CRIMSON EXPLORATION INC. - FORM 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8–K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of Earliest Event Reported): November 10, 2010

CRIMSON EXPLORATION INC.

(Exact Name of Registrant as Specified in Charter)

Delaware

(State or Other Jurisdiction of Incorporation)

001-12108

(Commission File Number)

20-3037840

(IRS Employer Identification No.)

717 Texas Ave., Suite 2900, Houston Texas 77002

(Address of Principal Executive Offices)

(713) 236-7400

(Registrant’s telephone number, including area code)

_____________________________________________________________________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 14d-2(b))

[] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02Results of Operations and Financial Condition.

On November 10, 2010, Crimson Exploration Inc. issued a press release announcing financial and operational results for the third quarter ended September 30, 2010. The press release is included in this report as Exhibit 99.1.

Crimson Exploration Inc. held an earnings conference call on November 11, 2010, to discuss financial and operational results for the third quarter ended September 30, 2010. A copy of the transcript of the earnings conference call is attached as Exhibit 99.2 to this current report on Form 8-K.

In accordance with General Instruction B.2 of Form 8-K, neither the press release nor the transcript shall be deemed “filed” for the purposes of Section 18 of the Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall such information and Exhibit be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act of 1934, each as amended, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01Financial Statements and Exhibits.

(d)

Exhibits

Exhibit Number	Description
99.1	Press Release dated November 10, 2010 (furnished herewith)
99.2	Transcript of Earnings Conference Call dated November 11, 2010 (furnished herewith)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.

		CRIMSON EXPLORATION INC.

Date:	November 12, 2010	/s/ E. Joseph Grady
		E. Joseph Grady
		Senior Vice President and Chief Financial Officer

Exhibit Index

Exhibit Number	Description
99.1	Press Release dated November 10, 2010 (furnished herewith)
99.2	Transcript of Earnings Conference Call dated November 11, 2010 (furnished herewith)

EXHIBIT 99.1

Crimson Exploration Announces Third Quarter 2010 Financial Results and Drilling Update

HOUSTON, November 10, 2010 (BUSINESS WIRE) -- Crimson Exploration Inc. (NasdaqGM:CXPO) today announced financial results for the third quarter and first nine months of 2010 and an update on recent drilling activity.

Summary Financial Results

The Company reported a net loss of $3.8 million, or ($0.10) per basic share outstanding, for the third quarter of 2010 compared to a net loss available to common stockholders of $9.7 million, or ($1.51) per basic share, for the third quarter of 2009. Exclusive of unrealized losses related to the mark to market valuation of our commodity price and interest rate hedges in each period, the net loss for the 2010 quarter would have been $3.0 million, or ($0.08) per share, compared to an adjusted net loss available to common stockholders of $3.4 million, or ($0.53) per share for the 2009 quarter. For the first nine months of 2010, the Company reported a net loss of $10.0 million, or ($0.26) per basic share, compared to a net loss available to common stockholders of $20.2 million, or ($3.20) per basic share for the 2009 period. Exclusive of unrealized losses related to derivative instruments for each nine month period, the net loss for 2010 would have been $10.2 million, or ($0.26) per share, compared to an adjusted net loss available to common stockholders of $9.0 million, or ($1.42) per share for the 2009 period. Basic shares outstanding for the quarters were 38,819,780 and 6,444,013 for 2010 and 2009, respectively, and for the first nine months were 38,655,038 and 6,301,280 for 2010 and 2009, respectively. The increase in the share count for 2010 is attributable to our public offering of common stock, and the simultaneous conversion of our preferred stock into common stock, in December 2009.

Revenues for the third quarter of 2010 were $24.5 million compared to revenues of $26.9 million in the prior year quarter. The decrease in revenue was due to slightly lower production and slightly lower average realized prices. Production for the third quarter of 2010 was approximately 3.4 Bcfe of natural gas equivalents, or 36,800 Mcfe per day, compared with production of 3.5 Bcfe, or 38,300 Mcfe per day, in the third quarter of 2009. Third quarter production was 22% higher than the second quarter 2010 daily average of 30,100 Mcfe due to new production from 2010 drilling in our Liberty County, Texas conventional program and our Haynesville/Mid-Bossier success in San Augustine County, Texas.

Average field sales prices for the third quarter of 2010, before the impact of realized hedging results, were $75.72 per barrel, $4.48 per Mcf, $34.60 per barrel and $5.63 per Mcfe for crude oil, natural gas, natural gas liquids and natural gas equivalents, respectively, up 21% on an equivalent basis compared to the 2009 quarter. Average realized sales prices for the 2010 quarter, including the impact of realized hedging results, were $84.76 per barrel, $6.47 per Mcf, $34.60 per barrel and $7.21 per Mcfe for crude oil, natural gas, natural gas liquids and natural gas equivalents, respectively, down 5% on an equivalent basis compared to the 2009 quarter. For the first nine months of 2010, average realized sales prices were up 4%, on an equivalent basis, compared to prices realized in the first nine months of 2009.

Lease operating expenses for the third quarter of 2010 were $3.6 million, or $1.06 per Mcfe, compared to $3.9 million, or $1.10 per Mcfe, in the third quarter of 2009. The cost per Mcfe for the 2010 third quarter improved over the year to date average of $1.27 per Mcfe due to the new production from success in our drilling program.

Production and ad valorem tax expenses for the third quarter of 2010 were $1.4 million, or $0.41 per Mcfe, compared to $1.6 million, or $0.44 per Mcfe, for the third quarter of 2009.

Depreciation, depletion and amortization (“DD&A”) expense for the third quarter of 2010 was $12.0 million, or $3.56 per Mcfe, compared to $13.4 million, or $3.81 per Mcfe, for the third quarter of 2009. DD&A expense per mcfe improved due to the success of our 2010 drilling program.

Exploration expense for the third quarter of 2010 was $1.3 million compared to $0.7 million for the third quarter of 2009. Exploration expense in 2010 resulted from lease expirations on certain conventional prospects in South Texas, while the 2009 expenses represented expensed geological and geophysical costs.

General and administrative expenses (“G&A”) were $4.5 million for the third quarter of 2010 compared to $3.8 million for the third quarter of 2009. Included in G&A expense is a non-cash stock expense of $0.5 million and $0.3 million for the third quarters ended 2010 and 2009, respectively. Recorded in the 2010 quarter was

approximately $0.7 million in incentive compensation for the 2010 year, while 2009 bonus compensation was not recorded until the fourth quarter.

Subsequent Event

As previously announced, on October 26, 2010, we closed on a private placement for the sale of Common Stock to America Capital Energy Corporation (“ACEC”), a private investor, whereby ACEC may purchase up to $30.0 million of newly issued Common Stock at a purchase price of $5.00 per share in a two step process. The first step of the process closed and we issued 4,250,000 shares of Common Stock, or 9.9% of the post-transaction outstanding shares of the Company, to ACEC for a total cash consideration of $21.25 million ($3 million of which was a deposit received at the end of September 2010, and which is reflected as an advance in the accounts payable line item on our September 30th balance sheet). At the first closing, we also entered into a 60-day option agreement with ACEC under which ACEC may acquire an additional 1,750,000 shares of a newly created series of preferred stock at $5.00 per share, for additional consideration of $8.75 million. The preferred stock will automatically convert into an equal number of shares of Common Stock on or before December 31, 2010. Under the terms of the preferred stock, ACEC would have the right to appoint a director to our board of directors prior to conversion. If the option is exercised and the preferred shares are converted to Common Stock, ACEC would own approximately 13.4% of our outstanding shares. We intend to use the net proceeds from the private placement for general corporate purposes, including the continued development of our significant inventory of drilling prospects.

Drilling Update

East Texas

The Gobi #1 (70% WI) and the Halbert Trust #1 (29% WI), both targeting the Mid-Bossier Shale in San Augustine, Co., have commenced fracing operations with initial production expected by the end of November. The Gobi #1, located in the Bruin Prospect area, was drilled to a total measured depth of 18,000’ with a 4,400’ lateral. Crimson anticipates conducting 14 frac stages. The Halbert Trust #1, operated by Eagle Oil & Gas and located in the Fairway Farms Prospect area, was drilled to a total measured depth of 17,786’ with a 4,200’ lateral. Eagle has just completed the 14 stage frac and is preparing to flow the well to sales.

In the Tiger Prospect area, Crimson is currently drilling the Bengal #1 (37.5% WI) below 15,400’ in its planned 4,500’ lateral targeting the Mid-Bossier Shale with completion operations scheduled for the end of December. The Bengal #1 represents Crimson’s first operated well in Sabine County, TX.

The Crimson Blue #1 (58.3% WI), located in the Bruin Prospect area, is expected to spud following the completion of drilling on the Bengal #1 and will target either the Haynesville Shale or Mid-Bossier Shale formations. The Blue #1 is expected to reach total measured depth by early first quarter 2011 with completion operations to begin shortly thereafter. The Blue #1 is approximately 1.5 miles north of the Grizzly #1 and approximately 1.5 miles west of the Kardell #1.

South Texas

The Windham #1 (20% WI), targeting the Eagle Ford Shale in Bee County, TX, has reached a total measured depth of 19,129’ with a 6,200’ lateral. Completion operations are scheduled to begin mid-December with first production expected in January 2011. The Born #1, located approximately 2.5 miles southeast of the Windham well in Bee County, was drilled to a total measured depth of 17,253’ with a 4,200’ lateral. Completion operations are scheduled to begin mid to late January with first production expected in late February 2011. Petrohawk Energy Corporation is the operator on both wells.

Completed Wells

In the third quarter, Crimson successfully brought three wells online that contributed to our growth in production. The Grizzly #1H (55% WI), targeting the Mid-Bossier Shale formation, commenced production at a gross restricted rate of 11,500 Mcfe per day. The Schwarz #2 (65% WI), targeting the Lower Cook Mountain sand, commenced production at a gross rate of 5,400 Mcf per day, 120 Barrels of condensate per day, and 216 Barrels of natural gas

liquids per day, or approximately 7.4 Mmcfe per day. The Catherine Henderson A-8 (66% WI), targeting the Upper Cook Mountain sand, commenced production at 6,900 Mcf per day, 445 barrels of condensate per day, and 565 barrels of natural gas liquids per day, or approximately 13.0 Mmcfepd. Due to the addition of these wells, Crimson grew production from 30,100 Mcfe per day in the second quarter of 2010 to 36,800 Mcfe per day in the third quarter of 2010, a 22% increase over the second quarter, and to an average rate of 42,400 Mcfe per day for the month of October 2010, a 41% increase over the second quarter average.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and nine month periods ended September 30, 2010 and 2009:

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2010		2009			%			2010		2009			%
Total Volumes Sold:
Natural gas (Mcf)		2,390,868		2,373,940			1	%		6,432,283		8,142,588			-21	%
Crude oil (barrels)		63,755		76,376			-17	%		178,825		264,170			-32	%
Natural gas liquids (barrels)		101,992		114,792			-11	%		243,859		334,303			-27	%
Natural gas equivalents (Mcfe)		3,385,350		3,520,948			-4	%		8,968,387		11,733,426			-24	%

Daily Sales Volumes:
Natural gas (Mcf)		25,988		25,804			1	%		23,561		29,826			-21	%
Crude oil (barrels)		693		830			-17	%		655		968			-32	%
Natural gas liquids (barrels)		1,109		1,248			-11	%		893		1,225			-27	%
Natural gas equivalents (Mcfe)		36,797		38,271			-4	%		32,851		42,980			-24	%

Average sales prices (before hedging):
Gas	$	4.48	$	3.24			38	%	$	4.61	$	3.92			18	%
Oil		75.72		66.57			14	%		76.40		52.80			45	%
NGLs		34.60		31.51			10	%		39.27		27.19			44	%
Mcfe		5.63		4.65			21	%		5.90		4.68			26	%

Average realized sales price (after hedging):
Gas	$	6.47	$	6.92			-7	%	$	6.76	$	6.77			0	%
Oil		84.76		87.85			-4	%		84.42		81.46			4	%
NGLs		34.60		31.51			10	%		39.27		27.19			44	%
Mcfe		7.21		7.60			-5	%		7.60		7.31			4	%

Selected Costs ($ per Mcfe):
Lease operating expenses	$	1.06	$	1.10			-4	%	$	1.27	$	1.15			10	%
Production and ad valorem taxes	$	0.41	$	0.44			-7	%	$	0.51	$	0.52			-2	%
Depreciation and depletion expense	$	3.56	$	3.81			-7	%	$	3.68	$	3.55			4	%
General and administrative expense (cash)	$	1.20	$	0.99			21	%	$	1.40	$	0.98			43	%
Interest	$	1.71	$	1.88			-9	%	$	1.83	$	1.39			31	%


Adjusted EBITDAX (1)	$	15,507,070	$	17,968,538			-14	%	$	40,054,757	$	55,161,084			-27	%

Capital expenditures
Property acquisition – proved	$	—	$	(11,366	)				$	—	$	(493,532	)
Leasehold acquisitions		1,190,556		114,658						6,200,604		1,490,381
Exploratory		52,311		4,708,158						716,538		5,329,830
Development		15,905,320		(54,850	)					32,290,340		9,641,898
Other		—		—						10,316		82,945
	$	17,148,187	$	4,756,600					$	39,217,798	$	16,051,522

(1) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).

CRIMSON EXPLORATION INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,		December 31,
	2010		2009
	(unaudited)
ASSETS
Current derivatives	$	11,063,206	$	9,937,697
Other current assets		15,844,972		14,773,246
Net property and equipment		398,092,542		393,127,727
Non-current derivatives		1,688,931		2,513,369
Other non-current assets		3,473,335		4,451,995

Total Assets	$	430,162,986	$	424,804,034

LIABILITIES AND STOCKHOLDERS' EQUITY
Current portion of long-term debt	$	1,662	$	19,014
Current derivatives		2,040,208		872,849
Other current liabilities		47,930,041		32,594,171
Long-term debt, net of current portion		196,274,986		192,749,751
Non-current derivatives		151,917		1,284,105
Other non-current liabilities		9,750,854		14,553,256
Total stockholders’ equity		174,013,318		182,730,888

Total Liabilities & Stockholders’ Equity	$	430,162,986	$	424,804,034

CRIMSON EXPLORATION INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

OPERATING REVENUES
Oil, gas and natural gas liquids sales	$	24,407,732		$	26,752,542		$	68,163,902		$	85,742,959
Operating overhead and other income		128,175			147,862			434,807			508,249
Total operating revenues		24,535,907			26,900,404			68,598,709			86,251,208

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

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

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

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

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

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

Dividends on preferred stock		—			(1,156,163	)		—			(3,353,150	)

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

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

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

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, amortization and exploration expenses. Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below, all of which will be required in determining our compliance with financial covenants under our Senior Credit Agreement and Second Lien Credit Agreement.

We have included EBITDAX and Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreements. We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results. Adjusted EBITDAX is a material component of the covenants that are imposed on us by our Senior Credit Agreement and Second Lien Credit Agreement. We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX. Non-compliance with the financial covenants contained in these credit agreements could result in a default, an acceleration in the repayment of amounts outstanding, and a termination of lending commitments. Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:

·	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

·	our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and

·	the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX and Adjusted EBITDAX are not presentations made in accordance with generally accepted accounting principles, or GAAP. As discussed above, we believe that the presentation of EBITDAX and adjusted EBITDAX in this release is appropriate. However, when evaluating our results, you should not consider EBITDAX and Adjusted EBITDAX in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss). EBITDAX and Adjusted EBITDAX have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations. Because other companies may calculate EBITDAX and Adjusted EBITDAX differently than we do, EBITDAX may not be, and Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

The following table reconciles net income to EBITDAX and Adjusted EBITDAX for the periods presented:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

Net income (loss)	$	(3,819,908	)	$	(8,586,126	)	$	(9,981,943	)	$	(16,816,587	)
Interest expense		5,785,042			6,633,642			16,387,881			16,349,300
Income (benefit) tax expense		(2,285,040	)		(4,826,137	)		(5,176,483	)		(9,080,238	)
Depreciation and amortization		12,035,848			13,400,031			32,973,530			41,599,314
Exploration expense		1,311,678			687,613			1,994,794			2,873,255
EBITDAX		13,027,620			7,309,023			36,197,779			34,925,044

Unrealized loss (gain) on derivative instruments		1,258,326			9,929,947			(265,899	)		17,237,909
Non-cash equity-based compensation charges		455,440			347,409			1,353,344			1,869,401
Amortization of deferred finance costs		776,137			382,159			2,349,167			1,109,805
(Gain) loss on sale of assets		(10,453	)		—			420,366			18,925
Adjusted EBITDAX	$	15,507,070		$	17,968,538		$	40,054,757		$	55,161,084

Updated Guidance for Fourth Quarter 2010

The Company is providing the following updated guidance for the fourth calendar quarter of 2010. Figures for lease operating expenses, production and ad valorem taxes, cash general and administrative expenses and DD&A are based on the midpoint of the production guidance range.

Fourth quarter 2010 production	40,000 – 43,000 mcfe per day

Lease operating expenses ($M)	$4,000 – $4,400

Production and ad valorem taxes	10% of actual prices

Cash G&A ($M)	$3,800 – $4,200

DD&A rate	$2.80 – $3.10 per mcfe

Teleconference Call

Crimson management will hold a conference call to discuss the information described in this press release on Thursday, November 11, 2010 at 9:30am Central Standard Time. Those interested in participating may do so by calling the following phone number: 1-(800) 768-6544, (International (785) 830-7990) and entering the following participation code 7755984. A replay of the call will be available from November 11, 2010 at 12:00pm CST through November 18, 2010 at 12:00pm CST by dialing toll free 1-(888) 203-1112, (International (719) 457-0820) and asking for replay ID code 7755984.

Crimson Exploration is a Houston, TX-based independent energy company engaged in the acquisition, development, exploitation and production of crude oil and natural gas, primarily in the onshore Gulf Coast regions of the United States. The Company owns and operates conventional properties in Texas, Louisiana, Colorado and Mississippi, approximately 12,000 net acres in the highly prospective Haynesville Shale, Mid-Bossier, and James Lime plays in

San Augustine and Sabine counties in East Texas, approximately 9,300 net acres in the prospective Eagle Ford play in South Texas and approximately 11,000 net acres in the Denver Julesburg Basin of Colorado.

Additional information on Crimson Exploration Inc. is available on the Company's website at http://crimsonexploration.com.

This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements include those concerning Crimson’s strategic plans, expectations and objectives for future operations. All statements included in this press release that address activities, events or developments that Crimson expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions Crimson made based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond Crimson’s control. Statements regarding future production, revenue and cash flow are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, commodity price changes, inflation or lack of availability of goods and services, environmental risks, drilling risks and regulatory changes and the potential lack of capital resources. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K for the year ended December 31, 2009, for a further discussion of these risks.

Contact: Crimson Exploration Inc., Houston, TX

E. Joseph Grady, 713-236-7400

Source: Crimson Exploration Inc.

EXHIBIT 99.2

CRIMSON EXPLORATION INC.

Moderator: Joe Grady

11-11-10/9:30 am CT

Confirmation # 7755984

Page 1

CRIMSON EXPLORATION INC.

Moderator: Joe Grady

November 11, 2010

9:30 am CT

Operator:

Good day and welcome to the Crimson Exploration Third Quarter 2010 Financial and Operational Results conference call. As a reminder, today's conference is being recorded.

At this time, I would like to turn the conference over to chief financial officer Mr. Joe Grady. Please go ahead, sir.

Joe Grady:

Thank you and welcome, everybody, to our call this morning. A quick overview of the agenda. Allan Keel, our President and CEO, will give you an overview of activity for the quarter. I'll follow with a brief review of the financial results. And then we'll open it up to a Q&A session.

But before we get started, I've got to go through the forward-looking statements qualifier. I want to remind everyone that the earnings release and discussion that will be had here today contain forward-looking statements as defined by the Securities and Exchange Commission and include comments concerning Crimson's strategic plans, expectations, and objectives for future operations.

While such statements are based on assumptions Crimson has made on its experience and expectations it believes were appropriate under the circumstances, those statements are just

CRIMSON EXPLORATION INC.

Moderator: Joe Grady

11-11-10/9:30 am CT

Confirmation # 7755984

Page 2

estimates and not guarantees of future performance or results and, therefore, should be considered in that context.

And with that, I'll turn it over to Allan.

Allan Keel:

Thanks, Joe and thanks to each of you for attending the call today.

We are happy to report we've had a very active and a very successful third quarter of 2010. We've successfully completed three wells during the quarter, the Grizzly number 1 well in San Augustine County, the Schwarz number 2, and the Catherine Henderson A-8 wells, both in Liberty County.

At the Grizzly well, as you know, most of you know, we had a 55% (working interest). It was our first operated well in the Mid-Bossier, Haynesville play over in East Texas. We started production in early August on a restricted rate of about 11.5 million a day, on a (1664 choke). That well continues to perform very nicely, and we're excited about the results there.

At the Schwarz number 2 well in Liberty County, that well also came on in August at an average daily rate of about 5.4 million a day of natural gas, 120 barrels of condensate, and about 216 barrels of natural gas liquids.

And then the Catherine Henderson A-8 well was our last well that we scheduled for 2010 in Liberty County. It came online in September at an average daily rate of 6.9 million a day, 445 barrels of condensate, and 565 barrels of natural gas liquids.

So as a result of that activity, we were able to increase our production in the third quarter by 22% over the second quarter 2010 production rate, up to a 36.8 million a day rate. Our October production averaged about 42.4 million a day, a 41% increase over the second quarter of 2010.

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So we're very excited about that. We're also actively drilling and completing a few other wells. And I'll go into that now.

In East Texas, the Gobi number 1 well, where we have a 70% working interest – or approximately 70% working interest – that was our second operated well in the Bruin Prospect area. That well is currently being frac'd or being completed in the mid-Bossier with initial production expected by the end of November. So we'll have some results on that, you know, in the near term.

Also, the Halbert Trust number 1, where we have 29% working interest in our Fairway Farms Prospect area in San Augustine County. That well is operated by an independent out of Dallas. It just recently completed a 14-stage frac in the mid-Bossier and is being prepared now to flow to sales.

We expect both of the wells, the Gobi and the Halbert Trust, to be produced using the restricted choke strategy that we utilized on our Grizzly well, which we think ultimately increases our reserves.

From a drilling perspective, in our Tiger Prospect area, which is a little bit farther to the southeast, our Bengal number 1, where we have a 37.5% working interest. That well is currently drilling below 15,400 feet in the lateral. We are planning on a 4,500 lateral right there and targeted in the mid-Bossier shale, with completion operations currently scheduled for the end of December, and that's – again, that would probably be subject to, you know, the pressure pumping equipment being available, but that's the date we have currently, is at the end of December.

That's our first operated well in Sabine County, Texas. And we – you know, that well will tell us a lot about the prospectivity of the mid-Bossier and the Haynesville, as you move farther to the southeast in east Texas.

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Once we finish drilling the Bengal well, we have two other locations ready to go, the Blue location. Another one's called (Kodiak). And both of those are located in our Bruin Prospect area. We expect (a spud), and we'll target the Haynesville and/or the mid-Bossier shale in one of those wells.

If we drill the Blue first, it's expected to reach a total measured depth by the early first quarter of 2011, with completion operations being shortly thereafter. You know, again, the Blue Prospect and the (Kodiak) are in our Bruin Prospect area, the Blue and the – excuse me, the Blue and the (Kodiak) wells are in the Bruin Prospect area, so we have a lot of good data there already.

Moving to south Texas, we are waiting on a completion of our – the two Eagle Ford Shale wells that we drilled with Petrohawk earlier this year. The Windham number 1 and the Born number 1, we have – again, we have a 20% working interest in both of those wells. The Windham well was our first horizontal well in the Eagle Ford, and it was drilled at a total measured depth of 19,129 feet, with a 6,200-foot lateral. Completion operations are expected to begin either in mid-December, with first production in January.

The Born number 1 well was drilled, you know, immediately after the Windham. It was drilled to a total measured depth of 17,253 feet with a 4,200-foot lateral.

So, you know, we're, you know, waiting on completion operations there. At the Born location, we're expecting that to occur in mid-January, with first production in February.

So overall, our kind of – looking at our CAPEX strategy, we anticipate, you know, the continued, you know, success in our completion operations from what we had in the third quarter. We expect to spend approximately $50 million to $55 million in 2010, which is closely aligned with our

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internally generated cash flow, which we set out as a goal at the beginning of the year, you know, subsequent to the equity offering that we did last September.

And so right now, what we're really focused on is finalizing the details of our 2011 capital program. We'll share that with everyone once those are finalized, but we hope to do that in a very near term.

You know, one of the main things that we'll be focused on next year is continuing to preserve our lease hold in east Texas, but at the same time, looking (to further prove-up) and to start developing some of our other lease hold that is more liquids-rich, primarily in the Eagle Ford, the Niobrara, and some even in southeast Texas in the Madisonville area.

So we're excited about that, but – and at the same time, we'll continue to develop our lease hold position in Liberty County, where we do have, you know, a very liquids-rich play there.

Also, you know, at this time, we're continuing our efforts to reduce debt and increase our financial capacity. We did close on a very significant transaction in October, where we had a private placement of our common stock at $5 a share, where we raised a little bit over $21 million and granted the buyer the option to purchase an additional $8.75 million worth of stock at $5 a share prior to year end.

The buyer – the shares were – it was American Capital Energy Corporation, or ACEC. It's the U.S. private equity investment subsidiary of the Shanghai Zhong Rong Property Group. We worked with this team for, you know, over a year now and feel very comfortable with them, and they've been a great partner to work with.

I think that initially it really started out as looking at a joint venture and some of our unconventional drilling opportunities. But as we talked more and more and shared with them

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some of our other ideas that we have within our inventory, I think they got really excited about the total – you know, all the prospects that we have in the company for growing this company and decided to make an investment, kind of an across-the-board set of – in one individual asset.

So very excited about that and working with them as we move forward. And I'm sure there will be some questions about that as we proceed, but with that, I'm going to turn it back over to Joe and let him give you a brief overview of the third quarter 2010 financial results.

Joe Grady:

Thank you, Allan.

Start out with – our lost for the quarter was $3.8 million, compared to a loss after preferred dividends of $9.7 million in the prior year quarter. Excluding the unrealized mark-to-market charges on our hedges, our net loss for the quarter was $3 million compared to a similarly adjusted loss in the third quarter of last year of $3.4 million.

For the first nine months of 2010, that loss was $10 million compared to a net loss after preferred dividends of $20 million for the 2009 period. Excluding the unrealized hedging charges for both periods, net loss was $10 million in 2010 compared to $9 million in 2009.

On an earnings per share basis, for the quarter, net loss per basic share was 10 cents for the 2010 quarter, and that's on 38.8 million shares outstanding, compared to a net loss of $1.51 per share in the 2009 quarter. And that was on 6.4 million shares.

Basic shares outstanding for 2010, the increase to the 38.8 million shares resulted from the public offering we did in December and the related conversion of all of our convertible preferred stock at that time.

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For the first nine months, net loss per basic share was 26 cents per share for the 2010 period on 38.7 million shares compared to a loss of $3.20 per share for the 2009 period on 6.3 million shares.

Adjusted EBITDAX, which is a number that we use as an indicator of cash flow from our operations, for the third quarter 2010, adjusted EBITDAX was approximately 16 million, compared to the prior year quarter of 18 million. For the first nine months of 2010, adjusted EBITDAX was approximately 40 million compared to 55 million for the 2009 period.

Switching to operating results, revenue for the current quarter was 24.5 million versus 26.9 million for the 2009 quarter, a slight decrease due to slightly lower production and slightly lower average realized prices.

On the production side, production for the current quarter averaged, as Allan mentioned, just under 37 million a day, which was right along the line with consensus in the market, and a little bit – just a tad over the midpoint of the guidance we gave preceding the quarter. That compared – that 36.8 million compared to an average of 38.3 million for the 2009 quarter. That was – that 36.8 was also, as Allan mentioned, 22% higher than the second quarter and 40% higher than – and the current October production was 40% higher than that second quarter, as well.

And he mentioned, we also have a number of wells that are ready to be completed and put on stream at various parts of time during this fourth quarter.

As you saw in the release, we anticipate our average production for the fourth quarter to range – or to fall within the range of 40 million to 43 million a day on average. On the price side, unhedged field prices averaged $5.63 per (Mcfe), compared to 465 per (Mcfe) for the third quarter, an approximately 21% increase.

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On a realized basis – and that is after – including the effects of settlements on our hedging instruments – prices averaged $7.21 per (Mcfe) in the third quarter of 2010 versus $7.60 per (Mcfe) for the quarter in 2009, a 5% decrease.

For fourth quarter guidance on the hedging, we have approximately 47% of our guided fourth quarter gas production hedged at an average floor of 785, and approximately 52% of our guided fourth quarter oil and liquids production hedged at average floor of $83.02.

On the LOE side for third quarter 2010 was 3.6 million, or $1.06 per (Mcfe), which was comparable in total cost, as well as a per unit cost, to the third quarter of 2009.

Cost per (Mcfe) in the third quarter this year improved over our year-to-date average of $1.27 as a result of the new production we've added from our drilling program.

Guidance for the fourth quarter under LOE is 4.0 million to 4.4 million, which is a little higher than what we had in the third quarter of 2010, as we anticipate several planned expense workovers during the quarter targeting production improvement.

On the G&A side, cash G&A – that is exclusive of stock compensation expense – third quarter was 4.0 million compared to 3.5 million in the third quarter of '09, which were the cash cost and then the current quarter were higher primarily because of about 700,000 in incentive compensation we recorded in the quarter for the year while bonus compensation for 2009 was not recorded until the fourth quarter.

Guidance for cash G&A for the fourth quarter is comparable to the third quarter actual just experienced.

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On liquidity and capital resources, Allan mentioned we did close private placement in October. We received the 22.25 million for the first step of the process. Assuming exercise of the second step of the process, we'll receive another 8.75 million in the fourth quarter. Assuming the exercise of the option, that will give ACEC approximately 13.4% of our outstanding shares and will entitle them to a board seat.

As we mentioned in a previous announcement, the proceeds from that private placement be used for general corporate purposes, including the continued development of our inventory drilling prospects.

And we currently project that for the year total CAPEX will be in the low- to mid-50 range, which is the guidance we've given for most of the year, and will be funded primarily from our cash flow from operations, including the change in – or the impact of the change in working capital.

We currently have approximately 27 million outstanding under our credit facility, which under the existing $95 million borrowing base gives us approximately 68 million in availability. We do have a re-determination in November. We're currently working with our bank group to re-determine that borrowing base, and we're optimistic, based on preliminary discussions, that that re-determination will be very close to the borrowing base that we have now.

And that concludes the financial review. And now we'll open it up for questions.

Operator:

All right. And if you would like to ask a question today, please press star and one on your touch-tone phone. That is star and one. You may remove yourself from the question queue at any time by pressing the pound key. We will give just a moment to allow for questions to queue.

And we will take our first question now from Chad Mabry with Rodman and Renshaw. Please go ahead. Your line is open.

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Chad Mabry:

Thanks. Good morning, guys.

Male:

Morning, Chad.

Chad Mabry:

Looking at – you know, looking into 2011, I know you're currently, you know, firming up your CAPEX plans. But, you know, can you elaborate a little bit on maybe some plans that the recent capital raise allows you to do, maybe looking at the Niobrara or the – you know, some of your (oil window) at the Eagle Ford. You know, how – are you going to try and, you know, maintain a pretty good-sized working interest (in those plays)? Are you looking to maybe farm out? Any color you could provide would be helpful.

Allan Keel:

Well, you know, Chad, I would say that our plans are – you know, we're trying to put all that together now, but I can tell you that one of the first things that we're going to do is we're going to be active in the Eagle Ford starting out probably in the Karnes County area where we have some acreage there. We'll drill at least one well, if not more there, next year. We're directly offset by several, you know, prominent operators in the area, so we feel like that acreage has been, you know, de-risked pretty significantly.

And then as you move – as we move to the west, we'll probably, you know, try to start evaluating our acreage in the Zavala area, as well, next year. So, you know, I think that's – you know, we do have a high working interest percentage in that particular area. It's, you know – it's over 90%.

So the question will be, you know, how much do we – do we (settle down) or do we, you know, promote someone into it? Or do we, you know, try to further develop it? Because it is being de-risked now by other operators. So that's something that we'll work on as we provide, and so that's kind of the Eagle Ford area.

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As you move into the – let's just jump up to the Niobrara real quick. You know, we do have a position up there. We're on the southern end of the DJ Basin – I'm sorry, the Wattenberg, excuse me. And so – the Wattenberg field.

So we're going to – we've got several locations kind of mapped out there. We're doing some additional technical work now. We're, you know, investigating the – you know, what the – the ability to access rigs and equipment up there, because we're not that – we haven't been that active up there.

But that is certainly, you know, the area that – the acreage that we have up there is in the area that is being, you know, prospective for the Niobrara. And the work that our team has done certainly, you know, confirms that.

So that's – you know, that's kind of a work in progress. And then, finally, back over into the kind of Madison County, Grimes County area, we do have acreage there that we think is also prospective for liquids. And using the – you know, the horizontal drilling technology, the multi-frac, you know, technology that's out there, we think that's going to be prospective, as well. So we're working that into our plans for 2011, as well.

Joe, do you have anything to add to that?

Joe Grady:

The one thing I'll add to that, Chad, is regarding the private placement that you mentioned. That is the ability to pursue some of these projects that Allan just mentioned, as well as continue to work on our east Texas area. We felt like the private placement would position us to do that.

As you might remember, back when we did the equity offering in December, we originally targeted 125 million and we only did 100. So adding this 30 to that 100 gets us to what we originally tried to target back in December and now, therefore, puts us in a better position to

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pursue some of these oil projects, which obviously are going to be better for us in balancing our product mix a little better between oil and gas.

Allan Keel:

Yes, and I would say, too, Chad, just to add to that, you know, we do have quite a long list of opportunities that we're, you know, trying to dedicate capital to and, you know, bringing in partners or, you know, looking for ways to maximize the value of our assets is something that we, you know, continue to do on a day-to-day basis.

Chad Mabry:

Okay, great. And I guess just, Allan, you beat me to the punch. You know, looking at east Texas, I know you had – at Madisonville targeted more, you know, (Rodessa), you know, before – are you thinking, you know, Eagle Ford just, you know – can you elaborate a little bit on some of the formations that you're looking at right now?

Male:

Well, yes. I think that the primary formation that we're focused on right now is the Woodbine. There's been a lot of success by some smaller independents working in that area. The results have been, you know, pretty outstanding, you know, so the – in fact, there's – some of our acreage directly offsets some of that success. So that's something that we want to look into, you know, (other), and that's, you know, something that we'll try to dedicate some capital to during 2010, but – I mean, 2011.

You know, there are some other zones up there that are prospective, but they're probably more kind of gas-oriented, so we're not going to pursue those at this time, but we do have a legacy position there that will – you know, we're going to continue to evaluate.

Chad Mabry:

Okay, great. Thanks, guys.

Male:

Okay. Thank you.

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Operator:

Our next question comes from Ron Mills with Johnson Rice. Please go ahead. Your line is open.

Ron Mills:

Good morning, guys.

Male:

Hey, Ron.

Ron Mills:

Chad just asked one of my questions on Madison/Grimes County. I know you – just to go forward with that a little bit, can you refresh my memory? I think you have about 15,000 total acres in that area, but – plus or minus a third of that is down around where that Woodbine activity is. Is that – am I remembering correctly?

Male:

Yes, I would say that that's generally right. I think, you know, we have – you know, some of the acreage we think is not as prospective as you move, you know, further to the east. I think the number's probably closer to 10,000 acres in total, and then probably half of that or, you know, 40% of that's maybe, you know, prospective in the Woodbine.

So we are – like I said, we are going to, you know, pursue that this coming year and see what we can do, but, I mean, they're – like I said earlier, there's a – you know, there's some offset activity to us, and I think, you know, we've discussed that before, that has really been outstanding. So we're excited about pursuing it.

Ron Mills:

Okay. And you mentioned earlier, you know, some of your activity next year will be focused also on lease maintenance. (You have more lease maintenance issues primarily) in east Texas. Do you also have some in the Eagle Ford? And kind of what level of activity do you need to maintain to make sure you maintain that acreage?

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Male:

Well, basically, all of our acreage in – with a minor exception down in Bee County – all of our acreage in the Eagle Ford area is (HBP). So we don't – you know, we're not really under any, you know, time pressure there. But, obviously, you know, given the markets, you know, we'd like to further develop those assets.

We do have – you know, really the only area where we have, you know, any kind of pressure on lease maintenance is in east Texas. You know, we've kind of talked about that before, but, you know, for each, you know, unit that we can drill, we can really preserve a significant amount of natural gas. So we're going to continue to do that.

We've got, you know, preliminarily I would say, you know, four to six wells scheduled over there next year. That's, you know, from our perspective. Now, what other operators do, where we would be a non-operating partner, that remains to be seen.

You know, there's generally been a discussion out there about coming (back on rigs) and – but there still are lease maintenance issues that you've got to, you know, consider when doing that.

So I think a combination of, you know, the result that we see from this Bengal well and what other operators do will dictate a lot of – you know, how much additional drilling is done in east Texas by us next year.

Ron Mills:

And the four to six wells you talked about preliminarily, is that just operated wells at this point?

Male:

Yes. Yes.

Ron Mills:

Okay. And that compares to two or three operated wells, really, here in the second half of this year? Is that...

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Male:

Well, you know, yes. We had the Grizzly, the Gobi, the Bengal well...

Ron Mills:

And now either the Blue or the (Kodiak).

Male:

Yes. Yes.

Ron Mills:

And so is that something that we would expect to probably see that number move up, you know, based on – in a success case that you would probably want to be more active there rather than a somewhat flat level? Would you be more constrained by rigs and/or (completion crews)?

Male:

I think – if I understand your question correctly, Ron, I think that, you know, we do have a rig under contract out there, and we're going to keep that rig, you know, busy out there probably most of next year.

Ron Mills:

Okay.

Male:

You know, the – you know, the pressure, pumping services, that's all – you know, continues to be a little bit of a challenge for us. (Carl's) done a good job of keeping us in the queue, but, you know, we have had some delays out there, not only have we, but other operators have, as well, so – but I think that, you know, that guidance that, you know, based right now of what we're looking at for our budget for next year, that's probably a good estimate.

But the wild card is, you know, what kind of results do we get out of the Bengal well? And what do other operators – you know, how do they elect to proceed? Do they decide to drill? Do they try to extend their leases or what? So that story is yet to be told.

Male:

We have, Ron, efforts along a number of lines in trying to address the exploration issue, in addition to the drilling ((inaudible))

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Male:

Right. Right.

Ron Mills:

Right. Okay. And then you mentioned the completion – the access to completions. You know, for, obviously, the Gobi and the Halbert Trust, it's different. But in terms of the Bengal and the Blue, you know, you have at least soft frac dates for the Bengal. You know, how's the process working relative to three or four months ago? Are you just – is it just a matter of staying in front of it a little bit better? Or is some of the access actually freeing up, since some capacity has already been added?

Male:

I'm going to let (Carl) tackle that one.

(Carl Isaac):

This is (Carl Isaac). I take care of Crimson's operations. And we've been able to position ourselves for 2011 in such a way that we have commitments from major pumping service companies to cover our program in the Haynesville and from a frac standpoint. And that commitment is loosely tied to what we perceive our schedule to be in 2011.

We've also taken the same approach on our Liberty County work, as well, so we feel pretty comfortable that, with maybe a little sway, we're going to have equipment more or less when we need it.

We've been trying to get in front of that. Relatively speaking, we're in a small player in the market, though we feel like we've been pretty successful in terms of positioning ourselves to have equipment when we need it.

Ron Mills:

Okay, good. And then, Joe, just two real – you talked about gas-oil hedging percentages. Do you expect overall your gas-oil split to be pretty similar to what you had in the third quarter? And

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in terms of just, you know, relative percentages, because the guidance you gave was just on an (Mcfe) basis?

And then, lastly, the (DDNA), you forecast a pretty big drop here in the fourth quarter. Is that just due to expected reserve additions, given the Haynesville activity?

Male:

I think the mix will not be too dissimilar. It might be a little bit higher on gas because of the addition of the Haynesville, but it won't be dissimilar.

And then, as it relates to the (DDNA) rate, you're correct. It's new reserves added, which – at lower cost than what historically our (DDNA) base rate has been, and that's the reason for the drop.

Ron Mills:

Great. All right, guys. Thank you.

Male:

Thanks, Ron.

Operator:

We'll go now to the site of Jeff Robertson with Barclays Capital. Please go ahead. Your line is open.

Jeff Robertson:

Thanks. My questions were just answered.

Male:

Thanks, Jeff.

Male:

Thanks, Jeff.

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Operator:

And as a reminder if you wish to ask a question, please press star and one on your touch-tone phone. That is star and one. We will go now to Daniel Morrison with Global Hunter. Please go ahead. Your line is open.

Daniel Morrison:

Thanks. Quick question about the – your (non-op) activity in the Haynesville – in the Fairway Farms area. Is that going to continue, or is the rig moved on to something else there?

Male:

The (non-op activity) in the Fairway Farms area?

Daniel Morrison:

Yes.

Male:

That rig should keep working.

Daniel Morrison:

Okay.

Male:

Well, actually, it's going to keep working, but they're going to move it, and we hope that they bring that rig back at some point, but we're – we have an operated location there that we plan to drill next year.

Daniel Morrison:

Okay. And – that covers me. Thanks.

Male:

Okay.

Male:

Thanks.

Male:

Thanks, (Dan).

Operator:

And we will go now to Ronald Beck with (Harris Beck Capital Partners). Please go ahead.

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Ronald Beck:

In addition to some of the previous questions, what is the CAPEX that's going to be required over the next two years to reserve those lease hold interests in the ((inaudible)) prospects?

Joe Grady:

Well, for this year, we're spending a little less than $30 million. As Allan mentioned earlier, we haven't finalized our budget for 2011, but we expect it'll be higher than that. It'll be a combination of both drilling, as well as the potential for amending, extending or releasing acreage that we think is – falls within drilling areas that make sense to extend.

Ronald Beck:

Given the amount of prospects you have in the fairly levered balance sheet, what are the other programs that you're looking at to exploit those prospects?

Male:

Well, as we discussed, we just did a private placement that we think will give us much more flexibility to be able to pursue some of our opportunities. And then, obviously, as the cash flow builds from the production increases, that will, as well.

We're always receptive to joint venture ideas primarily with industry partners in some of these areas, but we don't have anything imminent in the works on that right now.

Male:

Yes, and to ((inaudible)) activity increases in those areas, the possibilities for those type of arrangements increases.

Male:

Yes, and I would just add to that, to the extent that there's a part of the puzzle that just doesn't fit, and there's an opportunity to monetize that, we would consider that, as well.

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Ronald Beck:

Well, as you know, there's a lot of money chasing (gas plays) right now, whether it be prospects or companies. And it seems to me that you guys would be ideal for some sort of joint venture on a (E&P deal) partnership of that sort.

Male:

Well, we appreciate that. We think so, too.

Ronald Beck:

So that's yet to happen?

Male:

It's a possibility.

Ronald Beck:

All right, thanks.

Male:

Thank you.

Operator:

We will go now to the site of Michael Kanner with Angelo Gordon. Please go ahead.

Michael Kanner:

Hi, good morning. I noticed, I guess, after Q4 your gas hedges roll off fairly substantially, I guess going into 2011. Any thoughts on perhaps increasing your hedging exposure on the net gas side for 2011? Obviously, it's – you know, prices aren't great, but it's a bit better than it has been in recent months, so just your thoughts on 2011, additional hedging.

Male:

Well, we're going through an exercise as we speak, actually, and determining what we want to add for 2011 or 2012. Certainly on the oil side, prices are pretty attractive and will likely add some on that side in order to ensure some of the cash flow coming from oil or protect that cash flow.

Gas is a little more difficult, given where the prices are. But we do have some ideas on things that we can do there to protect ourselves on the downside, but also give us some upside. But I don't have anything definitive to ((inaudible))

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Michael Kanner:

It looks like you're about – from looking ((inaudible)) a little over 20% hedged on nat gas for next year, or say 20% give or take, I guess. Is that about right?

Male:

Well, we look at it as a percentage of (PDP), forecasted (PDP). And it's probably 45%, so if you assume continued growth, that obviously comes down on a total basis.

Michael Kanner:

Okay. Thank you.

Operator:

And we'll go next to the site of Eric Anderson with Hartford Financial. Please go ahead.

Eric Anderson:

Thank you. I wanted to congratulate you all on the private placement that you just executed and would point out that it was one of the better deals that I've seen in a long time. You know, had you tried to sell equity when the stock was in the mid- to high twos, I'm sure you could have got it done, but probably in the low twos, so to get something done at five, which it looked like it was a 75% premium to where you were trading is, you know, really commendable and just wanted to really congratulate you on that point.

And to follow that up, I'm just wondering if you can give us a little more color in terms of the relationship that you seem to have developed with ACEC over the past year. You know, how did you come to know each other? You know, over the hundreds of public or private oil companies that are out there, you know, how did they happen to choose you folks to work with?

Male:

Well, you know, I'll take a stab at that. And thanks for your compliment.

We've known one of the representatives of the ACEC group for quite some time. It's a person that was involved in the industry here, continues to be involved in the industry here in Houston. He's been a long-term friend of one of our senior guys, (Tommy Atkins), and we met him – we sat

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down one day for lunch and were talking about a JV on some of our unconventional acreage, and it kind of just evolved from that.

And we started showing him some other ideas, and he was excited about the growth prospects of the company, and it just – it took some time to – for that whole, you know, relationship to bloom with the – you know, with the ACEC, but I think once they saw the – you know, the upside potential that the company has, they were very excited about that, and they wanted to participate in everything and not just one particular area.

So, you know, I think that – and we got to, you know, meet some of the other principals of the company, the owner of the company, and I think we just share a common vision on how to build a business, and they like the prospects. And so I think that's really what led to us getting a deal done.

And I think it also took the just perseverance and patience on both parties' behalf. And we were able to get it done, and they're very excited, as are we, and we, you know, agree that, you know, it was a higher than – you know, where the market price of the stock was, but relative to the opportunity set that we have in the company, we think that it was a very fair price. So...

Eric Anderson:

Do they have the ability or the option to purchase stock in the open market?

Male:

They do.

Eric Anderson:

Okay.

Male:

Subject to normal trading windows of the company, because they'll be an insider. But subject to the insider trading policy we have and the windows that are available to all employees under that policy, they can buy in the market, yes.

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Eric Anderson:

So could they buy now? Or would that only kick in after they possibly complete the second half of the transaction?

Male:

No, they could buy now, except the window's not open.

Eric Anderson:

Okay. My follow-up question is, you know, it looks like the results that you've got – the Catherine Henderson A-8 well – are extremely compelling in today's liquids markets. And wondering what type of follow-up locations you have with that well.

Male:

Well, you know, we do have additional potential in the same area. You know, most of these wells that we drill in Liberty County are, you know, kind of one-off type opportunities, so they're kind of, you know, unique to the – you know, to themselves. You know, some of them can lead to more drilling opportunities, like the – I guess, really, the Catherine Henderson A-6 well that we drilled back in 2008. That actually led to, you know, quite a bit more drilling.

But, you know, we typically look at these things as, you know, single-shot-type opportunities and hope, you know, that they lead to more, but we do plan, you know, a three- to four-well drilling program in Liberty County again next year. And it's just a great area, and continue to try to, you know, harvest that area as much as we can.

Eric Anderson:

Okay. My last question is, with the acreage that have in Bee County, am I correct in assuming that you're being carried on that by Petrohawk for contributing your acreage?

Male:

Yes, on the first couple wells, we had a – there was a (promote involved). And then from that point forward, we'll be on a (heads-up basis).

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Eric Anderson:

Yes. And it looks like the horizontal leg on that first well is quite a bit longer than I'm used to seeing in other wells. Was there something particular with that? Or – I mean, was there like 6,200?

Male:

Well, they just – I think they just wanted to open up as, you know, much of the formation as they could. And that was – that particular unit allowed that to happen, so I think that's really the only strategy there.

Eric Anderson:

So just the way the acreage was sort of laid out?

Male:

Yes.

Eric Anderson:

Okay. Well, thanks very much, and congratulations again.

Male:

Thank you.

Male:

Thank you.

Operator:

And as a reminder if you wish to ask a question, please press star and one on your touch-tone phone. That is star and one. And you may remove yourself from the queue by pressing the pound key.

We will go next to John Selser with Iberia Capital Partners. Please go ahead. Your line is open.

John Selser:

Good morning.

Male:

Morning, John.

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Male:

Morning, John.

John Selser:

Pretty good game there in Baton Rouge last weekend.

Male:

For some.

Male:

For me.

John Selser:

Might have to change the name of the company. I just wanted to know if you're seeing any break yet in completion costs or frac costs. Are things freeing up any yet? I'm hearing maybe it's getting a little bit better. I just wanted to see what you were seeing out there.

Male:

Well, I think what we're seeing is maybe a flattening right now, but I wouldn't call it (a roll). You know, the first three quarters of this year, (solid service side) kind of (coming out of the bottom). And I think they found their level in the July-August timeframe, so maybe now we can kind of expect to go (complete wells) without cost continuing to rise on us.

And we've also incorporated those – that approach in terms of some of the commitments we have next year for pumping services so that we have a reasonable expectation that costs will be flat to what we've experienced over the last quarter.

John Selser:

I guess that's a start. Thank you.

Male:

Thanks, John.

Male:

Thanks.

Operator:

We will go now to the site of Don Knapp with Investment Management. Please go ahead.

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Don Knapp:

Good morning, gentlemen. I hope you can hear me. First of all, thank you for a very informative session and congratulations on the excellent operating results. Just a couple of quick questions. Most of mine have been answered already, but looking at property acquisitions, looking, let's say, to the recent past and the near-term future, any thoughts on property acquisitions?

Male:

Well, we – Don, we do continue to look and evaluate opportunities as they arise. As you know, the market for acquiring liquids is very robust and prices are very high. So, you know, if we're looking for properties acquired, you know, natural gas properties aren't (quite selling) at the same premium these days, obviously, due to the commodity prices out there.

But, you know, we do have a team that looks at producing property acquisitions. And, obviously, we also believe that scale is important in our business, so, you know, if we can continue – if we can build our business by acquiring (new assets) at a better price than we can, you know, (drill organically), that's something we'd certainly consider.

Don Knapp:

Okay. Thank you very much. Second quick question. Your focus has certainly been were it should be on what's going on in the Texas area, but I've often – I always feel that a great potential rests with the properties in Colorado. You touched on it briefly. Did you have any additional thoughts or would you like to expand a little bit on your Colorado opportunities? Thank you.

Male:

Well, I guess I'd just reiterate that, you know, we do believe that we have, you know, a significant amount of potential there. Our acreage there is for the most part held by production, so we're in no – under no pressure to get out there and drill a lot right now. The activity level continues to increase in and around our property base there, so I think it's important for us as a company to monitor that, but at the same time try to develop our acreage and our assets as quickly as we can.

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To the extent, you know, I think an earlier caller had asked about, you know, JVs and things of that nature. That's something that we would certainly consider in that area. But at the same time, if it – you know, if we can get the most value by, you know, operating it and drilling it ourselves, that's something that we will, you know, obviously, you know, take very seriously.

Male:

But which we will likely move in that direction as part of our capital budget in 2011, but we'll also be keeping an eye – eyes and ears open about the activity around us and be receptive to opportunities (and might come from that). So it's kind of a dual path, if you will.

Don Knapp:

Thank you very much. I appreciate it. And good luck, gentlemen.

Male:

Thank you.

Operator:

We will go next to Robert Cunjak with Sankaty Advisors. Please go ahead.

Robert Cunjak:

Morning, everyone. Had a question, talked about four to six operated wells in East Texas; what do you guys think the capital required for that would be, roughly? I know you guys are in the midst of working on your capital payments for '11, but, you know, what's the operatorship and, you know ((inaudible)) cost per well?

Male:

I think that – I think, Robert, that as we're putting together our plans, you know, we use – you know, we look at what our working interest is going to be, what the costs are, so I think that, you know, I'll let Joe tackle that question a little bit in more depth, but I think that, you know, if we assume four wells, you know, a 40% working interest, it's going to vary. It's maybe – it may be as high as 50.

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So I think in our – generally in our budget what we're thinking now is, you know, something – and, you know, again, similar to this year, may be plus or minus $30 million in total CAPEX.

Male:

Well, as I mentioned earlier, in 2010, we're just under 30 and we'll probably exceed that in 2011, the combination of drilling, as well as possibly extending leases.

But I think we're running about $13 million, $12.5 million a well without pilots. What we've been drilling today have pilots. So, you know, four at that level, then whatever our working interest ultimately turns out to be, depending on the configuration of the drilling unit. It sort of gives you some guidance there.

Male:

Yes, and I did not include in my number – I was not including any capital going to additional leasing or extensions or anything like that, so it's still a work in progress, Robert.

Robert Cunjak:

Okay. All right, great. Well, thanks very much.

Male:

Yes, thank you.

Operator:

We will go now to a follow-up from Chad Mabry with Rodman and Renshaw. Please go ahead.

(Jeff Aden):

Hey, you guys. It's (Jeff Aden). Just real quick, you know, with kind of the big drop you guys are forecasting on the (DDNA rate) side, just wondering if you can give us a little color on, you know, maybe what you think (reserver placement's) going to shake out to for the year.

Male:

Well, obviously, that'll be a function of what we end up with at the end of the year. And in terms of (PUDs) from the drilling of the resource play – and we haven't gotten to the point yet where we're

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ready to share that with the street. But I would expect that you'll see a meaningful increase in total proved reserves year over year.

(Jeff Aden):

Okay. I appreciate it, guys.

Male:

Thanks, Jeff.

Operator:

And we will go now to Daniel – to the site of Daniel Morrison with Global Hunter. Please go ahead.

Daniel Morrison:

I think I got covered. Thanks.

Male:

Okay. Thanks, Daniel.

Operator:

And at this time, we have no more questions in the queue.

Male:

Well, great. Well, we'd like to thank everybody for participating in today's call and look forward to keeping you up to date with our progress and the success we've had this year. So thanks a lot. That concludes our call.

Operator:

This now concludes today's conference. We hope you – we thank you for your participation, and please have a nice day.

END

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