Crimson Exploration Announces Fourth Quarter and Full Year 2012 Financial Results and an Operational Update

  Crimson Exploration Announces Fourth Quarter and Full Year 2012 Financial
  Results and an Operational Update

Business Wire

HOUSTON -- March 15, 2013

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 $17.5million 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 $87.7million, or ($1.98)per basic share, for the fourth quarter of 2012
compared to a net loss of $5.0million, or ($0.11) per basic share, for the
fourth quarter of 2011. Special non-cash items impacting the fourth quarter of
2012 were a $115.6million 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 $1.6million related to the mark-to-market
valuation on commodity price hedges and a $0.7 million leasehold impairment

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
36,840Mcfe 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
$7.87per Mcfe compared to an average field sales price of $6.72for 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 $8.24per Mcfe compared to a weighted average
realized sales price of $7.45per 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 $3.7million, or
$1.10per Mcfe, compared to $3.7million, or $1.00per 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 of2012 were
$1.8million, or $0.52 per Mcfe, compared to $1.3million, or $0.35 per Mcfe,
for the fourth quarter of2011, 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 $15.4million, or $4.53per Mcfe, compared to
$15.6million, 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

In 2012, Crimson recorded an income tax benefit of $34.7 million compared to
$8.1million in 2011. The income tax benefit of $34.7million is net of a
$10.2million 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 $1.66per Mcfe, compared to $5.7million, or $1.55per Mcfe, in
the fourth quarter of 2011. General and administrative expenses, exclusive of
non-cash stock option expense recognized in each quarter, was $5.0million for
the fourth quarter of 2012 compared to $5.3 million for fourth quarter of

2012 & 2013 Capital Programs

Capital expenditures for the fourth quarter of 2012 were $5.0million,
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 /        IP Rate       Liquids       IP
                         %          Formation                     - %           Date
Southeast Texas
Mosley #1H               84.3       Madison /       1,203         91.8          Mar
                                    Woodbine        Boepd                       2012
Pavelock #1H             2.7        Madison /       1,808         85.7          Mar
                                    Woodbine        Boepd                       2012
Vick Trust #1H           75.0       Madison /       383           74.9          May
                                    Woodbine        Boepd                       2012
Grace Hall #1H           82.5       Madison /       1,080         87.5          June
                                    Woodbine        Boepd                       2012
A. Yates #1H             50.0       Grimes /        472           90.9          June
                                    Woodbine        Boepd                       2012
Payne #1H                92.1       Madison /       1,332         93.1          July
                                    Woodbine        Boepd                       2012
Catherine                60.8       Liberty /       7.2           47.0          Aug
Henderson A-6 ST                    Cook Mtn.       Mmcfepd                     2012
Covington-Upchurch       67.8       Grimes /        6.9           33.4          Nov
#1H*                                Woodbine        Mmcfepd                     2012
Gatlin #1H               3.1        Madison /       1,436         88.1          Dec
                                    Woodbine        Boepd                       2012
South Texas
Littlepage McBride                  Karnes /        1,019                       Jan
#7H                      53.0       Eagle           Boepd         89.0          2012
                                    Dimmit /        370                         Feb
Beeler #1H               50.0       Eagle           Boepd         91.1          2012
                                    Karnes /        726                         Mar
Glasscock A #1H          95.5       Eagle           Boepd         91.6          2012
                                    Karnes /        685                         May
Glasscock B #1H          90.7       Eagle           Boepd         89.8          2012
                                    Zavala /        511                         Aug
KM Ranch #2H             50.0       Eagle           Boepd         89.4          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

Crimson’s 2013 capital budget is currently forecasted to be approximately
$58.7million 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

2012 Year End Reserves

Proved reserves at December31, 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 117.0Bcfe, consisting of 61.9billion cubic
feet of natural gas, 6.2million 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 $340.1million.

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 December31, 2012, 53% of proved reserves were natural gas, 54% were
proved developed and 90% were attributed to wells and properties operated by

The following table summarizes Crimson’s total proved reserves as of December
31, 2012:

                  Net Reserves                                         Present
                  Oil       NGL       Gas       Total         Discounted
Category          (MBBL)       (MBBL)       (MMCF)       (MMCFE)       at 10%
Developed         2,343        1,686        39,554       63,732        $   197.9
Undeveloped       3,859        1,306        22,330       53,317           142.2
Total             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
Crude oil                169,267              113,986          48  %           753,980            396,760          90  %
Natural gas              1,865,312            2,440,817        -24 %           7,799,301          11,675,602       -33 %
Natural gas              84,772               93,286           -9  %           300,435            417,956          -28 %
liquids (bbls)
Natural gas
equivalents              3,389,546            3,684,449        -8  %           14,125,791         16,563,898       -15 %
Daily Sales
Crude oil                1,840                1,239            48  %           2,060              1,087            90  %
Natural gas              20,275               26,531           -24 %           21,310             31,988           -33 %
Natural gas              921                  1,014            -9  %           821                1,145            -28 %
liquids (bbls)
Natural gas
equivalents              36,843               40,048           -8  %           38,595             45,381           -15 %
Average sales
prices (before
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  %
realized sales
price (after
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):
operating              $ 1.10               $ 1.00             10  %         $ 1.08             $ 0.80             35  %
Production and
ad valorem             $ 0.52               $ 0.35             50  %         $ 0.18             $ 0.41             -57 %
and depletion          $ 4.53               $ 4.24             7   %         $ 4.16             $ 3.44             21  %
General and
administrative         $ 1.60               $ 1.48             8   %         $ 1.21             $ 1.03             17  %
expense (cash)
Interest               $ 1.89               $ 1.65             15  %         $ 1.79             $ 1.52             18  %
Adjusted               $ 17,469,135         $ 17,222,786       1   %         $ 80,974,336       $ 77,145,044       5   %
acquisition –          $ -                  $ 14,101                         $ -                $ 954,687
Leasehold                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
Other                    -                    -                                25,410             5,416
                       $ 4,969,359          $ 26,944,177                     $ 79,334,481       $ 88,460,180
Average Shares
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              1,892,744             4,538,897
Other current assets                         844,495               473,616
Deferred tax asset (current and              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            $ -                   $ 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’          $ 368,620,389         $ 436,325,874

                       Three Months Ended                            Twelve Months Ended
                       December 31,                                  December 31,
                       2012                2011                   2012                 2011
Crude oil              $ 17,927,755           $ 11,041,070           $ 78,591,313             $ 36,760,014
Natural gas              7,026,416              11,655,237             26,459,983               56,666,485
Natural gas              2,968,799              4,738,928              10,852,720               20,209,534
liquids sales
operating                27,922,970             27,435,235             115,904,016              113,636,033
operating                3,712,099              3,673,140              15,270,587               13,273,760
Production and
ad valorem               1,765,742              1,278,531              2,492,117                6,732,545
Exploration              129,610                40,506                 292,651                  995,412
depletion and            15,352,615             15,608,642             58,764,443               56,920,515
Impairment and
abandonment of           115,556,718            733,900                117,890,239              14,954,633
oil and gas
General and              5,634,234              5,719,826              19,653,468               18,420,570
(Gain) loss on           -                      -                      (8,900       )           -
sale of assets
operating                142,151,018            27,054,545             214,354,605              111,297,435
FROM                     (114,228,048 )         380,692                (98,450,589  )           2,338,598
Interest                 (6,414,897   )         (6,075,946 )           (25,327,411  )           (25,104,073 )
Other income
(expense) and            (191,667     )         (225,680   )           (644,755     )           (1,633,170  )
(loss) gain on           (235,875     )         (1,604,327 )           (2,288,189   )           454,906
Total other              (6,842,439   )         (7,905,953 )           (28,260,355  )           (26,282,337 )
LOSS BEFORE              (121,070,487 )         (7,525,261 )           (126,710,944 )           (23,943,739 )
Income tax               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                2011
Net loss              $ (87,656,965 )       $ (4,999,457 )         $ (91,991,355 )        $ (15,845,382 )
Interest                6,414,897             6,075,946              25,327,411              25,104,073
Income tax              (33,413,522 )         (2,525,804 )           (34,719,589 )           (8,098,357  )
depletion and           15,352,615            15,608,642             58,764,443              56,920,515
Exploration             129,610               40,506                 292,651                 995,412
EBITDAX                 (99,173,365 )         14,199,833             (42,326,439 )           59,076,261
loss (gain)             235,875               1,604,327              2,288,189               (454,906    )
on derivative
equity-based            658,240               459,046                2,486,492               1,935,886
abandonment             115,556,718           733,900                117,890,239             14,954,633
of oil and
Other income
(expense) and           191,667               225,680                644,755                 1,633,170
(Gain) loss
on sale of              -                     -                      (8,900      )           -
Adjusted              $ 17,469,135          $ 17,222,786           $ 80,974,336            $ 77,145,044

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),                  $4,600 – $4,800
        including workovers
        Production and ad valorem taxes                 8% of actual prices
        Cash G&A ($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 9:30a.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. Areplay of the call will be available
from Monday, March 18, 2013 at 11:30a.m. CDT through Sunday, March 24, 2013
at 11:30p.m. CDT by dialing toll free: (888) 203-1112, (International: (719)
457-0820) and asking for replay ID code5562645.

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.


Crimson Exploration Inc.
E. Joseph Grady, 713-236-7400
Senior Vice President and Chief Financial Officer
Josh Wannarka, 713-236-7400
Manager of Investor Relations and FP&A
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