Quicksilver Resources Reports Preliminary 2012 Fourth-Quarter and Full-Year Results

Quicksilver Resources Reports Preliminary 2012 Fourth-Quarter and Full-Year

FORT WORTH, Texas, Feb. 25, 2013 (GLOBE NEWSWIRE) -- Quicksilver Resources
Inc. (NYSE:KWK) today announced preliminary 2012 fourth-quarter and full-year

2012 highlights:

  *Produced 132 billion cubic feet of natural gas equivalent (Bcfe)
  *Posted stellar results from the company's first multi-well pad in the Horn
    River Basin; initial production rates were between 23 MMcfd and 34 MMcfd
    per well at very high flowing pressures
  *Established oil production in two U.S. projects
  *Advanced negotiations in Barnett sale and Horn River joint venture
  *Reduced near-term capital and letter-of-credit obligations in the Horn
    River Basin
  *Secured financial covenant flexibility in Combined Credit Agreements
  *Closed Sand Wash Basin Acquisition and Exploration Agreement with SWEPI LP
  *Reduced overall company cost structure
  *Increased derivative portfolio to cover nearly 70 percent of expected 2013
    natural gas production at a weighted average price of $5.10 per Mcf

"Our top priorities are to improve liquidity through asset sales, joint
ventures and other measures, further reduce the overall company cost
structure, and match capital spending to operational cash flow," said Glenn
Darden, Quicksilver's President and Chief Executive Officer. "We are
progressing on all of these objectives, which should make us a stronger
company, able to operate more efficiently and effectively in the current
market environment and beyond."

Financial Results

Adjusted net loss for the fourth quarter, a non-GAAP financial measure, was $2
million, or $0.01 per diluted share, compared to breakeven adjusted net income
in the 2011 period. Reported net loss for the fourth quarter, which includes
the impact of a non-cash ceiling test impairment primarily generated by a
change in hedge accounting, was $1.1 billion, or $6.47 per diluted share. This
compares to net income of $24 million, or $0.14 per diluted share, in the
prior-year period.

Adjusted net loss for full-year 2012 – also a non-GAAP financial measure – was
$46 million, or $0.27 per diluted share, compared to net income of $20
million, or $0.12 per diluted share for full-year 2011. Including the impact
of non-cash impairments and other non-operational items, the net loss for
full-year 2012 was $2.5 billion, or $14.61 per diluted share compared to net
income of $90 million, or $0.52 per diluted share for full-year 2011.

The presentation of quarterly and full-year results are preliminary as the
company continues to analyze the non-cash accounting treatment of its hedge
portfolio and deferred tax balances. The company expects to issue its final
results for the year and quarters upon completion of that undertaking.

Impairments and Non-operational Items Included in Fourth-Quarter and Full-Year
2012 Results

Quicksilver's fourth-quarter 2012 results include a $1.2 billion non-cash
ceiling test impairment, of which 63% is attributable to a change in
accounting policy. The company elected at year-end to discontinue hedge
accounting to improve the comparability of financial results to its peers, and
consequently, the value of the hedge portfolio based on SEC reserve pricing
can no longer be included as part of the full-cost ceiling test. The book
value of Quicksilver's derivative portfolio at December 31, 2012 was $201

The remaining 37% of the impairment is attributable to 2012 reserve revisions
related to price, performance and the reclassification of existing proved
undeveloped reserves (PUD) that are not expected to be developed within the
SEC's prescribed five-year timeframe due to a reduction in drilling activity
amid depressed natural gas and NGL prices.

Fourth-quarter 2012 results also include a $326 million non-cash valuation
allowance of U.S. deferred tax assets related to the likelihood of
recoverability of future tax assets, which is driven by the continued
generation of net-operating losses as a result of the non-cash impairments.

Full-year results include, but are not limited to, non-cash property
impairments of $2.8 billion and $609 million of non-cash valuation allowances
of U.S. deferred tax assets.

These charges are non-cash and do not reflect the current market value of
Quicksilver's assets, nor do they impact its ability to realize its strategic
and operational objectives.

Further details of non-operational items and adjusted net income are included
in the tables accompanying this earnings release.


Fourth-quarter 2012 production was 31.5 Bcfe, or an average of 342 million
cubic feet of natural gas equivalent per day (MMcfed). Production from the
company's Barnett Shale was 22.7 Bcfe, or 247 MMcfed, which is down 6% from
the previous quarter due to a reduction in capital activity. Production from
Canada was 8.5 Bcfe, or 92 MMcfed, which was substantially less than the
productive capabilities of the asset, as Horn River volumes were restricted by
approximately 50% during most of the fourth quarter due to the continued
delays in commissioning of a third-party treating facility. In mid-December,
the company began ramping up Horn River production to 100 MMcfd of raw gas
after it secured alternative treating and transportation arrangements on an
interim and interruptible basis.

Full-year 2012 production was 132 Bcfe, or an average of 360 MMcfed.
Production for the first 45 days of 2013 was 16.8 Bcfe, or an average of 366

Revenue and Expenses

Production revenue for the fourth quarter of 2012 was $156 million and $636
million for full-year 2012. The company restructured certain long-term
commodity hedges in 2012, and as a result, the revenue from these restructured
hedges is recognized in production revenue based on the settlement dates of
the original contracts. However, the company received approximately $16
million of cash proceeds from these restructured hedges in the fourth quarter
2012, and approximately $64 million for full-year 2012, which will not be
recognized in revenue until future periods.

The average realized price for the fourth quarter and full-year 2012 was $4.96
and $4.83 per Mcfe, respectively, which excludes approximately $0.51 per Mcfe
for the fourth quarter and $0.48 per Mcfe for full-year 2012, of cash proceeds
from restructured hedges.

Lease operating expense for the fourth quarter of 2012 was $23 million, or
$0.73 per Mcfe, compared to $30 million, or $0.78 per Mcfe in the prior-year
quarter and $22 million, or $0.66 per Mcfe in the third quarter. Lease
operating expense in the Barnett Shale declined 42% compared to the prior year
quarter due to lower water hauling, compression and gas lift expense through
continued cost containment initiatives. Lease operating expense in the Horn
River Basin decreased 14% compared to the 2011 quarter due to a decline in
compression repair and maintenance expense.

Cash Flow

Operating cash flow for the fourth quarter was $81 million, and investing cash
flows provided a net inflow of $25 million after receipt of approximately $69
million in proceeds from sales of properties.

2012 Capital Program, 2013 Capital Budget and Debt

The company incurred approximately $31 million of capital expenditures in the
fourth quarter of 2012, of which approximately $10 million was associated with
drilling and completion activities, $7 million for acreage purchases, and $14
million for capitalized interest and overhead costs. For the full-year 2012,
total capital incurred was $390 million.

The company intends to invest a total of approximately $120 million in 2013,
which is a reduction of $270 million compared to 2012. The reduction is
primarily the result of lower spending in the Horn River Basin, but also is
the result of planned reductions across the asset base as the company resolves
to limit spending to expected operational cash flow. This budget, which
includes leasehold acquisition and amounts for capitalized interest and
overhead, is expected to result in a production decline of approximately 5% in
2013 compared to 2012.

The capital budget does not factor in proceeds from potential strategic
partnerships or asset sales.

At December 31, 2012, Quicksilver's total debt was approximately $2.1 billion,
or approximately $100 million less than the previous quarter. Included within
debt, the company had approximately $450 million utilized under its Combined
Credit Agreements as of year-end 2012, resulting in approximately $400 million
of remaining capacity. The majority of the debt reduction is due to the
repayment of credit facility borrowings with the joint venture proceeds from
the Niobrara transaction.

The semiannual redetermination of the Combined Credit Agreements is scheduled
for April 2013. The company expects a yet-to-be determined reduction in the
borrowing base; however, after redetermination, the credit facility is
expected to provide adequate liquidity to execute planned initiatives.

Quicksilver's 2013 budget and projections yield continued credit facility
covenant compliance and sufficient liquidity through 2013, but if prices
deteriorate, the company may reduce the capital program, reduce headcount and
expenses, and/or work with the lender group to amend the covenant
requirements. Additionally, successful consummation of a strategic transaction
would also allow continued covenant compliance.

First Quarter 2013 and Full-Year 2013 Outlook

First-quarter 2013 average daily production volume is expected to be 360 - 365
MMcfe per day, and full-year production volume is expected to be 335 - 345
MMcfe per day, originating as follows: 65% in the Barnett Shale, 33% in
Canada, and 2% in other U.S. basins. Average daily production volumes are
expected to consist of 82% natural gas and 18% natural gas liquids and crude

For the first quarter of 2013, average unit expenses, on a Mcfe basis, are
expected as follows:

* Lease operating expense                $0.80 - $0.82
* Gathering, processing & transportation 1.20 -1.22
* Production and ad-valorem taxes        0.14 -0.16
* General and administrative             0.55 -0.57
* Depletion, depreciation & accretion    0.52 -0.54


The company's natural gas swap portfolio is as follows: 200 MMcfd for 2013 at
a weighted-average price of $5.10 per Mcf, 170 MMcfd for 2014 at $5.08 per
Mcf, 150 MMcfd for 2015 at $5.23 per Mcf, and 40 MMcfd for 2016-2021 at $4.48
per Mcf.

Effective December 31, 2012, the company discontinued the use of hedge
accounting on all existing hedge contracts. The net deferred hedge gains that
are included in Accumulated Other Comprehensive Income as of December 31, 2012
will be recognized as production revenue during the periods in which the
hedged transaction occurs.

Operational Update


The company's Horn River Basin Asset began ramping-up production in
mid-December 2012 to 100 MMcfd of raw natural gas, which is being sourced from
ten out of the twelve wells capable of production in the basin. Four wells
have been producing for over 18 months, and six wells were brought online in
stages since the d-50 pad was completed in the third quarter of 2012. Two
wells on the d-50 pad are currently shut-in and will be brought online as
additional volumes are needed to meet minimum commitments. Net sales volume
after CO[2] treating is expected to be approximately 80 MMcfd based on gross
production of 100 MMcfd.

On January 30, 2013, the Canadian National Energy Board (NEB) issued its
report recommending against approval of NOVA Gas Transmission Ltd.'s (NGTL)
Komie North pipeline extension project (Project), which proposed construction
of a 75-mile pipeline to connect NGTL's Alberta system to a meter station
planned to be constructed on the company's acreage in the Horn River Basin.
The company believes the NEB's recommendation against the Project will be
adopted by the federal authority.

The NEB concluded that the evidence presented at this time did not justify a
36-inch line as proposed; however, its recommendation notwithstanding, the NEB
emphasized its belief in the long-term prospects for development of the Horn
River Basin. The company believes NGTL will undertake efforts to secure
additional shipper support for building of this 36" line.

In connection with the Project, the company had previously provided $30
million in letters of credit, which is expected to be reduced to $15 million
or completely eliminated through a cash payment. Future financial assurances
upon a revised application would be reduced proportionately to the extent of
any additional shipper support and are expected to be delayed by up to two
years. Consequently, Quicksilver is planning to defer drilling in the Horn
River Basin until 2014 and will likely defer construction of a natural gas
treating facility until at least 2016 to coincide with any new projected
timelines for the Project.

The company's ability to sell gas at the Station 2 and AECO hubs has not been
impacted by the NEB's recommendation, as its acreage is served by existing
treating facilities and pipelines which today can accommodate in excess of 1
billion cubic feet per day. Due to the pace of development in the basin by all
producers, discounted excess capacity is available in the region to meet
Quicksilver's needs.

Quicksilver's treating and transportation commitment in the Horn River is
scheduled to step up to 100 MMcfd on May 1, 2013, assuming the start-up of a
third-party treating facility, where it remains until 2018. The gathering,
treating and transportation obligation will remain at the 100 MMcfd gross
production level until the next scheduled step-up of the Fortune Creek
gathering commitment, which the company has the option to defer to as late as

The company continues to negotiate a potential joint venture in the Horn River
Basin, with the downstream marketing of the gas a top priority.

Production from Horseshoe Canyon was 55 MMcfd during the fourth quarter.
Development activity in Horseshoe Canyon will continue to be limited in 2013.

United States - Barnett Shale

Quicksilver drilled one well in the fourth quarter, which is expected to be
completed in the second half of 2013. For full-year 2012, the company drilled
22 gross (20.6 net) wells and connected 31 gross (26.7 net) wells to sales. At
December 31, 2012, Quicksilver had a remaining uncompleted well inventory of
25 gross operated wells that have been drilled in the Barnett Shale but await
completion or connection to sales lines.

Quicksilver is engaged in confidential negotiations with a potential buyer to
sell a non-operated minority working interest in its Barnett Shale Asset.

United States - Sand Wash Basin

In the fourth quarter, Quicksilver completed its most recent vertical well
with initial production of 400 barrels of oil equivalent per day (Boed), which
was partially restricted due to surface facility limitations. The well
averaged 138 Boed - of which 60% is oil - for the first 90 days of production.
With this well, the company has now found oil-productive Niobrara across a
distance of 35 miles in an east-to-west band and 7 miles on a north-to-south
band on its leasehold in Moffat and Routt counties.

The company closed on its Acquisition and Exploration Agreement with SWEPI LP,
a subsidiary of Royal Dutch Shell plc, on December 28, 2012. Quicksilver now
owns a 50% interest in over 320,000 net acres in the Sand Wash Basin in
Northwest Colorado, which will be jointly developed with SWEPI. The agreement
also established an Area of Mutual Interest covering in excess of 850,000
acres in the basin.

United States - West Texas

In the fourth quarter, the company completed the Vande Ranch State 1H,
Quicksilver's second short-lateral well, which targeted the Wolfcamp formation
in Upton County. The well is producing 38 Boed and continues to improve after
recovering 32% of its load water. The Price Ranch #1H well, Quicksilver's
first short lateral well drilled in Pecos County, averaged 129 Boed over its
first 100 days of production from the Bone Springs formation.

Quicksilver holds approximately 105,000 net acres across the Delaware and
Midland basins of West Texas, which are situated in the oil window of the
Wolfcamp and Bone Springs formations.


The Securities and Exchange Commission (SEC) requires proved reserve volumes
to be calculated using an average of the NYMEX and West Texas Intermediate
(WTI) spot prices for sales of gas and crude oil, respectively, on the first
calendar day of each month during the reporting year. On this basis, the
prices for gas and crude oil for 2012 reserves reporting purposes were $2.76
per million British thermal units (MMbtu) and $94.71 per barrel. The prices
used to calculate proved reserves for year-end 2011 were $4.12 per MMBtu of
gas and $95.71 per barrel of crude oil.

Quicksilver's preliminary year-end 2012 SEC proved reserves based on SEC
pricing total approximately 1.5 trillion cubic feet of natural gas equivalents
(Tcfe). The company's total proved developed reserves percentage increased to
88% from 69% in the prior year as more than 90% of the wells drilled in the
Barnett Shale in 2012 were proved undeveloped (PUD) locations at year-end
2011. A significant amount of proved undeveloped reserves were no longer
recognized as proved reserves based on both future development plans and
prices used to determine 2012 SEC reserves.

The changes in proved reserves from 2011 proved reserves include revisions of
approximately 1.3 Tcfe based on lower SEC prices, changes in well performance,
operating cost, future development plans, and other factors, as well as a
reclassification of some of our undeveloped locations from proved reserves as
they were not developed within five years of first recognition. The company
has been directing a large portion of its capital budget to the Horn River
Basin and new ventures in the U.S., and therefore, fewer Barnett Shale PUDs
are expected to be drilled within the SEC's prescribed five-year timeframe.

Reserves by product are 76% natural gas, 23% NGL, and 1% crude oil and
condensate. Geographically, 82% of reserves were located in the U.S.,
primarily in the Barnett Shale, and 18% in Canada.

Reserve Price Sensitivity

Quicksilver's reserves are directly correlated to the market price for natural
gas, natural gas liquids, and oil, which are traded daily on commodity
exchanges and are subject to market price fluctuation. Due to SEC rules, the
company reports year-end reserves using an average of the first day of the
month spot prices for the preceding twelve months, as disclosed above. As
commodity prices rise above the year-end SEC average price – as natural gas
prices currently have – Quicksilver's proved reserves may increase.
Conversely, proved reserves may decrease further should prices fall below the
year-end SEC average price.

Quicksilver's reserves are most sensitive to a change in the NYMEX gas price
because natural gas is approximately 76% of the company's year-end 2012
reserves. The company estimates that a $0.50 per MMbtu increase in the
benchmark natural gas price and $5 per barrel increase in the benchmark oil
price would increase proved reserves by 21% to 1.8 Tcfe, and a $0.50 per MMbtu
decrease in the benchmark natural gas price and $5 per barrel decrease in the
benchmark oil price would decrease proved reserves by 13% to 1.3 Tcfe. These
sensitivities are based solely on current reserves and may not provide an
accurate view of the company's proved reserves in a previous year or by
extrapolating higher or lower pricing increments than what has been provided.

Current strip prices for 2013 natural gas are approximately $0.72 per MMbtu
higher than the 2012 SEC price.

2012 Preliminary Reserves

                               Natural Gas Natural Gas Oil and
                              (Bcf)       Liquids     Condensate Total (Bcfe)
                                           (MBbl)      (MBbl)
Proved Reserves, December 31,  2,160      102,156    3,035     2,791
Revisions                      (944)      (45,378)   (479)     (1,219)
Extensions, Discoveries, and   26         3,518      345       49
Other Additions
Production                     (106)      (4,070)    (287)     (132)
Acquisitions & Dispositions,   (21)       (42)       (85)      (22)
Proved Reserves, December 31,  1,115      56,184     2,529     1,467
Reserve pricing (first of
month trailing 12-month        2.76                  94.71     
Barnett Shale                  724        47,117     76        1,007
Sand Wash                      —          —          85        1
West Texas                     —          —          83        —
Other U.S.                     1          167        2,172     15
Total U.S.                     725        47,284     2,416     1,023
Horn River                     105        —          —         105
Horseshoe Canyon               162        10         —         162
Total Canada                   267        10         —         267
Total Quicksilver              992        47,294     2,416     1,290
Barnett Shale                  123        8,890      113       177
Total Quicksilver              123        8,890      113       177
Total Proved                   1,115      56,184     2,529     1,467

Conference Call

The company will host a conference call to discuss preliminary fourth-quarter
operating and financial results at 10:00 a.m. central time today.

Quicksilver invites interested parties to listen to the call via the company's
website at www.qrinc.com or by calling 1-877-313-7932, using the conference ID
number 88746679, approximately 10 minutes before the call.A digital replay of
the conference call will be available at 2:00 p.m. central time the same day,
and will remain available for 30 days.The replay can be dialed at
1-855-859-2056 using the conference ID number 88746679.The replay will also
be archived for 30 days on the company's website.

Use of Non-GAAP Financial Measure

This news release and the accompanying schedule include the non-generally
accepted accounting principles ("non-GAAP") financial measure of adjusted net
income.The accompanying schedule provides reconciliations of this non-GAAP
financial measure to its most directly comparable financial measure calculated
and presented in accordance with accounting principles generally accepted in
the United States of America ("GAAP").Our non-GAAP financial measure should
not be considered as an alternative to GAAP measures such as net income or
operating income or any other GAAP measure of liquidity or financial

About Quicksilver Resources

Fort Worth, Texas-based Quicksilver Resources is an independent oil and gas
company engaged in the exploration, development and acquisition of oil and
gas, primarily from unconventional reservoirs including gas from shales and
coal beds in North America.The company has U.S. offices in Fort Worth, Texas;
Glen Rose, Texas; Craig, Colorado; Steamboat Springs, Colorado and Cut Bank,
Montana.Quicksilver's Canadian subsidiary, Quicksilver Resources Canada Inc.,
is headquartered in Calgary, Alberta.For more information about Quicksilver
Resources, visit www.qrinc.com.

Forward-Looking Statements

Certain statements contained in this press release and other materials we file
with the SEC, or in other written or oral statements made or to be made by us,
other than statements of historical fact, are "forward-looking statements" as
defined in the Private Securities Litigation Reform Act of
1995.Forward-looking statements give our current expectations or forecasts of
future events.Words such as "may," "assume," "forecast," "position,"
"predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate,"
"believe," "project," "budget," "potential," or "continue," and similar
expressions are used to identify forward-looking statements.They can be
affected by assumptions used or by known or unknown risks or
uncertainties.Consequently, no forward-looking statements can be
guaranteed.Actual results may vary materially.You are cautioned not to place
undue reliance on any forward-looking statements.You should also understand
that it is not possible to predict or identify all such factors and should not
consider the following list to be a complete statement of all potential risks
and uncertainties.Factors that could cause our actual results to differ
materially from the results contemplated by such forward-looking statements
include: changes in general economic conditions; fluctuations in natural gas,
NGL and oil prices; failure or delays in achieving expected production from
exploration and development projects; uncertainties inherent in estimates of
natural gas, NGL and oil reserves and predicting natural gas, NGL and oil
reservoir performance; effects of hedging natural gas, NGL and oil prices;
fluctuations in the value of certain of our assets and liabilities;
competitive conditions in our industry; actions taken or non-performance by
third parties, including suppliers, contractors, operators, processors,
transporters, customers and counterparties; changes in the availability and
cost of capital; delays in obtaining oilfield equipment and increases in
drilling and other service costs; delays in construction of transportation
pipelines and gathering, processing and treating facilities; operating
hazards, natural disasters, weather-related delays, casualty losses and other
matters beyond our control; the effects of existing and future laws and
governmental regulations, including environmental and climate change
requirements; failure or delay in completing strategic transactions; the
effects of existing or future litigation; failure or delays in completing
Quicksilver's proposed initial public offering of common units representing
limited partner interests in a master limited partnership holding portions of
our Barnett Shale assets; and additional factors described elsewhere in this
press release.

This list of factors is not exhaustive, and new factors may emerge or changes
to these factors may occur that would impact our business.Additional
information regarding these and other factors may be contained in our filings
with the SEC, especially on Forms 10-K, 10-Q and 8-K.All such risk factors
are difficult to predict, and are subject to material uncertainties that may
affect actual results and may be beyond our control.The forward-looking
statements included in this press release are made only as of the date of this
press release, and we undertake no obligation to update any of these
forward-looking statements to reflect subsequent events or circumstances
except to the extent required by applicable law.

All forward-looking statements are expressly qualified in their entirety by
the foregoing cautionary statements.

Investor & Media Contact:
David Erdman
(817) 665-4023

KWK 13-03

In thousands, except for per share data - Unaudited
                              For the quarter ended   For the year ended
                               December 31,            December 31,
Revenue                        2012         2011       2012         2011
Production                     $156,294   $194,473 $636,316   $800,543
Sales of purchased natural gas 19,564      26,529    62,405      86,645
Other                          3,214       2,095     (27,916)    56,435
Total revenue                  179,072     223,097   670,805     943,623
Operating expense                                                
Lease operating                22,927      29,508    95,333      102,874
Gathering, processing and      39,277      48,359    166,316     190,560
Production and ad valorem      4,562       5,382     25,395      29,226
Costs of purchased natural gas 19,513      26,144    62,041      85,398
Depletion, depreciation and    35,677      60,902    185,266     225,763
Impairment                     1,162,961   57,996    2,764,464   107,059
General and administrative     20,861      17,837    75,697      79,582
Other operating                742         229       1,562       557
Total expense                  1,306,520   246,357   3,376,074   821,019
Crestwood earn-out             —           —         41,097      —
Operating income (loss)        (1,127,448) (23,260)  (2,664,172) 122,604
Income (loss) from earnings of —           24,282    —           (8,439)
Other income (expense) - net   1,345       84,327    1,108       219,768
Fortune Creek accretion        (4,923)     —         (19,472)    —
Interest expense               (41,703)    (43,901)  (164,051)   (186,024)
Income (loss) before income    (1,172,729) 41,448    (2,846,587) 147,909
Income tax (expense) benefit   71,807      (17,917)  361,438     (57,863)
Net income (loss)              (1,100,922) 23,531    (2,485,149) 90,046
Earnings (loss) per common     $(6.47)    $0.14    $(14.61)   $0.53
share - basic
Earnings (loss) per common     $(6.47)    $0.14    $(14.61)   $0.52
share - diluted

In thousands, except share data - Unaudited
                                                    As of December 31,
                                                    2012         2011
Current assets                                                   
Cash and cash equivalents                            $4,951     $13,146
Accounts receivable - net of allowance for doubtful  64,149      95,282
Derivative assets at fair value                      113,367     162,845
Other current assets                                 25,046      29,154
Total current assets                                 207,513     300,427
Property, plant and equipment - net                              
Oil and gas properties, full cost method (including
unevaluated costs of $307,267 and $433,341,          622,519     3,226,476
Other property and equipment                         248,098     234,043
Property, plant and equipment - net                  870,617     3,460,519
Derivative assets at fair value                      105,270     183,982
Deferred income taxes                                65,135      —
Other assets                                         39,947      50,534
                                                    $1,288,482 $3,995,462
Current liabilities                                              
Current portion of long-term debt                    $—         $18
Accounts payable                                     37,131      142,672
Accrued liabilities                                  130,660     142,193
Derivative liabilities at fair value                 —           4,028
Current deferred tax liability                       3,891       45,262
Total current liabilities                            171,682     334,173
Long-term debt                                       2,063,206   1,903,431
Partnership liability                                130,912     122,913
Asset retirement obligations                         115,949     85,568
Derivative liabilities at fair value                 17,485      —
Other liabilities                                    19,242      28,461
Deferred income taxes                                —           258,997
Stockholders' equity                                             
Preferred stock, par value $0.01, 10,000,000 shares  —           —
authorized, none outstanding
Common stock, $0.01 par value, 400,000,000 shares
authorized, and 179,015,118 and 176,980,483 shares   1,790       1,770
issued, respectively
Additional paid in capital                           760,341     737,015
Treasury stock of 5,921,102 and 5,379,702 shares,    (49,495)    (46,351)
Accumulated other comprehensive income               187,892     214,858
Retained earnings (deficit)                          (2,130,522) 354,627
Total stockholders' equity                           (1,229,994) 1,261,919
                                                    1,288,482   3,995,462

In thousands - Unaudited
                                              For the year ended December 31,
                                              2012              2011
Operating activities:                                           
Net income (loss)                              $(2,485,149)    $90,046
Adjustments to reconcile net income (loss) to                   
net cash provided by operating activities:
Depletion, depreciation and accretion          185,266          225,763
Impairment expense                             2,764,464        107,059
Crestwood earn-out                             (41,097)         —
Deferred income tax expense (benefit)          (356,937)        64,492
Non-cash (gain) loss from hedging and          96,058           (51,780)
derivative activities
Stock-based compensation                       22,246           20,862
Non-cash interest expense                      9,854            16,510
Fortune Creek accretion                        19,472           —
Gain on disposition of BBEP units              —                (217,893)
Loss (income) from BBEP in excess of cash      —                28,269
Other                                          1,037            1,311
Changes in assets and liabilities                               
Accounts receivable                            30,950           (31,803)
Derivative assets at fair value                —                —
Prepaid expenses and other assets              3,070            (6,017)
Accounts payable                               (13,317)         (11,434)
Income taxes payable                           1,183            (4,803)
Accrued and other liabilities                  (14,884)         22,471
Net cash provided by operating activities      222,216          253,053
Investing activities:                                           
Capital expenditures                           (481,057)        (690,607)
Proceeds from Crestwood earn-out               41,097           —
Proceeds from sale of BBEP units               —                272,965
Proceeds from sale of properties and equipment 72,725           4,163
Net cash provided (used) by investing          (367,235)        (413,479)
Financing activities:                                           
Issuance of debt                               467,959          855,822
Repayments of debt                             (310,430)        (843,108)
Debt issuance costs paid                       (3,022)          (12,506)
Partnership funds received                     —                122,913
Distribution of Fortune Creek Partnership      (14,285)         —
Proceeds from exercise of stock options        11               1,299
Excess tax benefits on stock compensation      1,089            —
Purchase of treasury stock                     (3,144)          (4,864)
Net cash provided (used) by financing          138,178          119,556
Effect of exchange rate changes in cash        (1,354)          (921)
Net change in cash                             (8,195)          (41,791)
Cash and cash equivalents at beginning of      13,146           54,937
Cash and cash equivalents at end of period     $4,951          $13,146

Unaudited Selected Operating Results
                                              Quarter ended   Year ended
                                               December 31,    December 31,
                                              2012    2011    2012    2011
Average Daily Production:                                           
Natural Gas (MMcfd)                            274.9  336.6  288.5  335.1
NGL (Bbld)                                     10,525 11,892 11,121 12,147
Oil (Bbld)                                     725    759    784    748
Total (MMcfed)                                 342.4  412.5  360.0  412.4
Average Realized Prices, including hedging:                         
Natural Gas (per Mcf)                          $4.50 $4.73 $4.26 $4.95
NGL (per Bbl)                                  38.50  38.50  39.69  38.63
Oil (per Bbl)                                  78.55  85.55  85.98  88.15
Total (Mcfe)                                   4.96   5.12   4.83   5.32
Average Realized Prices, excluding hedging:                         
Natural Gas (per Mcf)                          $3.20 $3.40 $2.59 $3.88
NGL (per Bbl)                                  29.85   50.82   33.91   49.00
Oil (per Bbl)                                  77.96   85.93   86.08   88.27
Total (Mcfe)                                   3.65    4.40    3.31    4.75
Expense per Mcfe:                                                   
Lease operating expense:                                            
Cash expense                                   $0.72 $0.77 $0.71 $0.67
Equity compensation                            0.01   0.01   0.01   0.01
Total lease operating expense:                 $0.73 $0.78 $0.72 $0.68
Gathering, processing and transportation       $1.25 $1.27 $1.26 $1.27
Production and ad valorem taxes                $0.14 $0.14 $0.19 $0.19
Depletion, depreciation and accretion          $1.13 $1.60 $1.41 $1.50
General and administrative expense:                                 
Cash expense                                   $0.21 $0.32 $0.31 $0.31
Audit and accounting fees                      0.03   0.01   0.05   0.01
Strategic transaction costs                    0.26   0.01   0.06   0.03
Litigation settlement                          —      —      —      0.06
Equity compensation                            0.16   0.13   0.16   0.12
Total general and administrative expense       $0.66 $0.47 $0.58 $0.53
Interest Expense:                                                   
Cash expense on debt outstanding               $1.39 $1.12 $1.31 $1.15
Fees paid on letters of credit outstanding     0.01   0.01   —      0.01
Cash premium on early debt extinguishment      —      —      —      0.02
Non-cash interest                              0.05   0.09   0.07   0.11
Capitalized interest                           (0.13) (0.06) (0.14) (0.05)
Total interest expense                         $1.32 $1.16 $1.24 $1.24

Production, on a million cubic feet of natural gas equivalent (MMcfe)
per day basis, by operating area
                     Quarter ended           Year ended
                      December 31,            December 31,
                     2012        2011        2012        2011
Barnett Shale         247.1      338.0      274.8      336.6
Other U.S.            3.3        3.2        3.5        3.3
Total U.S.            250.4      341.2      278.3      339.9
Horseshoe Canyon      53.7       58.5       54.6       58.3
Horn River            38.3       12.8       27.1       14.2
Total Canada          92.0       71.3       81.7       72.5
Total Company         342.4      412.5      360.0      412.4

In thousands, except per share data - Unaudited
                               Quarter Ended          YearEnded
                                December 31,           December 31,
                               2012         2011      2012         2011
Net income (loss)               (1,100,922) 23,531   (2,485,149) 90,046
Unrealized (gain)/loss on       —            3,000     —            (45,852)
commodity derivatives
Restructure of hedge contracts  200         —        14,755      —
Loss (gain) from hedge          (2,526)     —        (4,594)     —
Impairment of assets            1,162,961   57,996   2,764,464   107,059
Crestwood earn-out              —           —        (41,097)    —
Inception loss on 10-year       —           —        21,670      —
Equity portion of interest rate —           38       —           (739)
derivatives from BBEP
Equity portion of commodity     —           (23,609) —           20,063
derivatives from BBEP
Equity portion -loss from sale  —           —        —           —
of properties from BBEP
Gain on BBEP units sold and     —           (84,646) —           (217,894)
Inventory adjustment            —           1,708    —           1,708
Debt retirement - related       —           —        —           2,943
Interest expense related to     —           1,030    2,789       2,047
debt restructure
Strategic transaction costs     7,505       446      8,503       4,978
Eagle legal settlement          —           —        —           8,500
Audit and accounting fees       —           —        3,479       —
Valuation allowance on deferred 325,847     —        609,477     —
tax asset
Reduction of uncertain tax      —           —        (9,219)     —
position liability
Acceleration of stock           900         —        4,137       —
compensation expense
Other                           —           —        1,130       —
Total adjustments before income 1,494,887   (44,037) 3,375,494   (117,187)
tax expense
Income tax expense for above    (396,362)   20,135   (936,724)   47,566
Total adjustments after tax     1,098,525   (23,902) 2,438,770   (69,621)
Adjusted net income             (2,397)     (371)    (46,379)    20,425
Adjusted net income per common  $(0.01)    $—      $(0.27)    $0.12
share - diluted
Diluted weighted average common 170,260     169,409  170,106     169,375
shares outstanding

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