Edgar Filing: CRIMSON EXPLORATION INC.

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

( ) 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 July 30, 2012, there were 46,065,761 shares outstanding of the registrant’s Common Stock, par value $0.001.

FORM 10-Q

CRIMSON EXPLORATION INC.

FOR THE QUARTER ENDED JUNE 30, 2012

Table of Contents
	Page

Part I:Financial Information

Item 1.Financial Statements
Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011	4
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2012	5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011	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	26

Item 4.Controls and Procedures	27

Part II:Other Information

Item 1.Legal Proceedings	28

Item 1A.Risk Factors	28

Item 2.Unregistered Sales of Equity Securities and Use Of Proceeds	28

Item 3.Defaults Upon Senior Securities	28

Item 4.Mine Safety Disclosures	28

Item 5.Other Information	29

Item 6.Exhibits	29

Signatures	31

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	June 30,			December 31,
	2012			2011
	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Accounts receivable, net of allowance of $547,184 and $579,143, respectively		14,435,958			16,059,667
Prepaid expenses		717,058			473,616
Derivative instruments		5,726,617			4,538,897
Deferred tax asset, net		247,346			—
Total current assets		21,126,979			21,072,180

PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method of accounting)		722,429,976			663,414,446
Other property and equipment		3,334,045			3,345,798
Accumulated depreciation, depletion and amortization		(298,835,052	)		(269,978,945	)
Total property and equipment, net		426,928,969			396,781,299

NONCURRENT ASSETS
Deposits		34,743			34,743
Debt issuance cost		1,248,164			1,140,031
Derivative instruments		1,033,677			—
Deferred tax asset, net		16,872,976			17,297,621
Total noncurrent assets		19,189,560			18,472,395

TOTAL ASSETS	$	467,245,508		$	436,325,874

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	43,613,937		$	49,539,258
Accrued liabilities		14,453,729			16,131,324
Asset retirement obligations		956,736			935,705
Derivative instruments		—			290,703
Deferred tax liability, net		—			189,146
Total current liabilities		59,024,402			67,086,136

NONCURRENT LIABILITIES
Long-term debt		227,694,428			190,041,933
Asset retirement obligations		9,882,294			9,071,064
Other noncurrent liabilities		596,365			621,043
Total noncurrent liabilities		238,173,087			199,734,040

Total liabilities		297,197,489			266,820,176

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Common stock (par value $0.001; 200,000,000 shares authorized; 46,254,579 and 45,270,768 shares issued and 46,071,284 and 45,129,407 shares outstanding, respectively)		46,254			45,271
Additional paid-in capital		244,662,869			243,484,877
Retained deficit		(73,840,436	)		(73,352,170	)
Treasury stock (at cost, 183,295 and 141,361 shares, respectively)		(820,668	)		(672,280	)
Total stockholders’ equity		170,048,019			169,505,698

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	467,245,508		$	436,325,874

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011

OPERATING REVENUES
Crude oil sales	$	21,505,766		$	9,437,066		$	38,398,380		$	16,852,709
Natural gas sales		6,051,551			15,538,315			13,120,665			30,263,264
Natural gas liquids sales		2,966,694			4,689,325			5,691,545			10,170,752
Total operating revenues		30,524,011			29,664,706			57,210,590			57,286,725

OPERATING EXPENSES
Lease operating expenses		3,603,046			4,657,344			8,240,431			8,687,922
Production and ad valorem taxes		(2,488,997	)		1,958,269			(1,080,256	)		3,838,475
Exploration expenses		48,895			289,595			349,591			381,209
Depreciation, depletion and amortization		14,675,882			14,385,639			29,137,944			27,866,568
Impairment and abandonment of oil and gas properties		806,067			3,965,511			1,482,541			9,410,025
General and administrative		4,525,720			4,058,859			9,297,177			8,227,722
Gain on sale of assets		—			—			(8,900	)		—
Total operating expenses		21,170,613			29,315,217			47,418,528			58,411,921

INCOME (LOSS) FROM OPERATIONS		9,353,398			349,489			9,792,062			(1,125,196	)

OTHER INCOME (EXPENSE)
Interest expense, net of amount capitalized		(6,212,806	)		(6,247,756	)		(12,457,988	)		(12,982,584	)
Other income and financing cost		(103,544	)		(457,186	)		(346,287	)		(1,154,879	)
Unrealized (loss) gain on derivative instruments		3,037,733			2,068,515			2,512,100			(2,163,290	)
Total other income (expense)		(3,278,617	)		(4,636,427	)		(10,292,175	)		(16,300,753	)

INCOME (LOSS) BEFORE INCOME TAXES		6,074,781			(4,286,938	)		(500,113	)		(17,425,949	)

Income tax (expense) benefit		(2,163,962	)		1,460,375			11,847			6,053,424

NET INCOME (LOSS)	$	3,910,819		$	(2,826,563	)	$	(488,266	)	$	(11,372,525	)

NET INCOME (LOSS) PER SHARE
Basic	$	0.09		$	(0.06	)	$	(0.01	)	$	(0.25	)
Diluted	$	0.09		$	(0.06	)	$	(0.01	)	$	(0.25	)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		44,134,330			45,188,542			44,055,639			45,065,402
Diluted		44,992,883			45,188,542			44,484,917			45,065,402

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2012 (UNAUDITED)

	NUMBER OF SHARES OF					ADDITIONAL								TOTAL
	COMMON STOCK			COMMON STOCK		PAID-IN CAPITAL		RETAINED DEFICIT			TREASURY STOCK			STOCKHOLDERS’ EQUITY
BALANCE, DECEMBER 31, 2011		45,129,407		$	45,271	$	243,484,877	$	(73,352,170	)	$	(672,280	)	$	169,505,698
Current period net loss		—			—		—		(488,266	)		—			(488,266	)
Share-based compensation		983,811			983		1,177,992		—			—			1,178,975
Treasury stock		(41,934	)		—		—		—			(148,388	)		(148,388	)
BALANCE, JUNE 30, 2012		46,071,284		$	46,254	$	244,662,869	$	(73,840,436	)	$	(820,668	)	$	170,048,019

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	For The Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(488,266	)	$	(11,372,525	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		29,137,944			27,866,568
Asset retirement obligations		(39,435	)		(70,250	)
Stock compensation expense		1,172,022			954,258
Amortization of financing costs and discounts		772,201			1,436,490
Deferred income taxes		(11,847	)		(6,053,424	)
Impairment and abandonment of oil and gas properties		1,482,541			9,410,025
Gain on sale of assets		(8,900	)		—
Unrealized (gain) loss on derivative instruments		(2,512,100	)		2,163,290
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, net		1,623,709			(4,032,879	)
Increase in prepaid expenses		(243,442	)		(33,419	)
Increase (decrease) in accounts payable and accrued liabilities		(7,627,594	)		10,804,633
Net cash provided by operating activities		23,256,833			31,072,767

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(60,288,459	)		(42,978,194	)
Acquisition of oil and gas properties		—			(940,345	)
Proceeds from sale of assets		400,900			—
Net cash used in investing activities		(59,887,559	)		(43,918,539	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on debt		(108,273,279	)		(72,240,239	)
Proceeds from debt		145,349,665			85,240,239
Debt issuance expenditures		(304,225	)		(46,214	)
Proceeds from issuance of common stock		6,953			29,912
Purchase of treasury stock		(148,388	)		(137,926	)
Net cash provided by financing activities		36,630,726			12,845,772

INCREASE IN CASH AND CASH EQUIVALENTS		—			—

CASH AND CASH EQUIVALENTS,
Beginning of period		—			—

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

Cash paid for interest	$	11,850,456		$	13,028,204
Cash paid for income taxes	$	—		$	—

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

CRIMSON EXPLORATION INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND NATURE OF OPERATIONS

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

2. BASIS OF PRESENTATION

Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S.”) for interim financial information and with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. Accordingly, they do not include all of the information and notes required by U.S. generally accepted accounting principles (“GAAP”) for complete annual financial statements. The accompanying consolidated financial statements at June 30, 2012 (unaudited) and December 31, 2011 and for the three and six months ended June 30, 2012 (unaudited) and 2011 (unaudited) contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three and six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

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, 2011.

The accompanying consolidated financial statements include Crimson Exploration Inc. and its wholly-owned subsidiaries: Crimson Exploration Operating, Inc., formed January 5, 2006, and LTW Pipeline Co., formed April 19, 1999. All material intercompany transactions and balances are eliminated upon consolidation. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.

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) valuation allowances associated with income taxes and accounts receivables; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations; (7) valuation of derivative instruments and (8) impairment

of oil and gas properties. 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, costless collars, put options and interest rate swaps. The fair value measurement of our unrealized commodity price and interest rate instruments were obtained from financial institutions and were reviewed by management using our hedge agreements and future commodity and interest rate 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 review oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs are typically not observable, we classify impairments of long-lived assets as a level 3 fair value measurement. 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. Because these significant factors are typically not observable, we classify asset retirement obligations as a level 3 fair value measurement. 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 measurements for assets and liabilities related to our derivative instruments that are measured at fair value on a recurring basis was as follows at June 30, 2012:

	Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	6,760,294	$	—	$	6,760,294	$	—
Commodity price contracts - liabilities		—		—		—		—
Total	$	6,760,294	$	—	$	6,760,294	$	—

Fair value measurements for assets and liabilities related to our derivative instruments that are measured at fair value on a recurring basis was as follows at December 31, 2011:

	Total			Fair Value Measurements Using
	Carrying Value			Level 1		Level 2			Level 3
Derivatives
Commodity price contracts - assets	$	4,538,897		$	—	$	4,538,897		$	—
Commodity price contracts - liabilities		(290,703	)		—		(290,703	)		—
Total	$	4,248,194		$	—	$	4,248,194		$	—

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 $6.8 million and $4.2 million at June 30, 2012 and December 31, 2011, respectively. As a result of these agreements, we recorded non-cash unrealized gains for unsettled contracts of $2.5 million and losses of $2.2 million for the six months ended June 30, 2012 and 2011, 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 and as an (increase) decrease in interest expense for our interest rate swaps. Our final interest rate swap terminated on May 8, 2011.

In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our crude oil and natural gas production, to reduce our sensitivity to volatile commodity prices, and with respect to portions of our debt, to reduce our sensitivity to volatile interest rates. 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 our debt and provide only partial protection against declines in commodity prices and increases in interest rates, respectively. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our hedging programs in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.

We use a mix of commodity swaps, put options, costless collars and interest rate swaps to accomplish our hedging strategy. Derivative assets and liabilities with the same counterparty, subject to contractual

terms which provide for net settlement, are reported on a net basis on our consolidated balance sheets. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, and specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. We believe our counterparty risk is low in part because of the offsetting relationship we have with each of our counterparties provided for in our revolving credit agreement and various hedge contracts. See Note 4 — “Fair Value Measurements” for further information.

The following derivative contracts were in place at June 30, 2012:

Crude Oil		Volume/Month (3)	Price/Unit		Fair Value
Jul 2012-Dec 2012	Collar	5,100 Bbls	$80.00-$107.30 (1)	$	70,892
Jul 2012-Dec 2012	Collar	5,000 Bbls	$85.00-$102.70 (1)		111,320
Jul 2012-Dec 2012	Collar	4,500 Bbls	$90.00-$110.46 (1)		184,538
Jul 2012-Sep 2012	Swap	8,000 Bbls	$99.28 (1)		330,390
Jul 2012-Dec 2012	Swap	10,000 Bbls	$114.85 (2)		1,022,622
Oct 2012-Dec 2012	Swap	6,000 Bbls	$98.05 (1)		201,621
Jan 2013-Dec 2013	Swap	14,000 Bbls	$101.25 (1)		2,161,281

Natural Gas
Jul 2012-Dec 2012	Put	320,000 Mmbtu	$5.00		2,721,955
Jul 2012-Dec 2012	Collar	165,000 Mmbtu	$2.50-$3.55		(17,554	)
Jan 2013-Dec 2013	Collar	75,000 Mmbtu	$3.00-$4.25		(26,771	)
Total net fair value of derivative instruments				$	6,760,294

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

(2)	Commodity derivative based on Brent crude oil

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

After June 30, 2012, we entered into a 75,000 Mmbtu/month natural gas collar for 2013, with a $3.25 put price and a $4.00 call price, as part of our continuing hedging strategy.

The following table details the effect of derivative contracts on the Consolidated Statements of Operations for the six months ended June 30, 2012 and 2011, respectively:

Contract Type	Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Recognized in Income
		Three months ended June 30,						Six months ended June 30,
		2012			2011			2012			2011
Crude oil contracts	Crude oil sales	$	586,360		$	(1,237,635	)	$	424,673		$	(2,115,255	)
Natural gas contracts	Natural gas sales		1,990,720			2,398,897			3,526,180			5,110,922
Natural gas liquids contracts	Natural gas liquids sales		—			(85,369	)		—			(93,475	)
Interest rate contracts	Interest expense		—			(421,423	)		—			(1,410,764	)
	Realized gain	$	2,577,080		$	654,470		$	3,950,853		$	1,494,428

Crude oil contracts	Unrealized (loss) gain on derivative instruments	$	5,724,945		$	3,301,525		$	4,192,815		$	809,778
Natural gas contracts	Unrealized (loss) gain on derivative instruments		(2,687,212	)		(1,499,446	)		(1,680,715	)		(4,151,365	)
Natural gas liquids contracts	Unrealized (loss) gain on derivative instruments		—			(153,482	)		—			(214,443	)
Interest rate contracts	Unrealized (loss) gain on derivative instruments		—			419,918			—			1,392,740
	Unrealized gain (loss)	$	3,037,733		$	2,068,515		$	2,512,100		$	(2,163,290	)

6. OIL AND GAS PROPERTIES

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

	Three months ended				Six months ended
	June 30,				June 30,
	2012		2011		2012		2011
Impairment and abandonment of proved properties	$	—	$	—	$	—	$	—
Impairment and abandonment of unproved properties		806,067		3,965,511		1,482,541		9,410,025
	$	806,067	$	3,965,511	$	1,482,541	$	9,410,025

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

2011 Asset Impairments. Non-cash impairments of unproved properties for the six months ended June 30 include $8.1 million related to our East Texas acreage and $1.3 million related to individually insignificant acreage. There were no impairments or abandonments of proved properties.

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:

Beginning January 1, 2012 liability	$	10,006,769
Accretion expense		250,367
Liabilities incurred		356,674
Liabilities settled		(265,095	)
Revisions		490,315
Ending June 30, 2012 liability	$	10,839,030

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 November 1, 2012. As of June 30, 2012, we had $58.1 million outstanding, with remaining availability of $41.9 million under our Senior Credit Agreement.

On May 17, 2012, we entered into a seventh amendment (the "Seventh Amendment") to our Senior Credit Agreement. The Seventh Amendment provides, among other things, for: (i) an extension of the maturity date of borrowings under the Senior Credit Agreement to May 31, 2015; (ii) decreasing (x) the applicable margin rate to between 1.75% and 2.75% for Libor Loans and to between 0.75% and 1.75% for Base Rate Loans and (y) the revolving credit commitment fee to between 0.375% and 0.500%, each of which is based on the borrowing base utilization; (iii) a revision to the minimum interest coverage ratio of EBITDAX to interest expense for the four trailing fiscal quarters to be not less than 2.50x as of the end of any fiscal quarter; (iv) a revision to the sale of mortgaged properties covenant to permit dispositions of properties not to exceed five percent of the borrowing base between borrowing base redeterminations; and (v) a revision to the limitation on hedging covenant to permit us to hedge, for the successive twelve month period, notional volumes not to exceed the greater of 80% of estimated production from proved developed producing reserves and 80% of reasonably anticipated production.

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 June 30, 2012, we had a principal amount of $175.0 million outstanding, with a discount of $5.4 million using the estimated market value interest rate at the time of issuance, for a net reported balance of $169.6 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 under 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, 2011 for a more detailed description of our Credit Agreements and the covenants under the Credit Agreements. At June 30, 2012, we were in compliance with the aforementioned financial covenants.

9. STOCKHOLDERS’ EQUITY

In the six months ended June 30, 2012, 303,016 shares of restricted Common Stock vested, of which 41,934 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 six months we also had 27,965 unvested shares of restricted Common Stock forfeited due to employee terminations. 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 six months ended June 30, 2012 as incentive-based equity compensation under the 2005 Stock Incentive Plan. We also granted 54,879 shares of restricted Common Stock to three members of our board of directors as compensation pursuant to the revised Director Compensation Plan and 6,000 shares of restricted Common Stock to new employees as part of their total compensation package.

In the six months ended June 30, 2011, 235,413 shares of restricted Common Stock previously issued pursuant to the long-term incentive plan vested, of which 32,831 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 six months we also had 139,040 unvested shares of restricted Common Stock forfeited due to employee terminations. We also issued 12,463 shares pursuant to stock option exercises. Discretionary grants of 366,633 shares of unvested restricted Common Stock were made to our employees during the six months as incentive-based equity compensation under the 2005 Stock Incentive Plan. We also granted 39,267 shares of restricted Common Stock to three members of our board of directors as compensation pursuant to the Director Compensation Plan and 7,205 shares of restricted Common Stock to a new employee as part of his total compensation package.

10. INCOME TAXES

Income tax benefit for the six months ended June 30, 2012 was approximately $12 thousand compared to an income tax benefit of $6.1 million for the six months ended June 30, 2011. 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 our 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 our net operating loss carryforwards to reduce future income tax obligations.

11. RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Not Yet Adopted

In December 2011, the FASB issued Accounting Standards Update No. 2011—11 “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities”. 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. The accounting update is effective for interim and annual periods beginning on or after January 1, 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 2012 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 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-looking Statements

The following discussion should be read in conjunction with the consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis reported on our Annual Report on Form 10-K for the year ended December 31, 2011. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties.

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

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

·	reserve potential;

·	business strategy;

·	estimates of future commodity prices;

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

·	expansion and growth of our business and operations;

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

·	acquisitions of crude oil and natural gas properties;

·	production of crude oil and natural gas reserves;

·	exploration prospects;

·	wells to be drilled and drilling results;

·	operating results and working capital;

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

·	future methods and types of financing.

We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For a discussion on risk factors affecting our business, see the information in “ITEM 1A. Risk Factors” contained in our Annual Report filed on Form 10-K for the year ended December 31, 2011, as filed with the Securities and Exchange Commission.

Overview

We are an independent energy company engaged in the acquisition, exploitation, exploration and development of crude oil and natural gas properties. We have historically focused our operations in 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 expanded our strategic focus to include longer reserve life resource plays in East Texas and South Texas that we believe provide significant long-term growth potential from multiple formations. Our operating revenues are derived from crude oil, natural gas and natural gas liquids sales that are proceeds from the sale of crude oil, natural gas and natural gas liquids production and realization of associated commodity derivatives.

Results of Operations

The following is a discussion of our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q.

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

Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Revenues

	Three months ended June 30,
	2012		2011		Change			Percent Change
Operating revenues:	(in millions, except percentages)
Crude oil sales	$	21.5	$	9.4	$	12.1			128.7%
Natural gas sales		6.0		15.6		(9.6	)		-61.5%
Natural gas liquids sales		3.0		4.7		(1.7	)		-36.2%
Operating revenues	$	30.5	$	29.7	$	0.8			2.7%

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 $30.5 million for the second quarter of 2012 compared to $29.7 million for the second quarter of 2011, a slight increase resulting primarily from a more than 100% increase in oil production, offset by lower high-rate gas production due to our focus on drilling oil and liquids rich wells and a 36% decrease in realized natural gas prices.

Production

	Three months ended June 30,
	2012		2011		Change			Percent Change
Sales volumes:
Crude oil (Bbl)		197,185		96,522		100,663			104.3%
Natural gas (Mcf)		2,001,086		3,268,416		(1,267,300	)		-38.8%
Natural gas liquids (Bbl)		82,520		97,976		(15,456	)		-15.8%
Natural gas equivalents (Mcfe)		3,679,316		4,435,404		(756,088	)		-17.0%

Quarterly production was approximately 3.7 Bcfe for the second quarter of 2012 compared to approximately 4.4 Bcfe for the second quarter of 2011. On a daily basis, we produced an average of 40,432 Mcfe for the second quarter of 2012 compared to an average of 48,741 Mcfe for the second quarter of 2011, a decrease in equivalent volumes due to our shift to drilling lower rate, but higher value, oil and liquids rich wells in 2012.

Average Sales Prices

	Three months ended June 30,
	2012		2011		Change			Percent Change
Average sales prices (before hedging):
Crude oil (Bbl)	$	106.09	$	110.59	$	(4.50	)		-4.1%
Natural gas (Mcf)		2.03		4.02		(1.99	)		-49.5%
Natural gas liquids (Bbl)		35.95		48.73		(12.78	)		-26.2%
Natural gas equivalents (Mcfe)		7.60		6.45		1.15			17.8%

	Three months ended June 30,
	2012		2011		Change			Percent Change
Average sales prices (after hedging):
Crude oil (Bbl)	$	109.06	$	97.77	$	11.29			11.5%
Natural gas (Mcf)		3.02		4.75		(1.73	)		-36.4%
Natural gas liquids (Bbl)		35.95		47.86		(11.91	)		-24.9%
Natural gas equivalents (Mcfe)		8.30		6.69		1.61			24.1%

Crude oil, natural gas and natural gas liquids prices are reported net of the realized effects of our hedging agreements. We realized gains of $0.6 million on our crude oil and natural gas liquids hedges and $2.0 million on our natural gas hedges in the second quarter of 2012, compared to realized losses of $1.3 million for crude oil and natural gas liquids hedges and gains of $2.4 million for natural gas hedges in the second quarter of 2011. The increase in realized hedging results for 2012 was primarily due to more favorable crude oil and natural gas hedges in place.

Costs and Expenses

	Three months ended June 30,
	2012			2011		Change			Percent Change
Selected operating expenses:	(in millions, except percentages)
Lease operating expenses	$	3.6		$	4.7	$	(1.1	)		-23.4%
Production and ad valorem taxes		(2.5	)		2.0		(4.5	)	NM
Exploration expenses		—			0.3		(0.3	)		-100.0%
General and administrative		3.9			3.6		0.3			8.3%
Operating expenses (cash)		5.0			10.6		(5.6	)		-52.8%
Depreciation, depletion & amortization		14.7			14.4		0.3			2.1%
Share-based compensation (1)		0.6			0.4		0.2			50.0%
Selected operating expenses (2)	$	20.3		$	25.4	$	(5.1	)		-20.1%

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

(2)	Exclusive of impairments, abandonments and gains or losses on sales of assets.

NM = not meaningful

	Three months ended June 30,
	2012			2011		Change			Percent Change
Selected operating expenses ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	0.98		$	1.05	$	(0.07	)		-6.7%
Production and ad valorem taxes		(0.68	)		0.44		(1.12	)	NM
Exploration expenses		0.01			0.07		(0.06	)		-85.7%
General and administrative (1)		1.06			0.82		0.24			29.3%
Operating expenses (cash)		1.37			2.38		(1.01	)		-42.4%
Depreciation, depletion & amortization		3.99			3.24		0.75			23.1%
Share-based compensation (1)		0.17			0.10		0.07			70.0%
Selected operating expenses (2)	$	5.53		$	5.72	$	(0.19	)		-3.3%

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

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

NM = not meaningful

Lease Operating Expenses. Lease operating expenses for the second quarter of 2012 were $3.6 million ($0.98 per Mcfe) compared to $4.7 million ($1.05 per Mcfe) in the second quarter of 2011, a decrease resulting primarily from the improved methodology of estimating expenses not yet billed by our service providers that was put in place in the third quarter of 2011.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the second quarter of 2012 were a credit of $2.5 million compared to expense of $2.0 million for the second quarter of 2011, a decrease primarily due to a $4.0 million credit for certain 2007-2011 severance taxes filed for and received from the State of Texas for allowed marketing costs.

Exploration Expenses. Exploration expenses were $49 thousand in the second quarter of 2012 compared to $0.3 million for the second quarter of 2011. The decrease in exploration expenses was primarily due to lower settled asset retirement obligations incurred in the second quarter of 2012 compared to the second quarter of 2011.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the second quarter of 2012 was $14.7 million compared to $14.4 million for the second quarter of 2011, an increase due to a higher DD&A rate associated with our recently developed crude oil wells, offset in part by lower production.

Impairment and Abandonment of Oil and Gas Properties. Non-cash impairment and abandonment of oil and gas properties for the second quarter of 2012 was $0.8 million compared to $4.0 million for the second quarter of 2011. The 2011 impairment was primarily the result of expiring leases in the individually significant pool for East Texas.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $4.5 million ($1.23 per Mcfe) for the second quarter of 2012 compared to $4.1 million ($0.92 per Mcfe) for the second quarter of 2011. Included in G&A expense is a non-cash stock expense of $0.6 million ($0.17 per Mcfe) and $0.4 million ($0.10 per Mcfe) in the second quarters of 2012 and 2011, respectively. G&A expenses increased primarily due to higher personnel and facility costs.

Interest Expense. Interest expense was $6.2 million for the second quarters of 2012 and 2011. Total interest expense remained flat primarily due to the absence of interest rate hedge settlements in 2012. Capitalized interest expense for the second quarters of 2012 and 2011 was zero and approximately $0.1 million, respectively.

Other Income and Financing Costs. Other income and financing costs were $0.1 million for the second quarter 2012 compared to $0.5 million for the second quarter of 2011. These amounts consist primarily of the amortization of capitalized costs associated with our credit facilities and commitment fees related to the undrawn availability under our revolving credit agreement.

Unrealized Gain (Loss) on Derivative Instruments. The non-cash unrealized gain on derivative instruments for the second quarter of 2012 was $3.0 million compared to $2.1 million for the second quarter of 2011. With the expiration of our interest rate swaps in May 2011, our remaining derivative instruments are commodity price based only. 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 hedged.

Income Tax. Net income before taxes was $6.1 million for the second quarter of 2012 compared to a net loss before taxes of $4.3 million in the second quarter of 2011. After adjusting for permanent tax differences, we recorded an income tax expense of $2.2 million for the second quarter of 2012, compared to an income tax benefit of $1.5 million for the second quarter of 2011.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Revenues

	Six months ended June 30,
	2012		2011			Change			Percent Change
Operating revenues:	(in millions, except percentages)
Crude oil sales	$	38.4		$	16.9	$	21.5			127.2%
Natural gas sales		13.1			30.2		(17.1	)		-56.6%
Natural gas liquids sales		5.7			10.2		(4.5	)		-44.1%
Operating revenues	$	57.2		$	57.3	$	(0.1	)		-0.2%

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 hedging instruments, were $57.2 million for the first six months of 2012 comparable to the 2011 revenues as oil volumes doubled, while natural gas revenue was lower due to a 34% decrease in production and realized prices, as we shifted our drilling focus to oil and liquids rich wells.

Production

	Six months ended June 30,
	2012		2011		Change			Percent Change
Sales volumes:
Crude oil (Bbl)		355,818		184,251		171,567			93.1%
Natural gas (Mcf)		4,165,211		6,286,764		(2,121,553	)		-33.7%
Natural gas liquids (Bbl)		145,056		222,075		(77,019	)		-34.7%
Natural gas equivalents (Mcfe)		7,170,455		8,724,720		(1,554,265	)		-17.8%

Production was approximately 7.2 Bcfe for the first six months of 2012 compared to 8.7 Bcfe for the first six months of 2011. On a daily basis, we produced an average of 39,398 Mcfe in the first six months of 2012 compared to an average of 48,203 Mcfe in the first six months of 2011, a decrease in equivalent volumes due to our shift to drilling lower rate, but higher value, oil and liquids rich wells in 2012.

Average Sales Prices

	Six months ended June 30,
	2012		2011		Change			Percent Change
Average sales prices (before hedging):
Crude oil (Bbl)	$	106.72	$	102.93	$	3.79			3.7%
Natural gas (Mcf)		2.30		4.00		(1.70	)		-42.5%
Natural gas liquids (Bbl)		39.24		46.22		(6.98	)		-15.1%
Natural gas equivalents (Mcfe)		7.43		6.23		1.20			19.3%

	Six months ended June 30,
	2012		2011		Change			Percent Change
Average sales prices (after hedging):
Crude oil (Bbl)	$	107.92	$	91.47	$	16.45			18.0%
Natural gas (Mcf)		3.15		4.81		(1.66	)		-34.5%
Natural gas liquids (Bbl)		39.24		45.80		(6.56	)		-14.3%
Natural gas equivalents (Mcfe)		7.98		6.57		1.41			21.5%

Crude oil, natural gas and natural gas liquids prices are reported net of the realized effect of our hedging agreements. We realized gains of $0.4 million on our crude oil hedges and gains of $3.5 million on our natural gas hedges in the first six months of 2012, compared to realized losses of $2.2 million on our crude oil hedges and gains of $5.1 million on our natural gas hedges in the first six months of 2011. The increase in realized hedging results for 2012 was primarily due to more favorable crude oil and natural gas hedges in place.

Costs and Expenses

	Six months ended June 30,
	2012			2011		Change			Percent Change
Selected operating expenses:	(in millions, except percentages)
Lease operating expenses	$	8.2		$	8.7	$	(0.5	)		-5.7%
Production and ad valorem taxes		(1.1	)		3.8		(4.9	)	NM
Exploration expenses		0.3			0.4		(0.1	)		-25.0%
General and administrative (1)		8.1			7.3		0.8			11.0%
Operating expenses		15.5			20.2		(4.7	)		-23.3%
Depreciation, depletion & amortization		29.1			27.9		1.2			4.3%
Share-based compensation (1)		1.2			1.0		0.2			20.0%
Selected operating expenses (2)	$	45.8		$	49.1	$	(3.3	)		-6.7%

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

(2)	Exclusive of impairments, abandonments and gains or losses on sales of assets.

NM = not meaningful

	Six months ended June 30,
	2012			2011		Change			Percent Change
Selected operating expenses ($ per Mcfe):	(in millions, except percentages)
Lease operating expenses	$	1.15		$	1.00	$	0.15			15.0%
Production and ad valorem taxes		(0.15	)		0.44		(0.59	)	NM
Exploration expenses		0.05			0.04		0.01			25.0%
General and administrative (1)		1.13			0.83		0.30			36.1%
Operating expenses		2.18			2.31		(0.13	)		-5.6%
Depreciation, depletion & amortization		4.06			3.19		0.87			27.3%
Share-based compensation (1)		0.16			0.11		0.05			45.5%
Selected operating expenses (2)	$	6.40		$	5.61	$	0.79			14.1%

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

(2)	Exclusive of impairments, abandonments and gains or losses on sales of assets.

NM = not meaningful

Lease Operating Expenses. Lease operating expenses for the first six months of 2012 were $8.2 million ($1.15 per Mcfe) compared to $8.7 million ($1.00 per Mcfe) in the first six months of 2011, a decrease resulting from the improved methodology of estimating expenses not yet billed by our service providers that was put in place in the third quarter of 2011. The increase on a per Mcfe basis is primarily due to the lower equivalent production volumes and higher lifting costs resulting from our shift to drilling oil and liquids rich wells.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the first six months of 2012 were a credit of $1.1 million compared to expense of $3.8 million for the first six months of 2011, a decrease primarily due to a $4.0 million credit for certain 2007-2011 severance taxes filed for and received from the State of Texas for allowed marketing costs.

Exploration Expenses. Exploration expenses were $0.3 million in the first six months of 2012 compared to $0.4 million for the first six months of 2011, a decrease primarily due to lower settled asset retirement obligations.

Depreciation, Depletion and Amortization (“DD&A”). DD&A expense for the first six months of 2012 was $29.1 million compared to $27.9 million for the first six months of 2011, a slight increase primarily due to a higher DD&A rate associated with our recently developed crude oil wells, offset in part by lower equivalent production.

Impairment and Abandonment of Oil and Gas Properties. Non-cash impairment and abandonment of oil and gas properties for the first six months of 2012 was $1.5 million compared to $9.4 million for the first six months of 2011. The 2011 impairment was primarily the result of expiring leases in the individually significant pool for East Texas.

General and Administrative (“G&A”) Expenses. Total G&A expenses were $9.3 million ($1.30 per Mcfe) for the first six months of 2012 compared to $8.2 million ($0.94 per Mcfe) for the first six months of 2011, which includes non-cash stock expense of $1.2 million ($0.16 per Mcfe) and $1.0 million ($0.11 per Mcfe) for the first six months of 2012 and 2011, respectively. G&A expenses increased primarily due to higher personnel and facility costs.

Interest Expense. Interest expense was $12.5 million ($1.74 per Mcfe) for the first six months of 2012 compared to $13.0 million ($1.49 per Mcfe) for the first six months of 2011. Total interest expense decreased primarily due to the absence of interest rate hedge settlements in 2012. Capitalized interest expense for the first six months of 2012 and 2011 was approximately zero and $0.2 million, respectively.

Other Income and Financing Costs. Other income and financing costs were $0.3 million for the first six months of 2012 compared with $1.2 million for the first six months of 2011. These amounts consist primarily of the amortization of capitalized costs associated with our credit facilities and commitment fees related to the undrawn availability under our revolving credit agreement.

Unrealized Gain (Loss) on Derivative Instruments. The non-cash unrealized gain for the first six months of 2012 was $2.5 million compared with a non-cash unrealized loss of $2.2 million for the first six months of 2011. Unrealized gain or loss is the change in the mark-to-market exposure under our commodity price hedging contracts and our interest rate swaps during the period. Unrealized gain or loss will vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities hedged.

Income Tax. Our net loss before taxes was $0.5 million for the first six months of 2012 compared to $17.4 million for the first six months of 2011. After adjusting for permanent tax differences, we recorded an income tax benefit of approximately $12 thousand for the first six months of 2012, compared to $6.1 million for the first six months of 2011.

Liquidity and Capital Resources

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our revolving credit facility. To the extent our cash requirements exceed our sources of liquidity, we will be required to fund our cash requirements through other means, such as through debt and equity financing activities or asset monetizations, or the curtailment of capital expenditures.

Liquidity and Cash Flow

The following table provides the components and changes in working capital as of June 30, 2012 and December 31, 2011.

	June 30, 2012			December 31, 2011			Change
Current assets	(in millions)
Accounts receivable, net	$	14.5		$	16.1		$	(1.6	)
Prepaid expenses		0.7			0.5			0.2
Derivative instruments		5.7			4.5			1.2
Deferred tax asset, net		0.2			—			0.2
Total current assets		21.1			21.1			—

Current liabilities
Accounts payable and accrued liabilities (1)		58.0			65.7			(7.7	)
Asset retirement obligations		1.0			0.9			0.1
Derivative instruments		—			0.3			(0.3	)
Deferred tax liability, net		—			0.2			(0.2	)
Total current liabilities		59.0			67.1			(8.1	)

Working capital (deficit)	$	(37.9	)	$	(46.0	)	$	8.1

(1) Reflects impact of reduced drilling activity in June 2012 compared to December 2011.

The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from internal and external sources, for the six months ended June 30, 2012 and 2011, respectively.

	Six months ended June 30,
	2012			2011
Financial Measures	(in millions)
Net cash provided by operating activities	$	23.3		$	31.1
Net cash used in investing activities		(59.9	)		(43.9	)
Net cash provided by financing activities		36.6			12.8
Cash and cash equivalents		—			—

During the first six months of 2012, the net cash provided by operating activities, before changes in working capital, increased to $29.5 million, from $24.3 million for the first six months of 2011, primarily due to the severance tax credit received.

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

Net cash provided by financing activities, which consists primarily of net borrowings/repayments on our revolving credit agreement, increased primarily due to temporary funding of our accelerated 2012 drilling activity.

See the Consolidated Statements of Cash Flows for further details.

Capital Resources

We maintain a senior secured revolving credit facility with Wells Fargo Bank, National Association (“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 November 1, 2012. The credit agreement also provides for the issuance of letters-of-credit up to a $5.0 million sub-limit. As of June 30, 2012, we had $58.1 million outstanding, with remaining availability of $41.9 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. 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 0.50%, which fee accrues and is payable quarterly in arrears.

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 and renew.

We utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural gas and natural gas liquids production. We use a series of swaps, put options and costless collars to accomplish our commodity hedging position. We currently have 4.1 Bcfe of production hedged for 2012, consisting of 190 MBbl of crude oil hedges and 2.9 Bcf of natural gas hedges at average floor prices of $97.40/Bbl and $4.15/Mmbtu, respectively. We also have 2.8 Bcfe of equivalent production

hedged for 2013, consisting of 168 MBbl of crude oil hedges and 1.8 Bcf of natural gas hedges at average floor prices of $101.25/Bbl and $3.13/Mmbtu, respectively.

Future Capital Requirements

Our future crude oil, natural gas 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 environment, and the superior economics from oil production, we will focus the majority of our capital expenditures on the development of our South Texas and Southeast Texas oil/liquids project 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 and planned capital development and to meet our debt service requirements for the next twelve months. We currently plan to limit our 2012 capital expenditures to an amount substantially comparable to our forecasted cash flow from operations for the year (prior to effects of changes in working capital); 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 2012 are on acreage that is currently held by existing production, therefore, we also possess the flexibility of reducing our capital expenditures, if deemed appropriate. 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, 2011.

Recent Accounting Pronouncements

evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are currently exposed to market risk primarily related to adverse changes in crude oil, natural gas 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 2011 Annual Report and Note 5 – Derivative Instruments included in Part I. Item 1. Financial Statements of this Form 10-Q.

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 crude oil, natural gas 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 crude oil, natural gas 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 derivative hedging program in light of increases in production, market conditions, commodity price forecasts, capital spending and debt service requirements.

At June 30, 2012, we had entered into swaps, put options and costless collars related to future crude oil and natural gas sales with a net fair value of $6.8 million. 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 $0.4 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 June 30, 2012, we did not have any outstanding interest rate swap 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 $0.6 million for a twelve month period, assuming current debt levels.

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

During the three months ended June 30, 2012, there has been no change to our internal controls over financial reporting that materially affected, or is reasonably likely to materially affect, these controls.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

From time to time, we are involved in litigation relating to claims arising out of our properties or operations or from disputes with vendors in the normal course of business.

See Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2011 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, 2011, 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 second quarter of 2012. 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
May 1-31, 2012	10,771	$	4.06	10,771	(1)
June 1-30, 2012	3,727	$	4.52	3,727	(1)
Total	14,498			14,498

(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. 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.

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		Registration Rights Agreement between Crimson Exploration Inc. and America Capital Energy corporation, dated as of December 22, 2010 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 28, 2010 File No. 001-12108)

#10.1		Amended and Restated Employment Agreement between Crimson Exploration Inc. and A. Carl Isaac effective as of April 18, 2012 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 19, 2012)

#10.2		Seventh Amendment, dated as of May 17, 2012, to the Amended and Restated Credit Agreement, dated as of May 31, 2007, among Crimson Exploration Inc., the guarantor party thereto, the lender parties thereto and Wells Fargo Bank, National Association

*#10.3		Summary terms of Director Compensation Plan, as amended, effective April 1, 2012

*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

Number		Description

*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

*101.PRE		XBRL Presentation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

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

SIGNATURES

Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CRIMSON EXPLORATION INC.

(Registrant)

Date:	August 8, 2012	By:	/s/ Allan D. Keel
			Allan D. Keel
			President and Chief Executive Officer

Date:	August 8, 2012	By:	/s/ E. Joseph Grady
			E. Joseph Grady
			Senior Vice President and Chief Financial Officer