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 March 31, 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 May 6, 2010, there were 38,476,846 shares outstanding of the registrant’s Common Stock, par value $0.001.

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED MARCH 31, 2010


	Page

Part I: Financial Information

Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	3
Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009	4
Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2010	5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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 4T. Controls and Procedures	22

Part II: Other Information

Item 2. Unregistered Sales of Equity Securities and Use Of Proceeds	23

Item 6. Exhibits	23

Signatures	24

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	March 31,			December 31,
	2010			2009
	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Accounts receivable, net of allowance of $411,324		12,997,584			14,773,246
Prepaid expenses		65,444			—
Derivative instruments		14,190,831			9,937,697
Total current assets		27,253,859			24,710,943

PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method of accounting)		564,726,476			559,565,531
Other property and equipment		3,681,798			3,679,515
Accumulated depreciation, depletion and amortization		(180,388,054	)		(170,117,319	)
Total property and equipment, net		388,020,220			393,127,727

NONCURRENT ASSETS
Deposits		104,697			104,697
Debt issuance cost		3,683,448			4,347,298
Derivative instruments		3,890,016			2,513,369
Total noncurrent assets		7,678,161			6,965,364

TOTAL ASSETS	$	422,952,240		$	424,804,034

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	9,009		$	19,014
Accounts payable		23,532,894			20,263,343
Income taxes payable		282,613			250,931
Accrued liabilities		4,431,277			8,852,310
Asset retirement obligations		332,832			330,287
Derivative instruments		1,596,260			872,849
Deferred tax liability, net		3,980,682			2,897,300
Total current liabilities		34,165,567			33,486,034

NONCURRENT LIABILITIES
Long-term debt, net of current portion		190,767,878			192,749,751
Asset retirement obligations		9,501,849			9,372,366
Derivative instruments		748,440			1,284,105
Deferred tax liability, net		3,699,234			4,471,023
Other noncurrent liabilities		705,928			709,867
Total noncurrent liabilities		205,423,329			208,587,112

Total liabilities		239,588,896			242,073,146

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Common stock (par value $0.001; 200,000,000 shares authorized; 38,489,875 and 38,516,658 shares issued and outstanding, respectively)		38,577			38,578
Additional paid-in capital		210,250,145			209,738,513
Retained deficit		(26,453,076	)		(26,661,891	)
Treasury stock (at cost, 86,973 and 61,546 shares, respectively)		(472,302	)		(384,312	)
Total stockholders’ equity		183,363,344			182,730,888

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	422,952,240		$	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
	March 31,
	2010			2009

OPERATING REVENUES
Natural gas sales	$	14,473,731		$	20,648,222
Crude oil sales		4,716,695			7,433,175
Natural gas liquids sales		3,294,161			2,481,987
Operating overhead and other income		125,272			167,483
Total operating revenues		22,609,859			30,730,867

OPERATING EXPENSES
Lease operating expenses		3,882,851			5,451,753
Production and ad valorem taxes		1,702,864			2,474,742
Exploration expenses		495,837			729,978
Depreciation, depletion and amortization		10,423,552			13,851,886
General and administrative		4,909,320			5,218,289
Total operating expenses		21,414,424			27,726,648

INCOME FROM OPERATIONS		1,195,435			3,004,219

OTHER INCOME (EXPENSE)
Interest expense		(5,357,276	)		(4,379,069	)
Other financing cost		(728,103	)		(301,111	)
Unrealized gain on derivative instruments		5,442,034			9,566,957
Total other income (expense)		(643,345	)		4,886,777

INCOME BEFORE INCOME TAXES		552,090			7,890,996

Income tax expense		(343,275	)		(2,856,383	)

NET INCOME		208,815			5,034,613

Dividends on preferred stock (Paid 2010 — $0; 2009 — $7,875)		—			(1,081,729	)

NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$	208,815		$	3,952,884

NET INCOME PER SHARE
Basic	$	0.01		$	0.66
Diluted	$	0.01		$	0.46

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		38,506,160			6,026,888
Diluted		38,653,645			10,856,219

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2010 (UNAUDITED)

	NUMBER OF SHARES
	COMMON STOCK			COMMON STOCK			ADDITIONAL PAID-IN CAPITAL		RETAINED EARNINGS			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 income		—			—			—		208,815			—			208,815
Share-based compensation		(1,356	)		(1	)		511,632		—			—			511,632
Treasury stock		(25,427	)		—			—		—			(87,990	)		(87,990	)
BALANCE, MARCH 31, 2010		38,489,875		$	38,577		$	210,250,145	$	(26,453,076	)	$	(472,302	)	$	183,363,344

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	208,815		$	5,034,613
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,423,552			13,851,886
Asset retirement obligations		(20,789	)		(202,216	)
Stock compensation expense		511,632			963,632
Amortization of debt issuance cost		680,261			258,372
Discount on notes payable		18,126			—
Deferred income taxes		311,593			2,309,439
Dry holes, abandoned property, impaired assets		107,794			11,234
Gain on derivative instruments		(5,442,034	)		(9,566,957	)
Changes in operating assets and liabilities:
Decrease in accounts receivable, net		1,775,662			52,144
Increase in prepaid expenses		(65,444	)		(231,461	)
Decrease in accounts payable and accrued liabilities		(1,123,739	)		(31,413,594	)
Net cash provided by (used in) operating activities		7,385,429			(18,932,908	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(5,271,023	)		(10,882,797	)
Net cash used in investing activities		(5,271,023	)		(10,882,797	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt		(21,430,814	)		(28,603,288	)
Proceeds from debt		19,420,809			58,418,993
Debt issuance expenditures		(16,411	)		—
Purchase of treasury stock		(87,990	)		—
Net cash (used in) provided by financing activities		(2,114,406	)		29,815,705

INCREASE IN CASH AND CASH EQUIVALENTS		—			—

CASH AND CASH EQUIVALENTS,
Beginning of period		—			—

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

Cash paid for interest	$	8,351,063		$	4,808,855
Cash paid for income taxes	$	—		$	5,000,000

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 that we believe provide significant long-term growth potential in 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 financial statements. The accompanying consolidated financial statements at March 31, 2010 (unaudited) and December 31, 2009 and for the first quarter 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 first quarter 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. 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.

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.

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 were evaluated for accuracy using our crude oil, natural gas and interest rate swap and collar agreements and future commodity and interest rate curves. Differences between management’s calculation and that of the financial institution were evaluated for reasonableness. See Note 4 – “Derivative Instruments” for further information.

Impairments. We review oil and gas properties for impairment when events and circumstances indicate a 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 future cash flows expected in connection with 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 first 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 March 31, 2010:

		Total			Fair Value Measurements Using
		Carrying Value			Level 1		Level 2			Level 3
Derivatives
Crude oil swaps and collars	$	(1,808,294	)	$	—	$	(1,808,294	)	$	—
Natural gas swaps and collars		21,906,818			—		21,906,818			—
Interest rate swaps		(4,362,377	)		—		(4,362,377	)		—
Total	$	15,736,147		$	—	$	15,736,147		$	—

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 quarter 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 $15.7 million and $10.3 million at March 31, 1010 and December 31, 2009, respectively. As a result of these agreements, we recorded a non-cash unrealized gain, for unsettled contracts, of $5.4 million and $9.6 million for the three months ended March 31, 2010 and 2009, respectively. The estimated change in fair value of the derivatives is reported in Other income (expense) as unrealized gain on derivative instruments. The realized gain (loss) on derivative instruments is included in natural gas and crude oil sales for our commodity hedges and as an increase (decrease) 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:


	Location of Gain or (Loss)	Amount of Gain or (Loss) Recognized in Income
Contract Type	Recognized in Income	Three months ended
		March 31, 2010			March 31, 2009
Natural gas contracts	Operating revenues	$	3,581,435		$	6,037,224
Crude oil contracts	Operating revenues		401,554			3,648,074
Interest rate contracts	Interest expense		(1,149,642	)		(1,003,158	)
	Realized gain	$	2,833,347		$	8,682,140

Natural gas contracts	Other income (expense)	$	5,670,152		$	12,584,096
Crude oil contracts	Other income (expense)		(476,210	)		(2,589,009	)
Interest rate contracts	Other income (expense)		248,092			(428,130	)
	Unrealized gain	$	5,442,034		$	9,566,957

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

We use a mix of commodity swaps and costless collars and interest rate swaps to accomplish our hedging strategy. Derivative assets and liabilities with the same counterparty, subject to contractual terms which provide for net settlement, are reported on a net basis on our consolidated balance sheets. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, 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 offsetting relationship we have with each of our counterparties provided for 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 March 31, 2010:

Crude Oil		Volume/Month		Price/Unit		Fair Value
Apr 2010-Dec 2010	Swap	4,250 Bbls		$72.32	$	(482,905	)
Apr 2010-Dec 2010	Collar	9,000 Bbls		$65.28-$70.60		(1,213,569	)
Apr 2010-Dec 2010	Collar	7,639 Bbls	(1)	$110.00-$181.25		1,984,507
Jan 2011-Dec 2011	Swap	3,300 Bbls		$70.74		(606,038	)
Jan 2011-Dec 2011	Collar	7,000 Bbls		$64.50-$69.50		(1,490,289	)

Natural Gas
Apr 2010-Jun 2010	Swap	26,667 Mmbtu (1)	(1)	$6.16 (2)		181,394
Apr 2010-Dec 2010	Swap	29,000 Mmbtu		$7.88		940,718
Apr 2010-Dec 2010	Collar	351,000 Mmbtu		$7.57-$9.05		10,470,637
Apr 2010-Dec 2010	Collar	85,556 Mmbtu	(1)	$9.00-$15.25		3,644,062
Jan 2011-Dec 2011	Collar	266,000 Mmbtu		$7.32-$8.70		6,670,007
		Commodity price derivative instruments				20,098,524

Interest rate		Notional Amount		Fixed LIBOR Rate
Apr 2010-Dec 2010	Swap	$50,000,000		1.50%		(415,868	)
Apr 2010- May 2011	Swap	$150,000,000		2.90%		(3,946,509	)
Interest rate derivative instruments						(4,362,377	)
Total net fair value asset of derivative instruments					$	15,736,147

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

(2) Average price for the remaining contract term

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		153,096
Revisions		—
Properties sold		—
Plugging and abandonment activity		(21,068	)
Ending March 31, 2010 liability	$	9,834,681

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 $105 million borrowing base, based on our current proved crude oil and natural gas reserves, and matures on May 8, 2011. 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 May 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 next borrowing base redetermination under our Senior Credit Agreement is scheduled for November 1, 2010. As of March 31, 2010, we had an outstanding loan balance of $39.0 million under our Senior Credit Agreement.

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 majority stockholder. The Second Lien Credit Agreement provided for a term loan made to us in a single draw in an aggregate principal amount of $150.0 million and matures on May 8, 2012. As of March 31, 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 borrowings mature and renew.

The Credit Agreements include usual and customary affirmative covenants for credit facilities of the respective types and sizes, as well as customary negative covenants, including, among others, limitations on liens, hedging, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, certain leases and investments outside of the ordinary course of business, as well as events of default. The Credit Agreements also contain certain financial and proved reserve covenants. See Note 10 of our 2009 Annual Report on Form 10-K for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements. At March 31, 2010, we were in compliance with the aforementioned covenants.

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 and the escrow was released 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 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 March 31, 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 first quarter 2010, 175,302 shares of restricted Common Stock, previously issued pursuant to the Long-Term Equity Incentive Plan, 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 1,356 unvested shares of restricted common stock forfeited due to employee terminations. We did not have any stock option exercises in the first quarter 2010.

8. INCOME TAXES

Income tax expense for the first quarter 2010 was $0.3 million, compared to $2.9 million for the first quarter 2009. The quarterly income tax expense is based on our estimate of the effective tax rate expected to be applicable for the full year. Negatively impacting the effective tax rate for the first quarter 2010 was the recording of an additional $0.1 million in deferred tax expense related to an overall effective tax rate adjustment to our deferred tax assets and liabilities.

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 on our 2009 Annual Report on Form 10-K. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties.

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

·	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 growth potential in 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 March 31, 2010 Compared to Three Months Ended March 31, 2009

Revenues

	Three months ended March 31,
	2010		2009		Change			Percent Change
Product revenues:	(in millions, except percentages)
Natural gas sales	$	14.5	$	20.7	$	(6.2	)		-30.0	%
Crude oil sales		4.7		7.4		(2.7	)		-36.5	%
Natural gas liquids sales		3.3		2.5		0.8			32.0	%
Product revenues	$	22.5	$	30.6	$	(8.1	)		-26.5	%

Natural Gas, Crude Oil and Natural Gas Liquids Sales. 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 $22.5 million for the first quarter 2010 compared to $30.6 million for the first quarter 2009 due to an approximate 34% decrease in production, offset by an approximate 12% increase in realized commodity prices.

	Three months ended March 31,
	2010	2009	Change		Percent Change
Sales volumes:
Natural gas (Mcf)	2,080,168	3,076,114	(995,946	)	-32.4%
Crude oil (Bbl)	56,304	96,305	(40,001	)	-41.5%
Natural gas liquids (Bbl)	71,230	110,242	(39,012	)	-35.4%
Natural gas equivalents (Mcfe)	2,845,372	4,315,396	(1,470,024	)	-34.1%

Quarterly production was approximately 2.8 Bcfe for the first quarter 2010 compared to approximately 4.3 Bcfe for the first quarter 2009. On a daily basis, we produced an average of 31,615 Mcfe for the 2010 quarter compared to an average of 47,949 Mcfe for the 2009 quarter. Production volumes decreased approximately 1.5 bcfe primarily due to natural field decline, limited production enhancing capital expenditure activity in 2009 and the first quarter 2010 and the sale of our Southwest Louisiana properties in December 2009. The Southwest Louisiana properties contributed approximately 3,300 Mcfe per day of production during the first quarter 2009.

	Three months ended March 31,
	2010		2009		Change		Percent Change
Average sales prices (before hedging):
Natural gas (Mcf)	$	5.24	$	4.75	$	0.49		10.3	%
Crude oil (Bbl)		76.64		39.30		37.34		95.0	%
Natural gas liquids (Bbl)		46.25		22.51		23.74		105.5	%
Natural gas equivalents (Mcfe)		6.50		4.84		1.66		34.3	%

	Three months ended March 31,
	2010		2009		Change		Percent Change
Average sales prices (after hedging):
Natural gas (Mcf)	$	6.96	$	6.71	$	0.25		3.7	%
Crude oil (Bbl)		83.77		77.18		6.59		8.5	%
Natural gas liquids (Bbl)		46.25		22.51		23.73		105.4	%
Natural gas equivalents (Mcfe)		7.90		7.08		0.82		11.6	%

Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $0.4 million on our crude oil hedges and $3.6 million on our natural gas hedges in the first quarter 2010, compared to realized gains of $3.6 million for crude oil hedges and $6.0 million for natural gas hedges in the first quarter 2009.

Costs and Expenses

	Three months ended March 31,
	2010		2009		Change			Percent Change
Certain Operating Expenses:	(in millions, except percentages)
Lease operating expenses	$	3.9	$	5.4	$	(1.5	)		-27.8	%
Production and ad valorem taxes		1.7		2.5		(0.8	)		-32.0	%
Exploration expenses		0.5		0.7		(0.2	)		-28.6	%
General and administrative(1)		4.4		4.2		0.2			4.8	%
Operating expenses (cash)		10.5		12.8		(2.3	)		-18.0	%
Depreciation, depletion & amortization		10.4		13.9		(3.5	)		-25.2	%
Share-based compensation(1)		0.5		1.0		(0.5	)		-50.0	%
Certain operating expenses	$	21.4	$	27.7	$	(6.3	)		-22.7	%

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

	Three months ended March 31,
	2010		2009		Change			Percent Change
Selected Costs ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	1.37	$	1.27	$	0.10			7.9	%
Production and ad valorem taxes		0.60		0.57		0.03			5.3	%
Exploration expenses		0.17		0.17		—			0.0	%
General and administrative(1)		1.55		0.99		0.56			56.6	%
Operating expenses (cash)		3.69		3.00		0.69			23.0	%
Depreciation, depletion & amortization		3.66		3.21		0.45			14.0	%
Share-based compensation(1)		0.18		0.22		(0.04	)		-18.2	%
Selected costs	$	7.53	$	6.43	$	1.10			17.1	%

(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 quarter 2010 were $3.9 million, compared to $5.4 million in the first quarter 2009, a decrease resulting from the implementation of cost reduction initiatives during 2009 and continuing in 2010 and the sale of the Southwest Louisiana properties in December 2009.

Production and Ad Valorem Tax Expenses. Production and ad valorem tax expenses for the first quarter 2010 were $1.7 million, compared to $2.5 million for the first quarter 2009, due to lower production in the first quarter 2010 and the sale of the Southwest Louisiana properties, offset in part by higher sales prices.

Exploration Expenses. Exploration expenses were $0.5 million in the first quarter 2010, compared to $0.7 million for the first quarter 2009. The decrease in exploration expenses was primarily due to the reduction in geological and geophysical costs in the first quarter 2010.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the first quarter 2010 was $10.4 million compared to $13.9 million for the first 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 $4.9 million for the first quarter 2010 compared to $5.2 million for the first quarter 2009. Included in G&A expense is a non-cash stock expense of $0.5 million ($0.18 per Mcfe) and $1.0 million ($0.22 per Mcfe) for the first quarters 2010 and 2009, respectively, which is the primary reason for the overall decrease.

Interest Expense. Interest expense was $5.4 million for the first quarter 2010, compared to $4.4 million for the first quarter 2009. Total interest expense increased primarily due to the increase in the overall rate on our second lien credit agreement in May 2009. No interest expense was capitalized for the first quarters of either 2010 or 2009.

Other Financing Costs. Other financing costs were $0.7 million for the first quarter 2010, compared to $0.3 million for the first quarter 2009. These expenses consist primarily of the amortization of capitalized costs associated with our credit facilities and commitment fees related to the undrawn availability under our revolving credit agreement.

Unrealized Gain on Derivative Instruments. The non-cash unrealized gain on derivative instruments for the first quarter 2010 was $5.4 million, compared to $9.6 million for the first quarter 2009. The unrealized gain or loss is the change in the mark-to-market exposure under our commodity price hedging contracts and our interest rate swaps. 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 income before taxes was $0.6 million for the first quarter 2010, compared to $7.9 million in the first quarter 2009. After adjusting for permanent tax differences, we recorded income tax expense of $0.3 million for the first quarter 2010, compared to $2.9 million for the first quarter 2009.

Dividends on Preferred Stock. Dividends on preferred stock were zero for the first quarter 2010, compared with $1.1 million in the first 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 first quarter 2009 included approximately $1.1 million on the Series G Preferred Stock and $4,375 on the Series H Preferred Stock.

Liquidity and Capital Resources

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our 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 and/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, and our liquidity may be adversely affected if commodity prices were to decline.

Our working capital deficit was $6.9 million as of March 31, 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 March 31, 2010 and December 31, 2009.

	March 31, 2010			December 31, 2009			Change
Current assets
Accounts receivable, net	$	12,997,584		$	14,773,246		$	(1,775,662	)
Prepaid expenses		65,444			—			65,444
Derivative instruments		14,190,831			9,937,697			4,253,134
Total current assets		27,253,859			24,710,943			2,542,916

Current liabilities
Current portion of long-term debt		9,009			19,014			(10,005	)
Accounts payable and accrued liabilities		27,964,171			29,115,653			(1,151,482	)
Income tax payable		282,613			250,931			31,682
Asset retirement obligations		332,832			330,287			2,545
Derivative instruments		1,596,260			872,849			723,411
Deferred tax liability, net		3,980,682			2,897,300			1,083,382
Total current liabilities		34,165,567			33,486,034			679,533

Working capital (deficit)	$	(6,911,708	)	$	(8,775,091	)	$	1,863,383

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 three months ended March 31, 2010 and 2009, respectively.

		Three months ended March 31,
		2010			2009
Financial Measures		(in millions)
Net cash provided by (used in) operating activities	$	7.4		$	(18.9	)
Net cash used in investing activities		(5.3	)		(10.9	)
Net cash (used in) provided by financing activities		(2.1	)		29.8
Cash and cash equivalents		—			—

Net cash provided by operating activities was $7.4 million for the first quarter 2010, compared to net cash used in operating activities of $18.9 million for the first quarter 2009. During the first quarter 2010, the net cash provided by operating activities, before changes in working capital, decreased to $6.8 million, from $12.7 million for the first quarter 2009, primarily due to the decrease in production from natural field decline, limited production-enhancing capital expenditure activity and the sale of our Southwest Louisiana properties.

Net cash used in investing activities, which consists primarily of capital expenditures on oil and gas drilling projects and leasehold acquisitions, was $5.3 million for the first quarter 2010, compared to $10.9 million for the first quarter 2009.

Net cash used in financing activities, which consists primarily of net borrowings/repayments on our revolving credit agreement, was $2.1 million for the first quarter 2010, compared to net cash provided by financing activities of $29.8 million for the first quarter 2009. In the first quarter 2010, we repaid a net $2.1 million of outstanding indebtedness under our revolving credit agreement, while we borrowed a net $29.8 million in 2009 to satisfy the fourth quarter 2008 balance in current liabilities related to the active drilling program in 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 $105 million borrowing base, based on our current proved crude oil and natural gas reserves, and matures on May 8, 2011. 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 May 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 next borrowing base redetermination under our Senior Credit Agreement is scheduled for November 1, 2010. The revolving credit agreement has a term of four years, and all principal amounts, together with all accrued and unpaid interest, will be due and payable in full on May 8, 2011. 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 will 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.

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 us and Wells Fargo Bank, which was subsequently repaid and the escrow was released 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 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 March 31, 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 March 31, 2010, we had 5.4 Bcfe and 3.9 Bcfe of equivalent production hedged representing 4.3 Bcf and 3.2 Bcf of natural gas hedges in place and 188 MBbl and 124 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 May 6, 2010, we had $36.0 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 $69.0 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 much 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 execute on our growth strategy and 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, and we continuously evaluate our financing opportunities. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors. Our ability to 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, although the 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 4T. CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

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 first 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
January 1-31, 2010	—	—	—	(1)
February 1-28, 2010	25,427	$3.46	25,427	(1)
March 1-31, 2010	—	—	—	(1)
Total	25,427		—

(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 Elimination (incorporated by reference to exhibit 3.1 to Crimson Exploration Inc.'s Current Report on Form 8-K filed March 22, 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.

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:	May 11, 2010	By:	/s/ Allan D. Keel
			Allan D. Keel
			President and Chief Executive Officer

Date:	May 11, 2010	By:	/s/ E. Joseph Grady
			E. Joseph Grady
			Senior Vice President and Chief Financial Officer