2010, compared to $9.1 million for the first nine months of 2009.

Dividends on Preferred Stock. Dividends on preferred stock were zero for the first nine months of 2010 compared with $3.4 million for the first nine 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 nine months of 2009 included approximately $3.3 million on the Series G Preferred Stock and $19,565 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.

Subsequent Event

On October 26, 2010, we entered into a private placement transaction with America Capital Energy Corporation (“ACEC”), a private investor, whereby ACEC may purchase up to $30.0 million of newly issued Common Stock at a purchase price of $5.00 per share in a two step process. We completed the first step of the transaction and issued 4,250,000 shares of Common Stock, or 9.9% of the post-transaction outstanding shares, to ACEC for a total cash consideration of $21.25 million, of which a $3.0 million deposit was received at the end of September 2010. Because of its contingent nature, the deposit was recorded in accounts payable at September 30, 2010. We also issued a 60-day option by which ACEC may acquire an additional 1,750,000 shares of Series I Convertible Preferred Stock, par value $0.01 per share, a newly created series of preferred stock at $5.00 per share, for additional consideration of $8.75 million. If the preferred stock is issued upon exercise of the option, ACEC, as holder of preferred stock, would have the right to appoint a director to our board of directors. The preferred stock will automatically convert into an equal number of shares of Common Stock upon the earlier of (i) the exercise of the ACEC’s right to appoint a director and (ii) December 31, 2010. If the option is exercised and the preferred shares are converted, ACEC will have been issued an aggregate of 6.0 million shares of common stock, or approximately 13.4% of the outstanding shares of Common Stock. We intend to use the net proceeds from the private placement for general corporate purposes, including the continued development of our significant inventory of drilling prospects.

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 forecasted 2010 and 2011 production from proved developed producing reserves 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 $23.1 million as of September 30, 2010, compared to a working capital deficit of $8.8 million as of December 31, 2009 due to a more active drilling program in 2010.

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

	September 30, 2010			December 31, 2009			Change
Current assets
Accounts receivable, net	$	15.8		$	14.8		$	1.0
Derivative instruments		11.1			9.9			1.2
Total current assets		26.9			24.7			2.2

Current liabilities
Accounts payable and accrued liabilities		44.4			29.1			15.3
Income tax payable		—			0.3			(0.3	)
Asset retirement obligations		0.8			0.3			0.5
Derivative instruments		2.0			0.9			1.1
Deferred tax liability, net		2.8			2.9			(0.1	)
Total current liabilities		50.0			33.5			16.5

Working capital (deficit)	$	(23.1	)	$	(8.8	)	$	(14.3	)

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 nine months ended September 30, 2010 and 2009, respectively.

	Nine months ended September 30,
	2010			2009
Financial Measures	(in millions)
Net cash provided by operating activities	$	36.5		$	2.8
Net cash used in investing activities		(39.3	)		(16.0	)
Net cash provided by financing activities		2.8			13.3
Cash and cash equivalents		—			—
Capital expenditures, including acquisitions		38.9			16.1

Net cash provided by operating activities was $36.5 million for the nine months ended September 30, 2010, compared to $2.8 million for the nine months ended September 30, 2009. During the first nine months of 2010, the net cash provided by operating activities, before changes in working

capital, decreased to $22.4 million, from $36.4 million for the nine 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 $39.3 million for the nine months ended September 30, 2010, compared to $16 million for the nine months ended September 30, 2009.

Net cash provided by financing activities, which consists primarily of net borrowings/repayments on our revolving credit agreement, was $2.8 million for the nine months ended September 30, 2010, compared to $13.3 million for the nine months ended September 30, 2009. In the first nine months of 2010, we borrowed a net $3.5 million under our revolving credit agreement, while we borrowed a net $14.8 million in the 2009 period.

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 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. We are currently working with our bank group on finalizing the November 2010 scheduled redetermination of our borrowing base and believe that it will be determined at an amount that is reasonably comparable with our current borrowing base. 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 million sub-limit. Although this agreement contains restrictions on our ability to incur debt, we may issue up to $200 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 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.

On June 9, 2010, we entered into a fifth amendment to our revolving 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 million. Until we enter into additional hedging agreements that would add an incremental $3 million in discounted present value to our reserve base, a maximum of $95 million of the $100 million borrowing base may be utilized.

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 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 LIBOR rate for a one month interest period plus 1.50%. The applicable margin for base rate loans is 6%, unless we fail to meet certain leverage and PV-10 ratios, in which case the applicable margin will be 7%. The interest rate on the LIBOR loans fluctuates based upon the higher of (i) 3% per annum and (ii) the LIBOR rate per annum. The applicable margin for LIBOR loans is 7%, unless we fail to meet certain leverage and PV-10 ratios, in which case the applicable margin will be 8%.

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 million in escrow on November 6, 2009 to collateralize a $10 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 million to Oaktree Holdings, a related party. The indebtedness under the $2 million promissory note bears interest at a per annum rate equal to 8% 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 September 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 September 30, 2010, we had 1.8 Bcfe and 4.0 Bcfe of equivalent production hedged for 2010 and 2011, respectively, consisting of 1.4 Bcf and 3.2 Bcf of natural gas hedges in place and 63 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 million and $150 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 November 5, 2010, we had $27.3 million outstanding under our revolving credit agreement and $150 million outstanding under our second lien credit agreement, with availability under our revolving credit agreement of $67.7 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 those of 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.

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 have 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

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009 and its modifications in Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, which could materially affect our business, financial condition or future results. The risks described in this report and in our previous filings with the Securities and Exchange Commission are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

We withheld the following shares of Crimson common stock from employee stock distributions to satisfy tax withholding obligations related to restricted stock which vested during the third quarter 2010. These shares may be deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this item.

Period	Total Number of Shares Purchased (1)		Average price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)		Maximum Number (or Approximate Dollar Value) of Shares That May Be Purchased Under the Plan or Programs
July 1-31, 2010		470	$	2.67		470		(1)
August 1-31, 2010		4,390	$	3.10		4,390		(1)
September 1-30, 2010		3,313	$	2.65		3,313		(1)
Total		8,173				8,173

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

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)

3.4		Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Appendix A to the Company’s Definitive Information Statement on Schedule 14C filed August 18, 2006)

3.5		Certificate of Designation, Preferences and Rights of Series I Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed October 29, 2010)

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)

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)

Number		Description

*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

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:	November 10, 2010	By:	/s/ Allan D. Keel
			Allan D. Keel
			President and Chief Executive Officer

Date:	November 10, 2010	By:	/s/ E. Joseph Grady
			E. Joseph Grady
			Senior Vice President and Chief Financial Officer