Crimson Exploration Announces Fourth Quarter And Full Year 2012 Financial Results And An Operational Update

Crimson Exploration Inc. (NasdaqGM:CXPO) today announced financial results for the fourth quarter and full year 2012 and an operational update.

2012 Summary & Highlights
  • Full year revenue of $115.9 million and Adjusted EBITDAX of $81.0 million
  • Increased quarterly crude oil and natural gas liquids production to 45% of total production, through a 90% increase in crude oil production
  • Increased proved reserve PV-10 value to $340.1 million, a 28% year-over-year increase
  • Increased proved crude oil and natural gas liquids reserve volumes by 66% and 18%, respectively, to a total of 9.2 million barrels

Management Commentary

Allan D. Keel, President and Chief Executive Officer, commented, “The Company entered 2012 with two main objectives. The first objective was to continue our transition to a balanced profile of natural gas and crude oil and NGLs. Second, validate our Woodbine acreage position. I am pleased to say the Company accomplished both tasks. In 2012, crude oil production increased by 90% to 753,980 net barrels, so total liquids production represented 45% of total production, up from 30% in 2011, and our year-end proved reserves were 47% crude oil and NGLs, up from 19% at year-end 2011. In our Woodbine play in Madison and Grimes counties, Texas, Crimson has emerged as an industry leader offering significant exposure to the core parts of the play. Since completing our Mosley #1H well in March 2012, Crimson’s operated properties in the Woodbine have produced over 550,000 gross barrels of oil equivalent and our operated and non-operated wells have achieved an average 24-hr initial production rate of 1,108 boepd and a 30-Day average production rate of 748 boepd. In 2013, we will continue to develop our assets in the Woodbine formation, while concurrently expanding our focus on oil-weighted opportunities to include the crude oil rich Buda formation in South Texas and look to possibly execute a drilling program for the James Lime in East Texas.”

Summary Fourth Quarter Financial Results

The Company reported Adjusted EBITDAX, as defined below, of $17.5 million in the fourth quarter of 2012 compared to Adjusted EBITDAX for the prior year quarter of $17.2 million. Net loss for the fourth quarter of 2012, exclusive of special non-cash charges discussed below, was $3.4 million, or ($0.08) per basic share, compared to a net loss of $3.5 million, or ($0.08) per basic share, in the fourth quarter of 2011. Net loss including those special charges was $87.7 million, or ($1.98) per basic share, for the fourth quarter of 2012 compared to a net loss of $5.0 million, or ($0.11) per basic share, for the fourth quarter of 2011. Special non-cash items impacting the fourth quarter of 2012 were a $115.6 million non-cash impairment of certain natural gas assets in South and East Texas, a $10.2 million deferred tax valuation charge related to net operating loss carryforwards, and an unrealized pre-tax charge of $0.2 million related to the mark-to-market valuation requirement on our commodity price hedges. In the fourth quarter of 2011, the Company recognized an unrealized pre-tax charge of $1.6 million related to the mark-to-market valuation on commodity price hedges and a $0.7 million leasehold impairment charge.

Revenues for the fourth quarter of 2012 were $27.9 million compared to revenues of $27.4 million in the prior year quarter. The slight increase results primarily from a 48% increase in higher value oil production, offset, in part, by declines in natural gas production and lower realized natural gas liquids (“NGL”) pricing.

Production for the fourth quarter of 2012 was approximately 3.4 Bcfe, or 36,840 Mcfe per day, achieving the upper end of the Company’s production guidance range of 34,000 to 37,000 Mcfe per day. Crude oil and NGL production increased to 254,039 barrels, or 45% of total production for the quarter, up from 207,272 barrels, or 34% of total production, in the fourth quarter of 2011. The increase in liquids production is a result of a strategic shift toward crude oil and liquids-rich projects in the Woodbine and Eagle Ford Shale formations initiated in 2011.

The weighted average field sales price in the fourth quarter of 2012 (before the effects of realized gains/losses on our commodity price hedges) was $7.87 per Mcfe compared to an average field sales price of $6.72 for the fourth quarter of 2011. The weighted average realized sales price in the fourth quarter of 2012 (including the effects of realized gains/losses on our commodity price hedges) was $8.24 per Mcfe compared to a weighted average realized sales price of $7.45 per Mcfe for the fourth quarter of 2011. The increase in the weighted average equivalent prices resulted from higher levels of crude oil and NGL production, despite the decrease in prices.

Lease operating expenses for the fourth quarter of 2012 were $3.7 million, or $1.10 per Mcfe, compared to $3.7 million, or $1.00 per Mcfe, in the fourth quarter of 2011. Lease operating expenses increased on a per Mcfe basis due to the lower equivalent production volumes and higher lifting costs associated with oil production compared to natural gas production.

Production and ad valorem tax expenses for the fourth quarter of 2012 were $1.8 million, or $0.52 per Mcfe, compared to $1.3 million, or $0.35 per Mcfe, for the fourth quarter of 2011, an increase resulting from higher tax rates paid on higher crude oil sales revenue.

Depreciation, depletion and amortization (“DD&A”) expense for the fourth quarter of 2012 was $15.4 million, or $4.53 per Mcfe, compared to $15.6 million, or $4.24 per Mcfe, for the fourth quarter of 2011. DD&A expense was relatively flat period over period as the slightly higher rate associated with recently developed crude oil wells was offset, in part, by lower equivalent production.

Non-cash impairment and abandonment of oil and gas properties in the fourth quarter of 2012 was $115.6 million compared to $0.7 million in the fourth quarter of 2011. Impairment and abandonment of oil and gas properties in the fourth quarter of 2012 was primarily caused by a continued trend of depressed natural gas prices and Crimson’s decision to reduce future dry gas related drilling and development activity in South and East Texas for the foreseeable future. This decision triggered the re-classification of primarily undeveloped reserves previously classified as proved which resulted in a reduction in value for the Company’s conventional natural gas assets in South Texas (purchased in a higher natural gas price environment in 2007 and 2008) and unconventional natural gas assets in East Texas. The Company will continue to hold proved producing acreage in these areas and may be able to re-book all or some portion of these reserves as proved once the commodity price environment improves.

In 2012, Crimson recorded an income tax benefit of $34.7 million compared to $8.1 million in 2011. The income tax benefit of $34.7 million is net of a $10.2 million partial valuation allowance of net operating loss carryforwards. The Company recorded this partial valuation allowance as it has been unable to realize significant net operating loss carryforwards in recent years nor does it expect that a significant amount will be realized in 2013.

General and administrative expense in the fourth quarter of 2012 was $5.6 million, or $1.66 per Mcfe, compared to $5.7 million, or $1.55 per Mcfe, in the fourth quarter of 2011. General and administrative expenses, exclusive of non-cash stock option expense recognized in each quarter, was $5.0 million for the fourth quarter of 2012 compared to $5.3 million for fourth quarter of 2011.

2012 & 2013 Capital Programs

Capital expenditures for the fourth quarter of 2012 were $5.0 million, allocated between completion operations and leasehold acquisitions in Madison and Grimes counties, Texas. In 2012, Crimson invested approximately $79.3 million, of which $63.5 million was used to drill 12 gross (7.9 net) wells and to sidetrack one (0.6 net) well, with a 100% success rate. The remaining $15.8 million was used to build facilities, acquire and extend leases, and complete wells drilled in late 2011.

The table below outlines Crimson’s 2012 drilling activity by area:
Well Name WI - % County / Formation IP Rate Liquids - % IP Date
Southeast Texas
Mosley #1H 84.3 Madison / Woodbine 1,203 Boepd 91.8 Mar 2012
Pavelock #1H 2.7 Madison / Woodbine 1,808 Boepd 85.7 Mar 2012
Vick Trust #1H 75.0 Madison / Woodbine 383 Boepd 74.9 May 2012
Grace Hall #1H 82.5 Madison / Woodbine 1,080 Boepd 87.5 June 2012
A. Yates #1H 50.0 Grimes / Woodbine 472 Boepd 90.9 June 2012
Payne #1H 92.1 Madison / Woodbine 1,332 Boepd 93.1 July 2012
Catherine Henderson A-6 ST 60.8 Liberty / Cook Mtn. 7.2 Mmcfepd 47.0 Aug 2012
Covington-Upchurch #1H* 67.8 Grimes / Woodbine 6.9 Mmcfepd 33.4 Nov 2012
Gatlin #1H 3.1 Madison / Woodbine 1,436 Boepd 88.1 Dec 2012
South Texas
Littlepage McBride #7H 53.0 Karnes / Eagle Ford 1,019 Boepd 89.0 Jan 2012
Beeler #1H 50.0 Dimmit / Eagle Ford 370 Boepd 91.1 Feb 2012
Glasscock A #1H 95.5 Karnes / Eagle Ford 726 Boepd 91.6 Mar 2012
Glasscock B #1H 90.7 Karnes / Eagle Ford 685 Boepd 89.8 May 2012
KM Ranch #2H 50.0 Zavala / Eagle Ford 511 Boepd 89.4 Aug 2012

*Initial production rate only reflects data from an unstimulated toe stage 24-hour test. Full scale flowback operations are currently pending the installation of midstream services to handle higher BTU content natural gas production. Initial production rates do not necessarily indicate current production.

Crimson’s 2013 capital budget is currently forecasted to be approximately $58.7 million focusing on its inventory of crude oil and liquids-rich projects in the Woodbine formation with a continuous rig program planned for 2013. The Company currently plans to drill one or more test wells in the crude oil rich Buda formation in the Zavala/Dimmit counties in South Texas. If warranted by market conditions, success in these areas and capital availability, the Company may further accelerate the drilling program in one or both of these areas.

2012 Year End Reserves

Proved reserves at December 31, 2012, as estimated by Netherland, Sewell & Associates, Inc., Crimson’s independent petroleum engineering firm, in accordance with reserve reporting guidelines mandated by the Securities and Exchange Commission (“ SEC”), were 117.0 Bcfe, consisting of 61.9 billion cubic feet of natural gas, 6.2 million barrels of crude oil, and 3.0 million barrels of natural gas liquids, with a present value of proved reserves discounted at 10% (“PV-10”) of $340.1 million.

Crimson’s strong success drilling the Woodbine formation in Madison and Grimes counties, Texas contributed to a 66% increase in crude oil proved reserves and an 18% increase in NGLs proved reserves over 2011. Accordingly, crude oil and NGL reserves now represent 47% of proved reserves at December 31, 2012, up from 19% in 2011, further balancing Crimson’s reserve profile. Additionally, the sharp increase in PV-10 demonstrates the value added from targeting crude oil and NGL weighted assets and further validates Crimson’s ability to evaluate and execute a high impact, lower risk drilling program.

Benchmark commodity prices used in calculating the proved reserve estimates and present value were the twelve month un-weighted arithmetic average of the first-day-of-the-month prices for the period January 2012 through December 2012. For crude oil and NGL reserves, the average West Texas Intermediate posted price of $91.21 per barrel at December 31, 2012, compared to $92.71 per barrel at December 31, 2011, is adjusted by field for quality, transportation fees, and regional price differentials. For natural gas reserves, the average Henry Hub spot price of $2.757 per MMBTU at December 31, 2012, compared to $4.118 per MMBTU December 31, 2011, is adjusted by field for energy content, transportation fees and regional price differentials. All prices are held constant for the lives of the reserves.

Due to a continuing low natural gas price environment, Crimson was required to remove approximately 92 Bcfe of proved undeveloped reserves (PUDs) in East Texas from its proved reserve base until natural gas prices return to more economical levels. Notwithstanding the removal of East Texas PUDs, Crimson increased year-over-year PV-10 to $340.1 million, a 28% increase, from $266.5 million in 2011, as the Company continued its transition to crude oil and natural gas liquid weighted projects.

Price related reserve revisions are an uncontrollable consequence of operating in a commodity price driven industry. Since year-end 2011, the prices used to calculate natural gas reserves declined $1.36 per MMBTU, or 33%, down to $2.757 per MMBTU. Crimson’s East Texas proved undeveloped reserves have been reclassified as unproved reserves but can be reinstated once natural gas prices improve. Assuming the East Texas PUDs were not reclassified, reserve growth in 2012 would have been 11% with a reserve replacement of 160%.

As of December 31, 2012, 53% of proved reserves were natural gas, 54% were proved developed and 90% were attributed to wells and properties operated by Crimson.

The following table summarizes Crimson’s total proved reserves as of December 31, 2012:
Net Reserves Present Value
Oil       NGL       Gas       Total Discounted
Category (MBBL) (MBBL) (MMCF) (MMCFE) at 10% (MM)
Developed 2,343 1,686 39,554 63,732 $ 197.9
Undeveloped 3,859 1,306 22,330 53,317   142.2
Total Proved 6,202 2,992 61,884 117,049 $ 340.1
Note: Total numbers may not add due to rounding.

Operational Update

Madison County, Texas – Force Area Woodbine

Crimson drilled the Nevill-Mosley #1H well (82.0% WI), targeting the Woodbine formation, to a total measured depth of 15,011 feet, including a 6,360 foot lateral. Crimson has begun completion operations and anticipates initial production in April after completing the well with approximately 22 stages of fracture stimulation. The Nevill-Mosley #1H is Crimson’s first well in the 2013 capital program.

Approximately 1.7 miles east of the Nevill-Mosley #1H well, Crimson spud the Mosley B #1H well (85.4% WI), targeting the Woodbine formation, which is currently drilling at a depth of 7,913 feet. Crimson anticipates drilling to a total measured depth of approximately 14,805 feet, including a 6,200 foot lateral, and conducting approximately 22 stages of fracture stimulation. Completion operations are expected to begin in April with initial production to follow in May. Upon completion of drilling operations, the rig will be moved 1 mile east to begin drilling the Payne B #1H.

Grimes County, Texas – Iola/Grimes Area Woodbine

As previously disclosed, full flow back operations on the Covington-Upchurch #1H well (67.8% WI) has been postponed as a result of delays in completing infrastructure capable of handling natural gas production with higher BTU content in the area. Crimson was informed by the service provider that installation of the refrigeration unit will now be completed by the end of March. The service provider indicated unforeseen regulatory issues, which are now resolved, as the reason for delay on completion of the project.

Dimmit County, Texas – Buda

Crimson recently secured a one well contract for a 1,000 horsepower drilling rig with anticipated delivery by the end of March. Crimson plans to spud the Beeler #2H well (50.0% WI), a horizontal well targeting the Buda formation, the first week of April with initial production rates expected in May. The Buda is a naturally fractured limestone formation located below the Eagle Ford and Austin Chalk formations at an average depth of 7,000 feet. The Beeler #2H will be drilled to a total measured depth of 11,180 feet, including an approximate 4,000 foot lateral.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and twelve month periods ended December 31, 2012 and 2011:
Three Months Ended Twelve Months Ended
December 31, December 31,
2012       2011       % 2012       2011       %
Total Volumes Sold:
Crude oil (bbls) 169,267 113,986 48 % 753,980 396,760 90 %
Natural gas (Mcf) 1,865,312 2,440,817 -24 % 7,799,301 11,675,602 -33 %
Natural gas liquids (bbls) 84,772 93,286 -9 % 300,435 417,956 -28 %
Natural gas equivalents (Mcfe) 3,389,546 3,684,449 -8 % 14,125,791 16,563,898 -15 %
Daily Sales Volumes:
Crude oil (bbls) 1,840 1,239 48 % 2,060 1,087 90 %
Natural gas (Mcf) 20,275 26,531 -24 % 21,310 31,988 -33 %
Natural gas liquids (bbls) 921 1,014 -9 % 821 1,145 -28 %
Natural gas equivalents (Mcfe) 36,843 40,048 -8 % 38,595 45,381 -15 %
Average sales prices (before hedging):
Oil $ 103.93 $ 103.93 0 % $ 102.79 $ 101.55 1 %
Gas 3.28 3.33 -2 % 2.64 3.89 -32 %
NGLs 35.02 51.34 -32 % 36.12 48.96 -26 %
Mcfe 7.87 6.72 17 % 7.71 6.41 20 %
Average realized sales price (after hedging):
Oil $ 105.91 $ 96.86 9 % $ 104.24 $ 92.65 13 %
Gas 3.77 4.78 -21 % 3.39 4.85 -30 %
NGLs 35.02 50.80 -31 % 36.12 48.35 -25 %
Mcfe 8.24 7.45 11 % 8.21 6.86 20 %
Selected Costs ($ per Mcfe):
Lease operating expenses $ 1.10 $ 1.00 10 % $ 1.08 $ 0.80 35 %
Production and ad valorem taxes $ 0.52 $ 0.35 50 % $ 0.18 $ 0.41 -57 %
Depreciation and depletion expense $ 4.53 $ 4.24 7 % $ 4.16 $ 3.44 21 %
General and administrative expense (cash) $ 1.60 $ 1.48 8 % $ 1.21 $ 1.03 17 %
Interest expense $ 1.89 $ 1.65 15 % $ 1.79 $ 1.52 18 %
Adjusted EBITDAX (1) $ 17,469,135 $ 17,222,786 1 % $ 80,974,336 $ 77,145,044 5 %
Capital expenditures
Property acquisition – proved $

$ 14,101 $

$ 954,687
Leasehold acquisitions 2,015,834 4,322,615 7,274,048 12,014,182
Exploratory (96,445 ) 4,047,025 9,696,858 9,672,150
Development 3,049,970 18,560,436 62,338,165 65,813,745


25,410 5,416
$ 4,969,359 $ 26,944,177 $ 79,334,481 $ 88,460,180
Weighted Average Shares Outstanding
Basic 44,269,388 43,904,661 44,147,787 44,788,551
Diluted 44,269,388 43,904,661 44,147,787 44,788,551

(1) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).
December 31,
2012         2011

Accounts receivable $ 11,726,078 $ 16,059,667

Current mark-to-market value of derivatives
1,892,744 4,538,897
Other current assets 844,495 473,616
Deferred tax asset (current and non-current) 52,171,316 17,297,621
Net property and equipment 300,827,480 396,781,299
Other non-current assets 1,158,276 1,174,774
TOTAL ASSETS $ 368,620,389 $ 436,325,874


Current mark-to-market value of derivatives

$ 290,703
Other current liabilities 38,685,288 66,795,433
Long-term debt 239,368,865 190,041,933
Other non-current liabilities 10,724,119 9,692,107
Total stockholders’ equity 79,842,117 169,505,698
TOTAL LIABILITIES & STOCKHOLDERS’ EQUITY $ 368,620,389 $ 436,325,874
Three Months Ended Twelve Months Ended
December 31, December 31,
2012       2011 2012         2011
Crude oil sales $ 17,927,755 $ 11,041,070 $ 78,591,313 $ 36,760,014
Natural gas sales 7,026,416 11,655,237 26,459,983 56,666,485
Natural gas liquids sales 2,968,799 4,738,928 10,852,720 20,209,534
Total operating revenues 27,922,970 27,435,235 115,904,016 113,636,033
Lease operating expenses 3,712,099 3,673,140 15,270,587 13,273,760
Production and ad valorem taxes 1,765,742 1,278,531 2,492,117 6,732,545
Exploration expenses 129,610 40,506 292,651 995,412
Depreciation, depletion and amortization 15,352,615 15,608,642 58,764,443 56,920,515
Impairment and abandonment of oil and gas properties 115,556,718 733,900 117,890,239 14,954,633
General and administrative 5,634,234 5,719,826 19,653,468 18,420,570
(Gain) loss on sale of assets


(8,900 )

Total operating expenses 142,151,018 27,054,545 214,354,605 111,297,435
INCOME (LOSS) FROM OPERATIONS (114,228,048 ) 380,692 (98,450,589 ) 2,338,598
Interest expense

) (6,075,946 ) (25,327,411 ) (25,104,073 )
Other income (expense) and financing costs (191,667 ) (225,680 ) (644,755 ) (1,633,170 )
Unrealized (loss) gain on derivative instruments (235,875 ) (1,604,327 ) (2,288,189 ) 454,906
Total other expense (6,842,439 ) (7,905,953 ) (28,260,355 ) (26,282,337 )
LOSS BEFORE INCOME TAXES (121,070,487 ) (7,525,261 ) (126,710,944 ) (23,943,739 )
Income tax benefit 33,413,522 2,525,804 34,719,589 8,098,357
NET LOSS $ (87,656,965 ) $ (4,999,457 ) $ (91,991,355 ) $ (15,845,382 )

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 the credit agreements representing our senior credit facility and our second lien credit facility.

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 credit agreements. 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 Twelve Months Ended
December 31, December 31,
2012       2011 2012      


Net loss $ (87,656,965 ) $ (4,999,457 ) $ (91,991,355 )


(15,845,382 )
Interest expense 6,414,897 6,075,946 25,327,411 25,104,073
Income tax benefit (33,413,522 ) (2,525,804 ) (34,719,589 ) (8,098,357 )
Depreciation, depletion and amortization 15,352,615 15,608,642 58,764,443 56,920,515
Exploration expenses 129,610 40,506 292,651 995,412
EBITDAX (99,173,365 ) 14,199,833 (42,326,439 ) 59,076,261
Unrealized loss (gain) on derivative instruments 235,875 1,604,327 2,288,189 (454,906 )
Non-cash equity-based compensation charges 658,240 459,046 2,486,492 1,935,886
Impairment and abandonment of oil and gas properties 115,556,718 733,900 117,890,239 14,954,633
Other income (expense) and financing costs 191,667 225,680 644,755 1,633,170
(Gain) loss on sale of assets


(8,900 )

Adjusted EBITDAX





Guidance for First Quarter 2013

The Company is providing the following updated guidance for the first calendar quarter of 2013.
First quarter 2013 production 34,000 – 35,000 Mcfe per day
Lease operating expenses ($M), including workovers $4,600 – $4,800
Production and ad valorem taxes 8% of actual prices
Cash G&A ($M) $3,500 – $4,000
DD&A rate $4.00 – $4.25 per Mcfe

Teleconference Call

Crimson management will hold a conference call to discuss the information described in this press release on Monday, March 18, 2013 at 9:30 a.m. CDT. Those interested in participating may do so by calling the following phone number: (888) 359-3627, (International: (719) 325-2458) and entering the following participation code: 5562645. A replay of the call will be available from Monday, March 18, 2013 at 11:30 a.m. CDT through Sunday, March 24, 2013 at 11:30 p.m. CDT by dialing toll free: (888) 203-1112, (International: (719) 457-0820) and asking for replay ID code 5562645.

Crimson Exploration is a Houston, TX-based independent energy company engaged in the exploitation, exploration, development and acquisition of crude oil and natural gas, primarily in the onshore Gulf Coast regions of the United States. The Company currently owns approximately 95,000 net acres onshore in Texas, Louisiana, Colorado and Mississippi, including approximately 19,000 net acres in Madison and Grimes counties in Southeast Texas, approximately 8,600 net acres in the Eagle Ford Shale in South Texas, approximately 10,000 net acres in the DJ Basin of Colorado, and approximately 4,800 net acres in the Haynesville Shale and Mid-Bossier gas plays and James Lime gas/liquids play in East Texas.

Additional information on Crimson Exploration Inc. is available on the Company's website at

This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”) and applicable securities laws. 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, cash flow operating results, leverage, drilling rigs operating, drilling locations, funding, derivative transactions, pricing, operating costs and capital spending, tax rates, and descriptions of our development plans 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, the proximity to and capacity of transportation facilities, the timing of planned capital expenditures, uncertainties in estimating reserves and forecasting production results, operating and drilling risks, regulatory changes and the potential lack of capital resources. All forward-looking statements are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. 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, 2012, and subsequent filings for a further discussion of these risks. Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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