10-Q

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, 2013

OR

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____ to ____

Commission file number 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 twelve 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 twelve months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer x	Non-accelerated filer o	Smaller reporting company o
		(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 2, 2013, there were 46,623,161 shares outstanding of the registrant’s Common Stock, par value $0.001.

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED MARCH 31, 2013

Table of Contents
	Page
Part I:Financial Information
Item 1.Financial Statements
Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	3
Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	4
Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2013	5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	6
Notes to the Consolidated Financial Statements	7
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.Quantitative and Qualitative Disclosures about Market Risk	23
Item 4.Controls and Procedures	24
Part II:Other Information
Item 1.Legal Proceedings	25
Item 1A.Risk Factors	25
Item 2.Unregistered Sales of Equity Securities and Use Of Proceeds	25
Item 3.Defaults Upon Senior Securities	25
Item 4.Mine Safety Disclosures	25
Item 5.Other Information	25
Item 6.Exhibits	26
Signatures	28

2

PART I.     FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	March 31,			December 31,
	2013			2012
	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Accounts receivable, net of allowance of $568,429 and $525,556, respectively		12,215,741			11,726,078
Prepaid expenses		811,937			844,495
Derivative instruments		23,203			1,892,744
Deferred tax asset, net		10,854,534			10,361,157
Total current assets		23,905,415			24,824,474
PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method of accounting)		750,422,487			740,070,145
Other property and equipment		3,036,873			3,061,635
Accumulated depreciation, depletion and amortization		(454,996,621	)		(442,304,300	)
Total property and equipment, net		298,462,739			300,827,480
NONCURRENT ASSETS
Deposits		34,743			34,743
Debt issuance cost		960,325			1,056,272
Derivative instruments		211,210			67,261
Deferred tax asset, net		43,801,070			41,810,159
Total noncurrent assets		45,007,348			42,968,435
TOTAL ASSETS	$	367,375,502		$	368,620,389
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	31,939,209		$	31,127,671
Accrued liabilities		9,616,158			6,680,843
Asset retirement obligations		738,428			876,774
Derivative instruments		136,373			—
Total current liabilities		42,430,168			38,685,288
NONCURRENT LIABILITIES
Long-term debt		238,589,148			239,368,865
Asset retirement obligations		10,236,482			10,152,432
Derivative instruments		21,026			—
Other noncurrent liabilities		559,349			571,687
Total noncurrent liabilities		249,406,005			250,092,984
Total liabilities		291,836,173			288,778,272
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Common stock (par value $0.001; 200,000,000 shares authorized; 46,874,484 and 46,259,009 shares issued and 46,606,703 and 46,063,822 shares outstanding as of March 31, 2013 and December 31, 2012, respectively)		46,874			46,259
Additional paid-in capital		246,669,871			246,007,941
Retained deficit		(170,074,924	)		(165,343,525	)
Treasury stock (at cost, 267,781 and 195,187 shares as of March 31, 2013 and December 31, 2012, respectively)		(1,102,492	)		(868,558	)
Total stockholders’ equity		75,539,329			79,842,117
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	367,375,502		$	368,620,389

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

3

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2013			2012
OPERATING REVENUES
Crude oil sales	$	16,093,396		$	16,892,614
Natural gas sales		6,002,675			7,069,114
Natural gas liquids sales		1,998,863			2,724,851
Total operating revenues		24,094,934			26,686,579
OPERATING EXPENSES
Lease operating expenses		3,262,127			4,637,385
Production and ad valorem taxes		1,688,742			1,408,741
Exploration expenses		117,481			300,696
Depreciation, depletion and amortization		12,839,720			14,462,062
Impairment of oil and gas properties		817,738			676,474
General and administrative		4,314,334			4,771,457
Gain on sale of assets		(6,384	)		(8,900	)
Total operating expenses		23,033,758			26,247,915
INCOME FROM OPERATIONS		1,061,176			438,664
OTHER INCOME (EXPENSE)
Interest expense		(6,283,737	)		(6,245,182	)
Other income (expense) and financing costs		(119,402	)		(242,743	)
Unrealized loss on derivative instruments		(1,882,990	)		(525,633	)
Total other income (expense)		(8,286,129	)		(7,013,558	)
LOSS BEFORE INCOME TAXES		(7,224,953	)		(6,574,894	)
Income tax benefit		2,493,554			2,175,809
NET LOSS	$	(4,731,399	)	$	(4,399,085	)
NET LOSS PER SHARE
Basic	$	(0.11	)	$	(0.10	)
Diluted	$	(0.11	)	$	(0.10	)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		44,389,522			43,976,950
Diluted		44,389,522			43,976,950

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

4

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2013

(UNAUDITED)

	NUMBER OF SHARES OF					ADDITIONAL								TOTAL
	COMMON STOCK			COMMON STOCK		PAID-IN CAPITAL		RETAINED DEFICIT			TREASURY STOCK			STOCKHOLDERS’ EQUITY
BALANCE, DECEMBER 31, 2012		46,063,822		$	46,259	$	246,007,941	$	(165,343,525	)	$	(868,558	)	$	79,842,117
Current period net loss		—			—		—		(4,731,399	)		—			(4,731,399	)
Share-based compensation		615,475			615		661,930		—			—			662,545
Treasury stock		(72,594	)		—		—		—			(233,934	)		(233,934	)
BALANCE, MARCH 31, 2013		46,606,703		$	46,874	$	246,669,871	$	(170,074,924	)	$	(1,102,492	)	$	75,539,329

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

5

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	For The Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(4,731,399	)	$	(4,399,085	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		12,839,720			14,462,062
Asset retirement obligations		(179,601	)		121,042
Stock compensation expense		662,545			532,311
Amortization of financing costs and discounts		418,391			385,585
Deferred income taxes		(2,484,288	)		(2,175,809	)
Impairment of unproved oil and gas properties		817,738			676,474
Gain on sale of assets		(6,384	)		(8,900	)
Unrealized loss on derivative instruments		1,882,990			525,633
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, net		(489,663	)		175,929
Decrease (increase) in prepaid expenses		32,558			(235,151	)
Increase (decrease) in accounts payable and accrued liabilities		3,734,515			(9,521,713	)
Net cash provided by operating activities		12,497,122			538,378
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(11,167,412	)		(32,675,599	)
Sale of assets		6,384			8,900
Net cash used in investing activities		(11,161,028	)		(32,666,699	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt		(37,215,089	)		(43,293,956	)
Proceeds from debt		36,112,929			75,503,103
Proceeds from issuance of common stock		—			6,952
Purchase of treasury stock		(233,934	)		(87,778	)
Net cash provided by (used in) financing activities		(1,336,094	)		32,128,321
INCREASE IN CASH AND CASH EQUIVALENTS		—			—
CASH AND CASH EQUIVALENTS,
Beginning of period		—			—
CASH AND CASH EQUIVALENTS,
End of period	$	—		$	—
Cash paid for interest	$	5,870,267		$	5,833,170
Cash paid for income taxes	$	—		$	—

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

6

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 exploitation, exploration, development and acquisition of natural gas and crude oil properties.  Our operating areas include the onshore U.S. Gulf Coast, South Texas, East Texas, Southeast Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have expanded our strategic focus to include longer reserve life resource plays that we believe provide significant long-term growth potential in multiple formations.  We are also focusing on further developing our oil/liquid weighted assets.

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 March 31, 2013 (unaudited) and December 31, 2012 and for the three months ended March 31, 2013 (unaudited) and 2012 (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 months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

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, 2012.

The accompanying consolidated financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Crimson Exploration Operating, Inc. and LTW Pipeline Co.  All material intercompany transactions and balances are eliminated upon consolidation.  Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.

New Accounting Standards Adopted in 2013

In December 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-11 “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” ASU 2011-11.  This accounting update requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  This accounting update was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.

In January 2013, the FASB issued ASU No. 2013-01— “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”.  The main objective in developing this update is to address implementation issues about the scope of ASU No. 2011-11.  This ASU clarifies the scope of the offsetting disclosures and addresses any unintended consequences.  The scope of Update

7

2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement.  This ASU is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.  An entity should provide the required disclosures retrospectively for all comparative periods presented.  This ASU was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.

3.           USE OF ESTIMATES

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) crude oil, natural gas and natural gas liquids revenues and reserves; (2) depreciation, depletion and amortization; (3) impairment of oil and gas properties; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations; (7) valuation of derivative instruments and (8) valuation allowances associated with income taxes and accounts receivables.  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.

4.           FAIR VALUE MEASUREMENTS

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 and costless collars.  The fair value measurement of our unrealized commodity price instruments were obtained from financial institutions and adjusted for non-performance risk, and were evaluated for accuracy using our hedge agreements and future commodity curves.  Differences between management’s calculation and that of the financial institutions were evaluated for reasonableness.  See Note 5 — “Derivative Instruments” for further information.

Impairments.  We test 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.  Additionally, we may use appropriate market data to determine fair value.  Because these significant fair value inputs are typically not observable, we classify impairments of long-lived assets as a Level 3 fair value measure.  See Note 6 – “Oil and Gas Properties” for further information.

8

Asset Retirement Obligations.  The initial measurement of asset retirement obligations ("AROs") at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties.  The factors used to determine fair value include, but are not limited to, plugging costs and reserve lives.  See Note 7 – “Asset Retirement Obligations” for further information.

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 8 — “Debt” for further information.

Accounting guidance has 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 have been no transfers between Level 1, Level 2 or Level 3 during this quarter.

Fair value information related to our derivative instruments measured at fair value on a recurring basis was as follows at March 31, 2013:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Commodity price contracts (assets)	$	234,413		$	—	$	234,413		$	—
Commodity price contracts (liabilities)		(157,399	)		—		(157,399	)		—
Total	$	77,014		$	—	$	77,014		$	—

At March 31, 2013, we did not measure assets or liabilities at fair value on a non-recurring basis.

Fair value information for related to our derivative instruments measured at fair value was as follows at December 31, 2012:

	Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts	$	1,960,005	$	—	$	1,960,005	$	—

5.           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 $77,014 and $2.0 million at March 31, 2013 and December 31, 2012, respectively.  As a result of these agreements, we recorded non-cash unrealized losses for unsettled contracts of $1.9 million and $0.5 million for the three months ended March 31, 2013 and 2012, respectively.  The estimated change in fair value of the derivatives is reported in other income (expense) as unrealized gain (loss) on derivative instruments.  The realized gain (loss) on derivative instruments is included in crude oil, natural gas and natural gas liquids sales for our commodity price hedges.

9

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our natural gas and crude oil production, to reduce our sensitivity to volatile commodity prices, and with respect to portions of our debt, to reduce our sensitivity to volatile interest rates.  None of our derivative instruments are designated as cash flow or fair value 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 crude oil, natural gas 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 provide only partial protection against declines in commodity prices.  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 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.  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 senior secured revolving credit agreement and various hedge contracts.  See Note 4 — “Fair Value Measurements” for further information.

The following derivative contracts were in place at March 31, 2013:

Crude Oil			Volume/Month		Price/Unit		Fair Value
Apr 2013-Dec 2013		Swap	14,000 Bbls	$	101.25 (1)	$	559,262
Apr 2013-Dec 2013		Swap	9,000 Bbls		109.13 (2)		90,989
Apr 2013-Jun 2013		Swap	6,000 Bbls		108.35 (2)		(21,678	)
Apr 2013-Dec 2013		Swap	6,000 Bbls		107.10 (2)		(48,805	)
Apr 2013-Jun 2013		Swap	7,000 Bbls		104.80 (2)		(99,799	)
Jul 2013-Sep 2013		Swap	6,000 Bbls		103.47 (2)		(82,032	)
Oct 2013-Dec 2013		Swap	3,000 Bbls		102.30 (2)		(36,529	)
Jan 2014-Dec 2014		Swap	7,500 Bbls		102.10 (2)		(79,460	)
Jan 2014-Jun 2014		Swap	2,000 Bbls		108.07 (2)		45,665
Jan 2014-Dec 2014		Swap	6,000 Bbls		106.40 (2)		236,162
Natural Gas
Apr 2013-Jun 2013		Collar	50,000 Mmbtu		Put $3.75-$4.00 Call (3)		(12,110	)
Apr 2013-Dec 2013		Collar	75,000 Mmbtu		Put $3.00-$4.25 Call (3)		(127,094	)
Apr 2013-Dec 2013		Collar	75,000 Mmbtu		Put $3.25-$4.00 Call (3)		(185,288	)
Apr 2013-Dec 2013		Collar	35,000 Mmbtu		Put $3.75-$4.21 Call (3)		(33,805	)
Apr 2013-Dec 2013		Swap	70,000 Mmbtu		$4.02 (3)		(53,207	)
Apr 2013-Dec 2014		Collar	42,500 Mmbtu		Put $3.75-$4.60 Call (3)		(42,669	)
Apr 2013-Dec 2014		Collar	42,500 Mmbtu		Put $3.50-$5.00 Call (3)		(32,588	)
	Total net fair value of derivative instruments					$	77,014

(1)   Commodity derivative based on West Texas Intermediate crude oil

(2)   Commodity derivative based on Brent crude oil

(3)   Commodity derivatives based on Henry Hub NYMEX natural gas prices

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The following table details the effect of derivative contracts on the Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012, respectively:

		Amount of Gain or (Loss) Recognized in Income
	Location of Gain or (Loss)	Three months ended March 31,
Contract Type	Recognized in Income	2013			2012
Crude oil contracts	Crude oil sales	$	(207,269	)	$	(161,597	)
Natural gas contracts	Natural gas sales		144,325			1,535,460
	Realized (loss) gain	$	(62,944	)	$	1,373,863
Crude oil contracts	Unrealized (loss) gain on derivative instruments	$	(809,413	)	$	(1,532,130	)
Natural gas contracts	Unrealized (loss) gain on derivative instruments		(1,073,577	)		1,006,497
	Unrealized loss	$	(1,882,990	)	$	(525,633	)

Balance Sheet Presentation

Our derivatives are presented on a net basis in derivative instruments on the Consolidated Balance Sheets.  The following summarizes the fair value of derivatives outstanding on a gross and net basis:

	March 31, 2013
	Gross		Netting (1)			Total
Assets:
Commodity derivatives	$	932,078	$	(697,665	)	$	234,413
Liabilities:
Commodity derivatives		855,064		(697,665	)		157,399

	December 31, 2012
	Gross		Netting (1)			Total
Assets:
Commodity derivatives	$	2,206,705	$	(246,700	)	$	1,960,005
Liabilities:
Commodity derivatives		246,700		(246,700	)		—

(1)   Represents counterparty netting under agreements governing such derivatives

6.           OIL AND GAS PROPERTIES

The following table sets forth the composition of impairment and abandonment expenses:

	Three months ended March 31,
	2013		2012
Impairment and abandonment of unproved properties	$	817,738	$	676,474

2013 Asset Impairments. Non-cash impairments of unproved properties include $0.8 million related to individually insignificant acreage.  There were no impairments or abandonments of proved properties.

2012 Asset Impairments. Non-cash impairments of unproved properties include $0.7 million related to individually insignificant acreage.  There were no impairments or abandonments of proved properties.

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7.           ASSET RETIREMENT OBLIGATIONS

We estimate the fair values of 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.  The following table sets forth the composition of asset retirement obligations rollforward:

Beginning January 1, 2013 liability	$	11,029,206
Accretion expense		122,638
Liabilities incurred		2,667
Liabilities settled		(179,601	)
Revisions		—
Ending March 31, 2013 liability	$	10,974,910

8.           DEBT

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lender parties thereto (the “Senior Credit Agreement”) that matures on May 31, 2015.  The borrowing base, currently set at $100 million, is based on our current proved crude oil and natural gas reserves, and is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates.  The next borrowing base redetermination under our Senior Credit Agreement is scheduled for May 1, 2013.  We have started discussions with our agent bank on the scheduled redetermination, but may not finalize these discussions prior to filing this quarterly report on Form 10-Q with the SEC.  As part of this process, our agent bank has recommended affirmation of the $100 million borrowing base to the lender group.  Based on our discussions, we are optimistic that the borrowing base will be reaffirmed at $100 million.  As of March 31, 2013, we had $68.1 million outstanding, with availability of $31.9 million, under our Senior Credit Agreement.

We also maintain a second lien credit agreement dated December 27, 2010 with Barclays Bank Plc, as agent, and the lender parties thereto, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”).  The Second Lien Credit Agreement provides for a term loan, which was made to us in a single draw in an aggregate principal amount of $175.0 million that matures on December 27, 2015.  As of March 31, 2013, we had a principal amount of $175.0 million outstanding, with a discount of $4.4 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $170.6 million.  The Senior Credit Agreement and the Second Lien Credit Agreement (the “Credit Agreements”) are secured by liens on substantially all of our assets, as well as security interests in the stock of our subsidiaries.  The liens securing the Second Lien Credit Agreement are junior to those securing the Senior Credit Agreement.  Interest is payable on the Credit Agreements as interim borrowings mature.

The Credit Agreements include usual and customary affirmative and negative covenants for credit facilities of their respective types and sizes, 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 covenants.  See Note 9 of our Annual Report on Form 10-K for the year ended December 31, 2012 for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements.  At March 31, 2013, we were in compliance with the covenants.

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9.           STOCKHOLDERS’ EQUITY

In the three months ended March 31, 2013, 417,252 shares of restricted Common Stock vested, of which 72,594 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, with the remaining shares being distributed to the employees and directors.  Discretionary grants of 642,000 shares of unvested restricted Common Stock were made to our employees during the three months ended March 31, 2013 as incentive-based equity compensation under the 2005 Stock Incentive Plan.

In the three months ended March 31, 2012, 193,228 shares of restricted Common Stock vested, of which 27,436 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, with the remaining shares being distributed to the employees and directors.  During the three months we also issued 2,897 shares pursuant to stock option exercises.  Discretionary grants of 948,000 shares of unvested restricted Common Stock were made to our employees during the three months ended March 31, 2013 as incentive-based equity compensation under the 2005 Stock Incentive Plan.  We also granted 4,000 shares of restricted Common Stock during such period to new employees as part of their compensation package.

10.         INCOME TAXES

Income tax benefit for the three months ended March 31, 2013 was $2.5 million compared to income tax benefit of $2.2 million for the three months ended March 31, 2012.  The quarterly income tax provision is based on our estimate of the effective tax rate expected to be applicable for the full year.  Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences net of a tax-adjusted $13.3 million valuation allowance.  The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

11.         RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Not Yet Adopted

In February 2013, the FASB issued ASU No. 2013-04— “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”.  The objective of this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP.  Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings.  U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice.  The accounting update is effective for interim and annual periods beginning after December 15, 2013.  We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

Further, we are closely monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board.  There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement

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presentation.  Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact that these standards will have, if any, on our financial position, results of operations or cash flows.

12.         SUBSEQUENT EVENT

On April 30, 2013, Crimson Exploration Inc. ("Crimson") and Contango Oil & Gas Company ("Contango") jointly announced that they have signed a merger agreement for an all-stock transaction pursuant to which Crimson would become a wholly owned subsidiary of Contango.  Upon consummation of the merger, each share of Crimson stock will be converted into 0.08288 shares of Contango stock resulting in Crimson stockholders owning 20.3% of the post-merger Contango.

Following the merger, the combined company will be a premier Houston-based independent oil and gas company with a balanced offshore Gulf of Mexico ("GoM") and onshore Texas production profile.  The combined company will offer a deep inventory of high-impact GoM prospects complemented by Crimson's onshore oil and natural gas liquids-focused, lower-risk unconventional resource positions in several prolific plays.  Pro forma for the merger, the combined companies’ net daily production for the quarter ending March 31, 2013 would be approximately 101 Mmcfe (31% oil and natural gas liquids) and total proved reserves are estimated to be approximately 312 Bcfe (31% oil and natural gas liquids), based on SEC pricing at March 31, 2013.  Pro forma PV-10 of the estimated proved reserves of the combined company would be approximately $932.5 million.  The enhanced size and scale of the combined company and its conservatively capitalized balance sheet will position it to implement an accelerated oil and natural gas liquids-focused drilling program.

Crimson stockholders will receive per-share consideration consisting of 0.08288 shares of Contango common stock for each Crimson share.  Based on Contango’s closing stock price on April 29, 2013, this transaction represents an implied price per share for Crimson of $3.19, a premium of approximately 8% percent to the most recent closing price of Crimson common stock.  Aggregate consideration in the transaction is approximately $390 million based on the assumed issuance of approximately 3.9 million shares of Contango common stock and the assumption by Contango of approximately $244 million of long-term debt of Crimson.

The merger is subject to the approval of the stockholders of both Contango and Crimson as well as customary closing conditions.  The Estate of Kenneth R. Peak, Brad Juneau, members of the management teams of Contango and Crimson, and affiliates of Oaktree Capital Management (Crimson’s largest stockholder) have all entered into voting agreements in support of the transaction.  The merger is expected to close in the third quarter of 2013.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Note Regarding 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 (this “Report”)and with the consolidated financial statements, notes and management’s discussion and analysis reported on our Annual Report on Form 10-K for the year ended December 31, 2012. Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, some of which are beyond our control.

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 risks and uncertainties could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us on our behalf.  Risks and uncertainties that could cause or contribute to such differences include, without limitation, those factors discussed in “ITEM 1A. Risk Factors” contained in our Annual Report filed on Form 10-K for the year ended December 31, 2012, as filed with the Securities and Exchange Commission.

We caution you that the forward-looking statements contained in this Report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur.  All forward-looking statements speak only as of the respective dates thereof.

We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law.  These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We are an independent energy company engaged in the exploitation, exploration, development and acquisition of crude oil and natural gas properties.  Our operating areas include the onshore U.S. Gulf Coast, Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have shifted our strategic focus to include longer reserve life resource

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plays in Southeast Texas (the Woodbine oil play) and South Texas (the Eagle Ford Shale and Buda oil plays).  We believe these plays provide significant long-term growth potential from multiple formations.  Additionally, we have producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may be prospective in the Niobrara Shale oil play.  Until we see improvement in natural gas prices, we will focus our drilling activity predominantly on further developing our oil and liquids-rich assets.

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, 2013 Compared to Three Months Ended March 31, 2012

Revenues

	Three months ended March 31,
	2013		2012		Change			Percent Change
Product revenues:	(in millions, except percentages)
Crude oil sales	$	16.1	$	16.9	$	(0.8	)		-4.7	%
Natural gas sales		6.0		7.1		(1.1	)		-15.5	%
Natural gas liquids sales		2.0		2.7		(0.7	)		-25.9	%
Product revenues	$	24.1	$	26.7	$	(2.6	)		-9.7	%

Crude Oil, Natural Gas and Natural Gas Liquids Sales.  Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our commodity price hedging instruments, were $24.1 million for the first quarter of 2013 compared to $26.7 million for the first quarter of 2012.  The decrease results from a 7.4% decrease in equivalent production volumes and a 2.5% decrease in realized equivalent prices.  The decrease in equivalent production volumes was primarily from an approximate 16% decrease in natural gas production while the decrease in equivalent realized prices was primarily from a 44% decrease in natural gas liquids realizations.

Production

	Three months ended March 31,
	2013		2012		Change			Percent Change
Sales volumes:
Crude oil (Bbl)		153,042		158,633		(5,591	)		-3.5%
Natural gas (Mcf)		1,824,552		2,164,125		(339,573	)		-15.7%
Natural gas liquids (Bbl)		81,723		62,536		19,187			30.7%
Natural gas equivalents (Mcfe) (1)		3,233,142		3,491,139		(257,997	)		-7.4%
% Crude oil and natural gas liquids		43.6%		38.0%					5.6%

(1)   Equivalent volumes are based upon one barrel of crude oil or natural gas liquids equivalent to 6 Mcf of natural gas based on an approximation of equivalent energy content but are not equivalent in value

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Quarterly production was approximately 3.2 Bcfe for the first quarter of 2013 compared to approximately 3.5 Bcfe for the first quarter of 2012.  On a daily basis, we produced an average of 35,924 Mcfe for the first quarter of 2013 compared to an average of 38,364 Mcfe for the first quarter of 2012, a decrease primarily due to our continued transition to drilling higher value, lower rate (on an equivalent basis) oil and liquids-rich projects in the Eagle Ford and Woodbine formations, compared to the higher rate dry natural gas wells previously pursued in the Haynesville/Mid-Bossier formations in East Texas.

Average Sales Prices

	Three months ended March 31,
	2013		2012		Change			Percent Change
Average sales prices (before hedging):
Crude oil (Bbl)	$	106.51	$	107.51	$	(1.00	)		-0.9%
Natural gas (Mcf)		3.21		2.56		0.65			25.4%
Natural gas liquids (Bbl)		24.46		43.57		(19.11	)		-43.9%
Natural gas equivalents (Mcfe)		7.47		7.25		0.22			3.0%

	Three months ended March 31,
	2013		2012		Change			Percent Change
Average sales prices (after hedging):
Crude oil (Bbl)	$	105.16	$	106.49	$	(1.33	)		-1.2%
Natural gas (Mcf)		3.29		3.27		0.02			0.6%
Natural gas liquids (Bbl)		24.46		43.57		(19.11	)		-43.9%
Natural gas equivalents (Mcfe)		7.45		7.64		(0.19	)		-2.5%

Crude oil, natural gas and natural gas liquids prices are reported net of the realized effects of our hedging agreements.  We realized gains of $0.1 million on natural gas hedges and losses of $0.2 million on crude oil hedges in the first quarter of 2013, compared to realized gains of $1.5 million for natural gas hedges and losses of $0.2 million for crude oil hedges in the first quarter of 2012.  The decrease in realized hedging results for 2013 was due to the expiration in 2012 of more favorable natural gas hedges put in place during a higher commodity price environment in January 2011.

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Costs and Expenses

	Three months ended March 31,
	2013		2012		Change			Percent Change
Selected Operating Expenses:	(in millions, except percentages)
Lease operating expenses	$	3.3	$	4.6	$	(1.3	)		-28.3%
Production and ad valorem taxes		1.7		1.4		0.3			21.4%
Exploration expenses		0.1		0.3		(0.2	)		-66.7%
General and administrative (1)		3.7		4.2		(0.5	)		-11.9%
Cash operating expenses		8.8		10.5		(1.7	)		-16.2%
Depreciation, depletion & amortization		12.8		14.5		(1.7	)		-11.7%
Share-based compensation (1)		0.7		0.5		0.2			40.0%
Selected operating expenses (2)	$	22.3	$	25.5	$	(3.2	)		-12.5%

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

(3)   Exclusive of impairments, abandonments and sales of assets

	Three months ended March 31,
	2013		2012		Change			Percent Change
Selected Operating Expenses ($ per Mcfe):
Lease operating expenses	$	1.01	$	1.33	$	(0.32	)		-24.1%
Production and ad valorem taxes		0.52		0.40		0.12			30.0%
Exploration expenses		0.04		0.09		(0.05	)		-55.6%
General and administrative (1)		1.13		1.21		(0.08	)		-6.6%
Cash operating expenses		2.70		3.03		(0.33	)		-10.9%
Depreciation, depletion & amortization		3.97		4.14		(0.17	)		-4.1%
Share-based compensation (1)		0.20		0.15		0.05			33.3%
Selected operating expenses ($ per Mcfe) (2)	$	6.87	$	7.32	$	(0.45	)		-6.1%

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

(2)   Exclusive of impairments, abandonments and sales of assets

Lease Operating Expenses.  Lease operating expenses for the first quarter of 2013 were $3.3 million ($1.01 per Mcfe) compared to $4.6 million ($1.33 per Mcfe) in the first quarter of 2012, a decrease resulting from lower workover costs.

Production and Ad Valorem Tax Expenses.  Production and ad valorem tax expenses for the first quarter of 2013 were $1.7 million compared to $1.4 million for the first quarter of 2012, an increase primarily due to a higher percentage of taxable production.

Depreciation, Depletion and Amortization (“DD&A”).  DD&A expense for the first quarter of 2013 was $12.8 million compared to $14.5 million for the first quarter of 2012.

Impairment of Oil and Gas Properties.  Non-cash impairment of oil and gas properties for the first quarter of 2013 was $0.8 million compared to $0.7 million for the first quarter of 2012.  The impairments were the result of amortization of unproved properties.

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General and Administrative (“G&A”) Expenses.  Total G&A expenses were $4.3 million ($1.33 per Mcfe) for the first quarter of 2013 compared to $4.8 million ($1.37 per Mcfe) for the first quarter of 2012, which includes non-cash stock expense of $0.7 million ($0.20 per MCFE) and $0.5 million ($0.15 per Mcfe) for the first three months of 2013 and 2012, respectively.  Cash G&A expenses decreased primarily due to lower personnel and facility costs.

Interest Expense.  Interest expense was $6.3 million for the first quarter of 2013 compared to $6.2 million for the first quarter of 2012.

Other Income (Expense) and Financing Cost.  Other income (expense) and financing cost was $0.1 million for the first quarter 2013 compared to $0.2 million for the first quarter of 2012.  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 Loss on Derivative Instruments.  The non-cash unrealized loss on derivative instruments for the first quarter of 2013 was $1.9 million compared to $0.5 million for the first quarter of 2012.  The unrealized gain or loss is the change in the mark-to-market exposure under our commodity price hedging contracts.  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 price curve of the commodities being hedged.

Income Taxes.  Our net loss before taxes was $7.2 million for the first quarter of 2013 compared to $6.6 million in the first quarter of 2012.  After adjusting for permanent tax differences, we recorded an income tax benefit of $2.5 million for the first quarter of 2013, compared to $2.2 million for the first quarter of 2012.  Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences net of a previously recorded tax-adjusted $13.3 million valuation allowance.  The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

Liquidity and Capital Resources

Our primary cash requirements are for capital expenditures (including acquisitions), working capital, operating expenses 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 or asset monetizations, or reduce our capital expenditures.

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Liquidity and Cash Flow

Our working capital deficit was $18.5 million as of March 31, 2013, compared to a working capital deficit of $13.9 million as of December 31, 2012.  The following table provides the components and changes in working capital as of March 31, 2013 and December 31, 2012.

	March 31, 2013			December 31, 2012			Change
Current assets	(in millions, except percentages)
Accounts receivable, net	$	12.2		$	11.7		$	0.5
Prepaid expenses		0.8			0.8			—
Derivative instruments		—			1.9			(1.9	)
Deferred tax asset, net		10.9			10.4			0.5
Total current assets		23.9			24.8			(0.9	)
Current liabilities
Accounts payable and accrued liabilities (1)		41.6			37.8			3.8
Asset retirement obligations		0.7			0.9			(0.2	)
Derivative instruments		0.1			—			0.1
Total current liabilities		42.4			38.7			3.7
Working capital (deficit)	$	(18.5	)	$	(13.9	)	$	(4.6	)

(1)   Reflects impact of timing of capital expenditures payable.

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, 2013 and 2012, respectively.

	Three months ended March 31,
	2013			2012
Financial Measures	(in millions)
Net cash provided by operating activities	$	12.5		$	0.5
Net cash used in investing activities		(11.2	)		(32.6	)
Net cash provided by (used in) financing activities		(1.3	)		32.1
Cash and cash equivalents		—			—

During the three months ended March 31, 2013 the net cash provided by operating activities before changes in working capital decreased to $9.2 million, from $10.1 million for the first three months of 2012, primarily due to slightly lower revenue.

Net cash used in investing activities consisted primarily of capital expenditures on oil and gas drilling projects and leasehold acquisitions.

Net cash used in financing activities, which consisted primarily of net borrowings (repayments) on our revolving credit agreement, was $1.3 million for the three months ended March 31, 2013 compared to net cash provided by financing activities of $32.1 million for the three months ended March 31, 2012, a decrease primarily due to the 2012 reduction of the working capital deficit at December 31, 2011.

See the Consolidated Statements of Cash Flows for further details.

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Capital Resources

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lender parties thereto (the “Senior Credit Agreement”) that matures on May 31, 2015.  The borrowing base currently set at $100 million, is based on our current proved crude oil and natural gas reserves, and is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates.  The next borrowing base redetermination under our Senior Credit Agreement is scheduled for May 1, 2013.  We have started discussions with our agent bank on the scheduled redetermination, but may not finalize these discussions prior to filing this quarterly report on Form 10-Q with the SEC.  As part of this process, our agent bank has recommended affirmation of the $100 million borrowing base to the lender group.  Based on our discussions, we are optimistic that the borrowing base will be reaffirmed at $100 million.  The credit agreement also provides for the issuance of letters-of-credit up to a $5.0 million sub-limit.  As of March 31, 2013, we had $68.1 million outstanding, with availability of $31.9 million under our Senior Credit Agreement.

Advances under our Senior 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.  The applicable margin ranges between 1.75% and 2.75%, for LIBOR loans, and between 0.75% and 1.75%, 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.  The commitment fee payable on the unused portion of our borrowing base is between 0.375% and 0.500%, depending on the borrowing base utilization.

We also maintain a second lien credit agreement dated December 27, 2010 with Barclays Bank Plc, as agent, and the lender parties thereto, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”).  The Second Lien Credit Agreement provides for a term loan, made to us in a single draw, in an aggregate principal amount of $175.0 million and matures on December 27, 2015.  As of March 31, 2013, we had a principal amount of $175.0 million outstanding, with a discount of $4.4 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $170.6 million.

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 greatest of (i) 4.00% per annum, (ii) the “prime rate”, (iii) the Federal Funds Effective Rate plus ½ of 1% and (iv) the LIBOR rate for a one month interest period plus 1.00%.  The applicable margin for base rate loans is 8.50%.  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 9.50%.

Our Senior 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 Senior Credit Agreement.  Unpaid interest is payable under our credit agreements as interim borrowings mature.

We utilize commodity price hedge instruments to minimize exposure to declining prices on our natural gas, crude oil and natural gas liquids production.  We use a series of swaps and costless collars to accomplish our commodity hedging position.  We currently have 5.2 Bcfe of equivalent production hedged for the remainder of 2013, consisting of 3.2 Bcf of natural gas hedges at NYMEX prices, 201 MBbl of crude oil hedges at Brent prices and 126 MBbl of crude oil hedges at WTI prices.  We also

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have 2.0 Bcfe of equivalent production hedged for 2014, consisting of 174 MBbl of crude oil hedges at Brent prices and 1.0 Bcf of natural gas hedges at NYMEX prices.

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 resource plays in South, Southeast and East Texas and Colorado and in our conventional inventory, with activity in any particular area to be a function of market and field economics.  In the short term, due to the low natural gas price environment, and the superior economics from oil production, we will focus the majority of our capital expenditures on the development of our South and Southeast Texas crude oil and natural gas liquids rich prospect inventory.  We anticipate that acquisitions, including those of undeveloped leasehold interests, will continue to play a role in our business strategy as those opportunities arise from time to time.  While there are currently no unannounced agreements for the acquisition of any material businesses or assets, such transactions can be effected quickly and could occur at any time.

        We believe that our internally generated cash flow, combined with access to our Senior Credit Agreement, will be sufficient to meet the liquidity requirements necessary to fund our daily operations, planned capital development and debt service requirements for the next twelve months.  We currently plan to limit our 2013 capital expenditures to our forecasted cash flow from operations for the year; however, we do possess the capacity, through our Senior Credit Agreement, to increase and/or accelerate drilling on any particular area should we determine that market and project economics so warrant.  The vast majority of our planned capital expenditures for 2013 are on acreage that is currently held by existing production, therefore, we also possess the flexibility of reducing or deferring our capital expenditures, if deemed appropriate, without the risk of significant lease expirations.  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 commodity price volatility, which could, among other things, lead to a decline in the borrowing base under our Senior Credit Agreement in connection with a borrowing base redetermination.  In addition, if 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.  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, 2012.

Recent Accounting Pronouncements

In February 2013, the FASB issued ASU No. 2013-04— “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”.  The objective of this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting

22

principles (“GAAP”).  Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings.  U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice.  The accounting update is effective for interim and annual periods beginning after December 15, 2013.  We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

        Further, we are closely monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board.  There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation.  Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact that these standards will have, if any, on our financial position, results of operations or cash flows.

ITEM 3.          QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are currently exposed to market risk primarily related to adverse changes in natural gas, crude oil and natural gas liquids prices. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosure About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2012 and Note 5 – Derivative Instruments included in Part I. Item 1. Financial Statements of this Report.

Commodity Price Risk

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

At March 31, 2013, we had entered into swaps and costless collars related to future natural gas and crude oil sales with a net fair value of $77,014.  A price increase of $1.00 per Bbl of crude oil would decrease the net fair value of our commodity derivatives by approximately $0.3 million.  A price increase of $0.10 per MMBtu for natural gas would decrease the net fair value of our commodity derivatives by approximately $0.2 million.

Interest Rate Risk

We are exposed to interest rate risk on debt with variable interest rates.  In the past we have entered into, and may in the future enter into, interest rate swap agreements.  Changes in interest rates affect the amount of interest we pay on borrowings under our Senior Credit Agreement and our Second Lien Credit Agreement.  At March 31, 2013, we did not have any outstanding interest rate swap

23

agreements.  Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our Senior Credit Agreement would result in an increase of our interest expense by $0.7 million.

ITEM 4.          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 Report, 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 (the “Exchange Act”), 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 three months ended March 31, 2013, there has been no change to our internal controls over financial reporting that materially affected, or is reasonably likely to materially affect, these controls.

24

PART II.     OTHER INFORMATION

ITEM 1.          LEGAL PROCEEDINGS

See Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2012 for a description of legal proceedings to which we are subject.

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, 2012, 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 first quarter of 2013.  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
February 1-28, 2013	11,267	$	3.23	11,267	(1)
March 1-31, 2013	61,327	$	3.20	61,327	(1)
Total	72,594			72,594

(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 and other equity incentives.  Company policy and the 2005 Stock Incentive Plan provide for the withholding of shares to satisfy tax obligations.

ITEM 3.          DEFAULTS UPON SENIOR SECURITIES

        None.

ITEM 4.          MINE SAFETY DISCLOSURES

        None.

ITEM 5.          OTHER INFORMATION

        None.

25

ITEM 6.                 EXHIBITS

Number	Description
3.1	Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on July 5, 2005)
3.2	Bylaws of Crimson Exploration Inc. (incorporated by reference to Exhibit 3.7 to the Company’s Current Report on Form 8-K filed on July 5, 2005)
3.3	Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Appendix A to the Company’s Definitive Information Statement on Schedule 14C filed on August 18, 2006)
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 on July 5, 2005)
4.2	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)
4.3	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 on December 10, 2009)
4.4	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 on December 10, 2009)
*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
*101.INS	XBRL Instance Document
*101.SCH	XBRL Schema Document
*101.CAL	XBRL Calculation Linkbase Document
*101.LAB	XBRL Labels Linkbase Document

26

ITEM 6.                 EXHIBITS (continued)

Number	Description
*101.PRE	XBRL Presentation Linkbase Document
*101.DEF	XBRL Definition Linkbase Document
	*Filed herewith
	**Furnished herewith

27

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 8, 2013	By:	/s/ Allan D. Keel
			Allan D. Keel
			President and Chief Executive Officer
Date:	May 8, 2013	By:	/s/ E. Joseph Grady
			E. Joseph Grady
			Senior Vice President and Chief Financial Officer

28

EX-31.1

EX-31.2

EXHIBIT 31.2

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, E. Joseph Grady, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Crimson Exploration Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)  Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 8, 2013
	/s/ E. Joseph Grady
Name:	E. Joseph Grady
Title:	Senior Vice President
	Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is provided pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and accompanies the Quarterly Report on Form 10-Q (the “Form 10-Q”) for the quarter ended March 31, 2013 of Crimson Exploration Inc. (the “Issuer”).  The undersigned hereby certifies that the Form 10-Q fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)) and that the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

Date:	May 8, 2013
	/s/ Allan D. Keel
Name:	Allan D. Keel
Title:	President and Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Issuer and will be furnished to the Securities and Exchange Commission, or its staff, upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO

18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906

 OF THE SARBANES-OXLEY ACT OF 2002

This certification is provided pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and accompanies the Quarterly Report on Form 10-Q (the “Form 10-Q”) for the quarter ended March 31, 2013 of Crimson Exploration Inc. (the “Issuer”).  The undersigned hereby certifies that the Form 10-Q fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)) and that the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

Date:	May 8, 2013
	/s/ E. Joseph Grady
Name:	E. Joseph Grady
Title:	Senior Vice President
	Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Issuer and will be furnished to the Securities and Exchange Commission, or its staff, upon request.

XML

DERIVATIVE INSTRUMENTS (Details 2) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Effect of derivative contracts on Consolidated Statements of Operations
Realized (loss) gain	$ (62,944)	$ 1,373,863
Unrealized loss on derivative instruments	(1,882,990)	(525,633)
Crude oil contract
Effect of derivative contracts on Consolidated Statements of Operations
Unrealized loss on derivative instruments	(809,413)	(1,532,130)
Crude oil contract | Crude oil sales
Effect of derivative contracts on Consolidated Statements of Operations
Realized (loss) gain	(207,269)	(161,597)
Natural gas reserves contract
Effect of derivative contracts on Consolidated Statements of Operations
Unrealized loss on derivative instruments	(1,073,577)	1,006,497
Natural gas reserves contract | Natural gas reserves sales
Effect of derivative contracts on Consolidated Statements of Operations
Realized (loss) gain	$ 144,325	$ 1,535,460

XML

USE OF ESTIMATES

3 Months Ended

Mar. 31, 2013

USE OF ESTIMATES

USE OF ESTIMATES

3.           USE OF ESTIMATES

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) crude oil, natural gas and natural gas liquids revenues and reserves; (2) depreciation, depletion and amortization; (3) impairment of oil and gas properties; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations; (7) valuation of derivative instruments and (8) valuation allowances associated with income taxes and accounts receivables.  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.

XML

DEBT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 Senior Credit Agreement item	Mar. 31, 2013 Second Lien Credit Agreement	Dec. 27, 2010 Second Lien Credit Agreement
Debt
Borrowing base	$ 100
Number of additional unscheduled redeterminations between scheduled redetermination dates	1
Amount outstanding	68.1
Remaining borrowing capacity	31.9
Principal amount of debt			175.0
Principal amount outstanding, gross		175.0
Discount on debt instrument		4.4
Net outstanding balance		$ 170.6

XML

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	3 Months Ended
	Mar. 31, 2013
Asset Retirement Obligations Roll forward
Asset retirement obligations at the beginning of the period	$ 11,029,206
Accretion expense	122,638
Liabilities incurred	2,667
Liabilities settled	(179,601)
Asset retirement obligations at the end of the period	$ 10,974,910

XML

STOCKHOLDERS' EQUITY (Details)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Stockholders' Equity
Shares issued pursuant to stock option exercises		2,897
Restricted common stock
Stockholders' Equity
Shares vested	417,252	193,228
Shares held to satisfy the employees' tax liability	72,594	27,436
Restricted common stock | Employees
Stockholders' Equity
Shares granted	642,000	948,000
Restricted common stock | New employees
Stockholders' Equity
Shares granted		4,000

XML

INCOME TAXES (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
INCOME TAXES
Income tax benefit	$ (2,493,554)	$ (2,175,809)
Tax-adjusted valuation allowance	$ 13,300,000

XML

BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 2013

BASIS OF PRESENTATION

BASIS OF PRESENTATION

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 March 31, 2013 (unaudited) and December 31, 2012 and for the three months ended March 31, 2013 (unaudited) and 2012 (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 months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

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, 2012.

The accompanying consolidated financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Crimson Exploration Operating, Inc. and LTW Pipeline Co.  All material intercompany transactions and balances are eliminated upon consolidation.  Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.

New Accounting Standards Adopted in 2013

In December 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-11 “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” ASU 2011-11.  This accounting update requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  This accounting update was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.

In January 2013, the FASB issued ASU No. 2013-01— “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”.  The main objective in developing this update is to address implementation issues about the scope of ASU No. 2011-11.  This ASU clarifies the scope of the offsetting disclosures and addresses any unintended consequences.  The scope of Update 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement.  This ASU is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods.  An entity should provide the required disclosures retrospectively for all comparative periods presented.  This ASU was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.

XML

SUBSEQUENT EVENT (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	0 Months Ended
	Mar. 31, 2013 Combined entities Pro forma Mcfe	Apr. 30, 2013 Subsequent event Crimson Contango Scenario forecast
Subsequent event
Number of shares of common stock to be received for each share owned as consideration		0.08288
Ownership percentage in post-merger entity		20.30%
Approximate net daily production (in Mmcfe)	101,000
Oil and natural gas liquids production as a percentage of net daily production	31.00%
Estimated total proved reserves (in Bcfe)	312,000,000
Oil and natural gas liquids as a percentage of estimated total proved reserves	31.00%
PV-10 of the estimated proved reserves	$ 932.5
Share price (in dollars per share)		$ 3.19
Premium on share price as a percentage of most recent closing price of common stock		8.00%
Aggregate consideration		390
Number of shares of common stock assumed to be issued		3,900,000
Long-term debt assumed		$ 244

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CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 0
Accounts receivable, net of allowance of $568,429 and $525,556, respectively	12,215,741	11,726,078
Prepaid expenses	811,937	844,495
Derivative instruments	23,203	1,892,744
Deferred tax asset, net	10,854,534	10,361,157
Total current assets	23,905,415	24,824,474
PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method of accounting)	750,422,487	740,070,145
Other property and equipment	3,036,873	3,061,635
Accumulated depreciation, depletion and amortization	(454,996,621)	(442,304,300)
Total property and equipment, net	298,462,739	300,827,480
NONCURRENT ASSETS
Deposits	34,743	34,743
Debt issuance cost	960,325	1,056,272
Derivative instruments	211,210	67,261
Deferred tax asset, net	43,801,070	41,810,159
Total noncurrent assets	45,007,348	42,968,435
TOTAL ASSETS	367,375,502	368,620,389
CURRENT LIABILITIES
Accounts payable	31,939,209	31,127,671
Accrued liabilities	9,616,158	6,680,843
Asset retirement obligations	738,428	876,774
Derivative instruments	136,373
Total current liabilities	42,430,168	38,685,288
NONCURRENT LIABILITIES
Long-term debt	238,589,148	239,368,865
Asset retirement obligations	10,236,482	10,152,432
Derivative instruments	21,026
Other noncurrent liabilities	559,349	571,687
Total noncurrent liabilities	249,406,005	250,092,984
Total liabilities	291,836,173	288,778,272
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Common stock (par value $0.001; 200,000,000 shares authorized; 46,874,484 and 46,259,009 shares issued and 46,606,703 and 46,063,822 shares outstanding as of March 31, 2013 and December 31, 2012, respectively)	46,874	46,259
Additional paid-in capital	246,669,871	246,007,941
Retained deficit	(170,074,924)	(165,343,525)
Treasury stock (at cost, 267,781 and 195,187 shares as of March 31, 2013 and December 31, 2012, respectively)	(1,102,492)	(868,558)
Total stockholders' equity	75,539,329	79,842,117
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 367,375,502	$ 368,620,389

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (4,731,399)	$ (4,399,085)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	12,839,720	14,462,062
Asset retirement obligations	(179,601)	121,042
Stock compensation expense	662,545	532,311
Amortization of financing costs and discounts	418,391	385,585
Deferred income taxes	(2,484,288)	(2,175,809)
Impairment of unproved oil and gas properties	817,738	676,474
Gain on sale of assets	(6,384)	(8,900)
Unrealized loss on derivative instruments	1,882,990	525,633
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, net	(489,663)	175,929
Decrease (increase) in prepaid expenses	32,558	(235,151)
Increase (decrease) in accounts payable and accrued liabilities	3,734,515	(9,521,713)
Net cash provided by operating activities	12,497,122	538,378
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(11,167,412)	(32,675,599)
Sale of assets	6,384	8,900
Net cash used in investing activities	(11,161,028)	(32,666,699)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt	(37,215,089)	(43,293,956)
Proceeds from debt	36,112,929	75,503,103
Proceeds from issuance of common stock		6,952
Purchase of treasury stock	(233,934)	(87,778)
Net cash provided by (used in) financing activities	(1,336,094)	32,128,321
INCREASE IN CASH AND CASH EQUIVALENTS	0
CASH AND CASH EQUIVALENTS, Beginning of period		0
CASH AND CASH EQUIVALENTS, End of period	0
Cash paid for interest	$ 5,870,267	$ 5,833,170

XML

ASSET RETIREMENT OBLIGATIONS (Tables)

3 Months Ended

Mar. 31, 2013

ASSET RETIREMENT OBLIGATIONS

Schedule for roll forward of composition of asset retirement obligations

Beginning January 1, 2013 liability	$	11,029,206
Accretion expense		122,638
Liabilities incurred		2,667
Liabilities settled		(179,601	)
Revisions		—
Ending March 31, 2013 liability	$	10,974,910

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DERIVATIVE INSTRUMENTS (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
DERIVATIVE INSTRUMENTS
Net assets for derivative instruments	$ 77,014		$ 2,000,000
Unrealized loss on derivative instruments	(1,882,990)	(525,633)
Commodity price derivative instruments
DERIVATIVE INSTRUMENTS
Net assets for derivative instruments	234,413		1,960,005
Fair value of derivative asset	932,078		2,206,705
Fair value of derivative liability	(697,665)		(246,700)
Total net fair value of derivative assets	77,014
Commodity price derivative instruments | West Texas Intermediate crude oil | Apr 2013-Dec 2013, one | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	14
Price/Unit (in dollars per Bbls or per Mmbtu)	101.25
Fair value of derivative asset	559,262
Commodity price derivative instruments | Brent crude oil | Apr 2013-Dec 2013, two | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	9
Price/Unit (in dollars per Bbls or per Mmbtu)	109.13
Fair value of derivative asset	90,989
Commodity price derivative instruments | Brent crude oil | Apr 2013-Jun 2013,one | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	6
Price/Unit (in dollars per Bbls or per Mmbtu)	108.35
Fair value of derivative liability	(21,678)
Commodity price derivative instruments | Brent crude oil | Apr 2013-Dec 2013, three | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	6
Price/Unit (in dollars per Bbls or per Mmbtu)	107.10
Fair value of derivative liability	(48,805)
Commodity price derivative instruments | Brent crude oil | Apr 2013-Jun 2013, two | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	7
Price/Unit (in dollars per Bbls or per Mmbtu)	104.80
Fair value of derivative liability	(99,799)
Commodity price derivative instruments | Brent crude oil | Jul 2013-Sep 2013 | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	6
Price/Unit (in dollars per Bbls or per Mmbtu)	103.47
Fair value of derivative liability	(82,032)
Commodity price derivative instruments | Brent crude oil | Oct 2013-Dec 2013 | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	3
Price/Unit (in dollars per Bbls or per Mmbtu)	102.30
Fair value of derivative liability	(36,529)
Commodity price derivative instruments | Brent crude oil | Jan 2014-Dec 2014, one | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	7.5
Price/Unit (in dollars per Bbls or per Mmbtu)	102.10
Fair value of derivative liability	(79,460)
Commodity price derivative instruments | Brent crude oil | Jan 2014 - Jun 2014 | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	2
Price/Unit (in dollars per Bbls or per Mmbtu)	108.07
Fair value of derivative asset	45,665
Commodity price derivative instruments | Brent crude oil | Jan 2014-Dec 2014, two | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	6
Price/Unit (in dollars per Bbls or per Mmbtu)	106.40
Fair value of derivative asset	236,162
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Dec 2013, one | Collar | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	75,000
Floor Price/Unit (in dollars per Bbls or per Mmbtu)	3.00
Cap Price/Unit (in dollars per Bbls or per Mmbtu)	4.25
Fair value of derivative liability	(127,094)
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Dec 2013, two | Collar | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	75,000
Floor Price/Unit (in dollars per Bbls or per Mmbtu)	3.25
Cap Price/Unit (in dollars per Bbls or per Mmbtu)	4.00
Fair value of derivative liability	(185,288)
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Jun 2013,one | Collar | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	50,000
Floor Price/Unit (in dollars per Bbls or per Mmbtu)	3.75
Cap Price/Unit (in dollars per Bbls or per Mmbtu)	4.00
Fair value of derivative liability	(12,110)
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Dec 2013, three | Collar | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	35,000
Floor Price/Unit (in dollars per Bbls or per Mmbtu)	3.75
Cap Price/Unit (in dollars per Bbls or per Mmbtu)	4.21
Fair value of derivative liability	(33,805)
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Dec 2013, four | Swap | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	70,000
Price/Unit (in dollars per Bbls or per Mmbtu)	4.02
Fair value of derivative liability	(53,207)
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Dec 2014, one | Collar | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	42,500
Floor Price/Unit (in dollars per Bbls or per Mmbtu)	3.75
Cap Price/Unit (in dollars per Bbls or per Mmbtu)	4.60
Fair value of derivative liability	(42,669)
Commodity price derivative instruments | Henry Hub NYMEX natural gas | Apr 2013-Dec 2014, two | Collar | Not Designated
DERIVATIVE INSTRUMENTS
Volume/Month (in Bbls or Mmbtu)	42,500
Floor Price/Unit (in dollars per Bbls or per Mmbtu)	3.50
Cap Price/Unit (in dollars per Bbls or per Mmbtu)	5.00
Fair value of derivative liability	$ (32,588)
Cash flow hedges | Designated
DERIVATIVE INSTRUMENTS
Number of derivative instruments	0
Fair value hedges | Designated
DERIVATIVE INSTRUMENTS
Number of derivative instruments	0

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ORGANIZATION AND NATURE OF OPERATIONS

3 Months Ended

Mar. 31, 2013

ORGANIZATION AND NATURE OF OPERATIONS

ORGANIZATION AND NATURE OF OPERATIONS

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 exploitation, exploration, development and acquisition of natural gas and crude oil properties.  Our operating areas include the onshore U.S. Gulf Coast, South Texas, East Texas, Southeast Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have expanded our strategic focus to include longer reserve life resource plays that we believe provide significant long-term growth potential in multiple formations.  We are also focusing on further developing our oil/liquid weighted assets.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2013	Dec. 31, 2012
CONSOLIDATED BALANCE SHEETS
Accounts receivable, allowance (in dollars)	$ 568,429	$ 525,556
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	46,874,484	46,259,009
Common stock, shares outstanding	46,606,703	46,063,822
Treasury stock, shares	267,781	195,187

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RECENT ACCOUNTING PRONOUNCEMENTS

3 Months Ended

Mar. 31, 2013

RECENT ACCOUNTING PRONOUNCEMENTS

RECENT ACCOUNTING PRONOUNCEMENTS

11.         RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Not Yet Adopted

In February 2013, the FASB issued ASU No. 2013-04— “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”.  The objective of this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP.  Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings.  U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice.  The accounting update is effective for interim and annual periods beginning after December 15, 2013.  We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

Further, we are closely monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board.  There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation.  Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact that these standards will have, if any, on our financial position, results of operations or cash flows.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2013	May 02, 2013
Document and Entity Information
Entity Registrant Name	CRIMSON EXPLORATION INC.
Entity Central Index Key	0000813779
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		46,623,161
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1

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SUBSEQUENT EVENT

3 Months Ended

Mar. 31, 2013

SUBSEQUENT EVENT

SUBSEQUENT EVENT

12.         SUBSEQUENT EVENT

On April 30, 2013, Crimson Exploration Inc. ("Crimson") and Contango Oil & Gas Company ("Contango") jointly announced that they have signed a merger agreement for an all-stock transaction pursuant to which Crimson would become a wholly owned subsidiary of Contango.  Upon consummation of the merger, each share of Crimson stock will be converted into 0.08288 shares of Contango stock resulting in Crimson stockholders owning 20.3% of the post-merger Contango.

Following the merger, the combined company will be a premier Houston-based independent oil and gas company with a balanced offshore Gulf of Mexico ("GoM") and onshore Texas production profile.  The combined company will offer a deep inventory of high-impact GoM prospects complemented by Crimson's onshore oil and natural gas liquids-focused, lower-risk unconventional resource positions in several prolific plays.  Pro forma for the merger, the combined companies’ net daily production for the quarter ending March 31, 2013 would be approximately 101 Mmcfe (31% oil and natural gas liquids) and total proved reserves are estimated to be approximately 312 Bcfe (31% oil and natural gas liquids), based on SEC pricing at March 31, 2013.  Pro forma PV-10 of the estimated proved reserves of the combined company would be approximately $932.5 million.  The enhanced size and scale of the combined company and its conservatively capitalized balance sheet will position it to implement an accelerated oil and natural gas liquids-focused drilling program.

Crimson stockholders will receive per-share consideration consisting of 0.08288 shares of Contango common stock for each Crimson share.  Based on Contango’s closing stock price on April 29, 2013, this transaction represents an implied price per share for Crimson of $3.19, a premium of approximately 8% percent to the most recent closing price of Crimson common stock.  Aggregate consideration in the transaction is approximately $390 million based on the assumed issuance of approximately 3.9 million shares of Contango common stock and the assumption by Contango of approximately $244 million of long-term debt of Crimson.

The merger is subject to the approval of the stockholders of both Contango and Crimson as well as customary closing conditions.  The Estate of Kenneth R. Peak, Brad Juneau, members of the management teams of Contango and Crimson, and affiliates of Oaktree Capital Management (Crimson’s largest stockholder) have all entered into voting agreements in support of the transaction.  The merger is expected to close in the third quarter of 2013.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
OPERATING REVENUES
Crude oil sales	$ 16,093,396	$ 16,892,614
Natural gas sales	6,002,675	7,069,114
Natural gas liquids sales	1,998,863	2,724,851
Total operating revenues	24,094,934	26,686,579
OPERATING EXPENSES
Lease operating expenses	3,262,127	4,637,385
Production and ad valorem taxes	1,688,742	1,408,741
Exploration expenses	117,481	300,696
Depreciation, depletion and amortization	12,839,720	14,462,062
Impairment of oil and gas properties	817,738	676,474
General and administrative	4,314,334	4,771,457
Gain on sale of assets	(6,384)	(8,900)
Total operating expenses	23,033,758	26,247,915
INCOME FROM OPERATIONS	1,061,176	438,664
OTHER INCOME (EXPENSE)
Interest expense	(6,283,737)	(6,245,182)
Other income (expense) and financing costs	(119,402)	(242,743)
Unrealized loss on derivative instruments	(1,882,990)	(525,633)
Total other income (expense)	(8,286,129)	(7,013,558)
LOSS BEFORE INCOME TAXES	(7,224,953)	(6,574,894)
Income tax benefit	2,493,554	2,175,809
NET LOSS	$ (4,731,399)	$ (4,399,085)
NET LOSS PER SHARE
Basic (in dollars per share)	$ (0.11)	$ (0.10)
Diluted (in dollars per share)	$ (0.11)	$ (0.10)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic (in shares)	44,389,522	43,976,950
Diluted (in shares)	44,389,522	43,976,950

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OIL AND GAS PROPERTIES

3 Months Ended

Mar. 31, 2013

OIL AND GAS PROPERTIES

OIL AND GAS PROPERTIES

6.           OIL AND GAS PROPERTIES

The following table sets forth the composition of impairment and abandonment expenses:

	Three months ended March 31,
	2013		2012
Impairment and abandonment of unproved properties	$	817,738	$	676,474

2013 Asset Impairments. Non-cash impairments of unproved properties include $0.8 million related to individually insignificant acreage.  There were no impairments or abandonments of proved properties.

2012 Asset Impairments. Non-cash impairments of unproved properties include $0.7 million related to individually insignificant acreage.  There were no impairments or abandonments of proved properties.

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DERIVATIVE INSTRUMENTS

3 Months Ended

Mar. 31, 2013

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

5.           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 $77,014 and $2.0 million at March 31, 2013 and December 31, 2012, respectively.  As a result of these agreements, we recorded non-cash unrealized losses for unsettled contracts of $1.9 million and $0.5 million for the three months ended March 31, 2013 and 2012, respectively.  The estimated change in fair value of the derivatives is reported in other income (expense) as unrealized gain (loss) on derivative instruments.  The realized gain (loss) on derivative instruments is included in crude oil, natural gas and natural gas liquids sales for our commodity price hedges.

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our natural gas and crude oil production, to reduce our sensitivity to volatile commodity prices, and with respect to portions of our debt, to reduce our sensitivity to volatile interest rates.  None of our derivative instruments are designated as cash flow or fair value 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 crude oil, natural gas 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 provide only partial protection against declines in commodity prices.  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 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.  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 senior secured revolving credit agreement and various hedge contracts.  See Note 4 — “Fair Value Measurements” for further information.

The following derivative contracts were in place at March 31, 2013:

Crude Oil			Volume/Month		Price/Unit		Fair Value
Apr 2013-Dec 2013		Swap	14,000 Bbls	$	101.25 (1)	$	559,262
Apr 2013-Dec 2013		Swap	9,000 Bbls		109.13 (2)		90,989
Apr 2013-Jun 2013		Swap	6,000 Bbls		108.35 (2)		(21,678	)
Apr 2013-Dec 2013		Swap	6,000 Bbls		107.10 (2)		(48,805	)
Apr 2013-Jun 2013		Swap	7,000 Bbls		104.80 (2)		(99,799	)
Jul 2013-Sep 2013		Swap	6,000 Bbls		103.47 (2)		(82,032	)
Oct 2013-Dec 2013		Swap	3,000 Bbls		102.30 (2)		(36,529	)
Jan 2014-Dec 2014		Swap	7,500 Bbls		102.10 (2)		(79,460	)
Jan 2014-Jun 2014		Swap	2,000 Bbls		108.07 (2)		45,665
Jan 2014-Dec 2014		Swap	6,000 Bbls		106.40 (2)		236,162
Natural Gas
Apr 2013-Jun 2013		Collar	50,000 Mmbtu		Put $3.75-$4.00 Call (3)		(12,110	)
Apr 2013-Dec 2013		Collar	75,000 Mmbtu		Put $3.00-$4.25 Call (3)		(127,094	)
Apr 2013-Dec 2013		Collar	75,000 Mmbtu		Put $3.25-$4.00 Call (3)		(185,288	)
Apr 2013-Dec 2013		Collar	35,000 Mmbtu		Put $3.75-$4.21 Call (3)		(33,805	)
Apr 2013-Dec 2013		Swap	70,000 Mmbtu		$4.02 (3)		(53,207	)
Apr 2013-Dec 2014		Collar	42,500 Mmbtu		Put $3.75-$4.60 Call (3)		(42,669	)
Apr 2013-Dec 2014		Collar	42,500 Mmbtu		Put $3.50-$5.00 Call (3)		(32,588	)
	Total net fair value of derivative instruments					$	77,014

(1)   Commodity derivative based on West Texas Intermediate crude oil

(2)   Commodity derivative based on Brent crude oil

(3)   Commodity derivatives based on Henry Hub NYMEX natural gas prices

The following table details the effect of derivative contracts on the Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012, respectively:

Contract Type	Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Recognized in Income
		Three months ended March 31,
		2013			2012
Crude oil contracts	Crude oil sales	$	(207,269	)	$	(161,597	)
Natural gas contracts	Natural gas sales		144,325			1,535,460
	Realized (loss) gain	$	(62,944	)	$	1,373,863
Crude oil contracts	Unrealized (loss) gain on derivative instruments	$	(809,413	)	$	(1,532,130	)
Natural gas contracts	Unrealized (loss) gain on derivative instruments		(1,073,577	)		1,006,497
	Unrealized loss	$	(1,882,990	)	$	(525,633	)

Balance Sheet Presentation

Our derivatives are presented on a net basis in derivative instruments on the Consolidated Balance Sheets.  The following summarizes the fair value of derivatives outstanding on a gross and net basis:

	March 31, 2013
	Gross		Netting (1)			Total
Assets:
Commodity derivatives	$	932,078	$	(697,665	)	$	234,413
Liabilities:
Commodity derivatives		855,064		(697,665	)		157,399

	December 31, 2012
	Gross		Netting (1)			Total
Assets:
Commodity derivatives	$	2,206,705	$	(246,700	)	$	1,960,005
Liabilities:
Commodity derivatives		246,700		(246,700	)		—

(1)   Represents counterparty netting under agreements governing such derivatives

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FAIR VALUE MEASUREMENTS (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
FAIR VALUE MEASUREMENTS
Maximum period of interest rate paid on floating-rate debt	3 months
Transfer of assets from level 1 to level 2	$ 0
Transfer of assets from level 2 to level 1	0
Transfer of liabilities from level 1 to level 2	0
Transfer of liabilities from level 2 to level 1	0
Transfer of assets from level 3 to other levels	0
Transfer of assets from other levels to level 3	0
Transfer of liabilities from level 3 to other levels	0
Transfer of liabilities from other levels to level 3	0
Fair value measurements related to derivative instruments
Commodity price contracts (assets)	77,014	2,000,000
Commodity price contracts
Fair value measurements related to derivative instruments
Commodity price contracts (assets)	234,413	1,960,005
Total Carrying Value | Commodity price contracts | Recurring basis
Fair value measurements related to derivative instruments
Commodity price contracts (assets)	234,413
Commodity price contracts (liabilities)	(157,399)
Total	77,014	1,960,005
Level 2 | Commodity price contracts | Recurring basis
Fair value measurements related to derivative instruments
Commodity price contracts (assets)	234,413
Commodity price contracts (liabilities)	(157,399)
Total	$ 77,014	$ 1,960,005

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2013

FAIR VALUE MEASUREMENTS

Schedule of fair value information related to derivative instruments

Fair value information related to our derivative instruments measured at fair value on a recurring basis was as follows at March 31, 2013:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Commodity price contracts (assets)	$	234,413		$	—	$	234,413		$	—
Commodity price contracts (liabilities)		(157,399	)		—		(157,399	)		—
Total	$	77,014		$	—	$	77,014		$	—

Fair value information for related to our derivative instruments measured at fair value was as follows at December 31, 2012:

	Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts	$	1,960,005	$	—	$	1,960,005	$	—

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STOCKHOLDERS' EQUITY

3 Months Ended

Mar. 31, 2013

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

9.           STOCKHOLDERS’ EQUITY

In the three months ended March 31, 2013, 417,252 shares of restricted Common Stock vested, of which 72,594 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, with the remaining shares being distributed to the employees and directors.  Discretionary grants of 642,000 shares of unvested restricted Common Stock were made to our employees during the three months ended March 31, 2013 as incentive-based equity compensation under the 2005 Stock Incentive Plan.

In the three months ended March 31, 2012, 193,228 shares of restricted Common Stock vested, of which 27,436 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, with the remaining shares being distributed to the employees and directors.  During the three months we also issued 2,897 shares pursuant to stock option exercises.  Discretionary grants of 948,000 shares of unvested restricted Common Stock were made to our employees during the three months ended March 31, 2013 as incentive-based equity compensation under the 2005 Stock Incentive Plan.  We also granted 4,000 shares of restricted Common Stock during such period to new employees as part of their compensation package.

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ASSET RETIREMENT OBLIGATIONS

3 Months Ended

Mar. 31, 2013

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

7.           ASSET RETIREMENT OBLIGATIONS

We estimate the fair values of 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.  The following table sets forth the composition of asset retirement obligations rollforward:

Beginning January 1, 2013 liability	$	11,029,206
Accretion expense		122,638
Liabilities incurred		2,667
Liabilities settled		(179,601	)
Revisions		—
Ending March 31, 2013 liability	$	10,974,910

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DEBT

3 Months Ended

Mar. 31, 2013

DEBT

DEBT

8.           DEBT

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lender parties thereto (the “Senior Credit Agreement”) that matures on May 31, 2015.  The borrowing base, currently set at $100 million, is based on our current proved crude oil and natural gas reserves, and is subject to semi-annual redeterminations, although our lenders may elect to make one additional unscheduled redetermination between scheduled redetermination dates.  The next borrowing base redetermination under our Senior Credit Agreement is scheduled for May 1, 2013.  We have started discussions with our agent bank on the scheduled redetermination, but may not finalize these discussions prior to filing this quarterly report on Form 10-Q with the SEC.  As part of this process, our agent bank has recommended affirmation of the $100 million borrowing base to the lender group.  Based on our discussions, we are optimistic that the borrowing base will be reaffirmed at $100 million.  As of March 31, 2013, we had $68.1 million outstanding, with availability of $31.9 million, under our Senior Credit Agreement.

We also maintain a second lien credit agreement dated December 27, 2010 with Barclays Bank Plc, as agent, and the lender parties thereto, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”).  The Second Lien Credit Agreement provides for a term loan, which was made to us in a single draw in an aggregate principal amount of $175.0 million that matures on December 27, 2015.  As of March 31, 2013, we had a principal amount of $175.0 million outstanding, with a discount of $4.4 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $170.6 million.  The Senior Credit Agreement and the Second Lien Credit Agreement (the “Credit Agreements”) are secured by liens on substantially all of our assets, as well as security interests in the stock of our subsidiaries.  The liens securing the Second Lien Credit Agreement are junior to those securing the Senior Credit Agreement.  Interest is payable on the Credit Agreements as interim borrowings mature.

The Credit Agreements include usual and customary affirmative and negative covenants for credit facilities of their respective types and sizes, 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 covenants.  See Note 9 of our Annual Report on Form 10-K for the year ended December 31, 2012 for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements.  At March 31, 2013, we were in compliance with the covenants.

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INCOME TAXES

3 Months Ended

Mar. 31, 2013

INCOME TAXES

INCOME TAXES

10.         INCOME TAXES

Income tax benefit for the three months ended March 31, 2013 was $2.5 million compared to income tax benefit of $2.2 million for the three months ended March 31, 2012.  The quarterly income tax provision is based on our estimate of the effective tax rate expected to be applicable for the full year.  Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences net of a tax-adjusted $13.3 million valuation allowance.  The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

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OIL AND GAS PROPERTIES (Tables)

3 Months Ended

Mar. 31, 2013

OIL AND GAS PROPERTIES

Schedule of composition of impairment and abandonment expenses

	Three months ended March 31,
	2013		2012
Impairment and abandonment of unproved properties	$	817,738	$	676,474

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DERIVATIVE INSTRUMENTS (Details 3) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Assets:
Total	$ 77,014	$ 2,000,000
Commodity derivatives
Assets:
Gross	932,078	2,206,705
Netting	(697,665)	(246,700)
Total	234,413	1,960,005
Liabilities:
Gross	855,064	246,700
Netting	(697,665)	(246,700)
Total	$ 157,399

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)	Total	COMMON STOCK	ADDITIONAL PAID-IN CAPITAL	RETAINED DEFICIT	TREASURY STOCK
BALANCE at Dec. 31, 2012	$ 79,842,117	$ 46,259	$ 246,007,941	$ (165,343,525)	$ (868,558)
BALANCE (in shares) at Dec. 31, 2012	46,063,822	46,063,822
Increase (Decrease) in Stockholders' Equity
Current period net loss	(4,731,399)			(4,731,399)
Share-based compensation	662,545	615	661,930
Share-based compensation (in shares)		615,475
Treasury stock	(233,934)				(233,934)
Treasury stock (in shares)		(72,594)
BALANCE at Mar. 31, 2013	$ 75,539,329	$ 46,874	$ 246,669,871	$ (170,074,924)	$ (1,102,492)
BALANCE (in shares) at Mar. 31, 2013	46,606,703	46,606,703

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2013

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

4.           FAIR VALUE MEASUREMENTS

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 and costless collars.  The fair value measurement of our unrealized commodity price instruments were obtained from financial institutions and adjusted for non-performance risk, and were evaluated for accuracy using our hedge agreements and future commodity curves.  Differences between management’s calculation and that of the financial institutions were evaluated for reasonableness.  See Note 5 — “Derivative Instruments” for further information.

Impairments.  We test 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.  Additionally, we may use appropriate market data to determine fair value.  Because these significant fair value inputs are typically not observable, we classify impairments of long-lived assets as a Level 3 fair value measure.  See Note 6 – “Oil and Gas Properties” for further information.

Asset Retirement Obligations.  The initial measurement of asset retirement obligations ("AROs") at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties.  The factors used to determine fair value include, but are not limited to, plugging costs and reserve lives.  See Note 7 – “Asset Retirement Obligations” for further information.

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 8 — “Debt” for further information.

Accounting guidance has 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 have been no transfers between Level 1, Level 2 or Level 3 during this quarter.

Fair value information related to our derivative instruments measured at fair value on a recurring basis was as follows at March 31, 2013:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Commodity price contracts (assets)	$	234,413		$	—	$	234,413		$	—
Commodity price contracts (liabilities)		(157,399	)		—		(157,399	)		—
Total	$	77,014		$	—	$	77,014		$	—

At March 31, 2013, we did not measure assets or liabilities at fair value on a non-recurring basis.

Fair value information for related to our derivative instruments measured at fair value was as follows at December 31, 2012:

	Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts	$	1,960,005	$	—	$	1,960,005	$	—

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OIL AND GAS PROPERTIES (Details) (USD $)	3 Months Ended			12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Individually insignificant acreage	Dec. 31, 2012 Individually insignificant acreage
Impairment and abandonment expenses
Impairment and abandonment of unproved properties	$ 817,738	$ 676,474	$ 800,000	$ 700,000
Impairment and abandonment of proved properties	$ 0	$ 0

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DERIVATIVE INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2013

DERIVATIVE INSTRUMENTS

Schedule of derivative contracts

The following derivative contracts were in place at March 31, 2013:

Crude Oil			Volume/Month		Price/Unit		Fair Value
Apr 2013-Dec 2013		Swap	14,000 Bbls	$	101.25 (1)	$	559,262
Apr 2013-Dec 2013		Swap	9,000 Bbls		109.13 (2)		90,989
Apr 2013-Jun 2013		Swap	6,000 Bbls		108.35 (2)		(21,678	)
Apr 2013-Dec 2013		Swap	6,000 Bbls		107.10 (2)		(48,805	)
Apr 2013-Jun 2013		Swap	7,000 Bbls		104.80 (2)		(99,799	)
Jul 2013-Sep 2013		Swap	6,000 Bbls		103.47 (2)		(82,032	)
Oct 2013-Dec 2013		Swap	3,000 Bbls		102.30 (2)		(36,529	)
Jan 2014-Dec 2014		Swap	7,500 Bbls		102.10 (2)		(79,460	)
Jan 2014-Jun 2014		Swap	2,000 Bbls		108.07 (2)		45,665
Jan 2014-Dec 2014		Swap	6,000 Bbls		106.40 (2)		236,162
Natural Gas
Apr 2013-Jun 2013		Collar	50,000 Mmbtu		Put $3.75-$4.00 Call (3)		(12,110	)
Apr 2013-Dec 2013		Collar	75,000 Mmbtu		Put $3.00-$4.25 Call (3)		(127,094	)
Apr 2013-Dec 2013		Collar	75,000 Mmbtu		Put $3.25-$4.00 Call (3)		(185,288	)
Apr 2013-Dec 2013		Collar	35,000 Mmbtu		Put $3.75-$4.21 Call (3)		(33,805	)
Apr 2013-Dec 2013		Swap	70,000 Mmbtu		$4.02 (3)		(53,207	)
Apr 2013-Dec 2014		Collar	42,500 Mmbtu		Put $3.75-$4.60 Call (3)		(42,669	)
Apr 2013-Dec 2014		Collar	42,500 Mmbtu		Put $3.50-$5.00 Call (3)		(32,588	)
	Total net fair value of derivative instruments					$	77,014

(1)   Commodity derivative based on West Texas Intermediate crude oil

(2)   Commodity derivative based on Brent crude oil

(3)   Commodity derivatives based on Henry Hub NYMEX natural gas prices

Schedule of effect of derivative contracts on the Consolidated Statements of Operations

Contract Type	Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Recognized in Income
		Three months ended March 31,
		2013			2012
Crude oil contracts	Crude oil sales	$	(207,269	)	$	(161,597	)
Natural gas contracts	Natural gas sales		144,325			1,535,460
	Realized (loss) gain	$	(62,944	)	$	1,373,863
Crude oil contracts	Unrealized (loss) gain on derivative instruments	$	(809,413	)	$	(1,532,130	)
Natural gas contracts	Unrealized (loss) gain on derivative instruments		(1,073,577	)		1,006,497
	Unrealized loss	$	(1,882,990	)	$	(525,633	)

Summary of the fair value of derivatives outstanding on a gross and net basis

	March 31, 2013
	Gross		Netting (1)			Total
Assets:
Commodity derivatives	$	932,078	$	(697,665	)	$	234,413
Liabilities:
Commodity derivatives		855,064		(697,665	)		157,399

	December 31, 2012
	Gross		Netting (1)			Total
Assets:
Commodity derivatives	$	2,206,705	$	(246,700	)	$	1,960,005
Liabilities:
Commodity derivatives		246,700		(246,700	)		—

(1)   Represents counterparty netting under agreements governing such derivatives