Quicksilver Resources Reports Preliminary 2013 Fourth-Quarter and Full-Year Results

Quicksilver Resources Reports Preliminary 2013 Fourth-Quarter and Full-Year

FORT WORTH, Texas, March 14, 2014 (GLOBE NEWSWIRE) -- Quicksilver Resources
Inc. (NYSE:KWK) today announced preliminary 2013 fourth-quarter and full-year

2013 and Q1 2014 Highlights:

-- Raised proceeds and announced sales for total of $596 million

  *Sold 25% interest in Barnett Asset to TGBR, a subsidiary of Tokyo Gas Co.,
    Ltd., for net proceeds of $464 million
  *Sold Montana Asset to Synergy Offshore LLC for net proceeds of $42 million
  *Announced sale of Niobrara Asset along with SWEPI LP to Southwestern
    Energy Co., which is expected to generate cash proceeds of $90 million

-- Refinanced $1.1 billion in debt, extended maturities and reduced weighted
average interest rates

-- Increased pro forma proved reserves by 20%

-- Secured partners on the West Texas Asset and narrowed focus on core
Wolfcamp to Pecos County

-- Added to the 2014 derivative position; approximately 75% of expected 2014
equivalent production covered with commodity swaps at a weighted average price
of $5.08/Mcfe

-- Resumed Barnett drilling activity in thethird quarter with the goal to
rebuild volumes

-- Secured amendment to lower gathering rate and defer capital spending
requirements in the Horn River Basin

-- Secured site for potential LNG exports from Canada

"Over the last year, Quicksilver has reduced debt, enhanced liquidity, and
advanced projects," said Glenn Darden, Quicksilver's Chief Executive Officer.
"We have more work to do, but with the improvements made, and what we believe
will be more to come, 2014 is shaping up to be a significant year for this

Financial Results

Fourth-quarter 2013

Reported net loss for the fourth quarter 2013 was $32 million, or $0.18 per
diluted share, compared to a reported net loss of $548 million, or $3.22 per
diluted share, in the 2012 quarter.

Adjusted net loss for the fourth quarter 2013, a non-GAAP financial measure,
was $5 million, or $0.03 per diluted share, compared to adjusted net income of
$9 million, or $0.05 per diluted share, in the 2012 quarter. Fourth-quarter
2013 adjusted net loss excludes a $13 million mark-to-market gain on commodity
derivatives and $4 million charge related to strategic transaction costs,
among other miscellaneous items. Details of adjusted net income are included
in the tables accompanying this earnings release.

Full-year 2013

Reported net income for full-year 2013 was $162 million, or $0.92 per diluted
share, compared to a reported net loss of $2.4 billion, or $13.83 per diluted
share, for full-year 2012. The reported net loss in 2012 was mainly impacted
by non-cash impairments of $2.6 billion.

Full-year 2013 adjusted net loss, a non-GAAP financial measure, was $32
million, or $0.18 per diluted share, compared to an adjusted net loss of $8
million, or $0.05 per diluted share, for full-year 2012.


Fourth-quarter 2013 production was 24.5 Bcfe, or an average of 266 million
cubic feet of natural gas equivalent per day (MMcfed) compared to 31.5 Bcfe,
or an average of 342 MMcfed in the 2012 quarter. Full-year 2013 production was
108 Bcfe, or an average of 296 MMcfed.

Pro forma for asset sales, 2013 production was approximately 101 Bcfe, or an
average of 276 MMcfed, compared to pro forma production of approximately 105
Bcfe, or an average of 288 Bcfe in 2012. The decline in pro forma production
is mainly attributable to the impact of curtailed capital spending across the
company's asset base.

Inclement weather in North Texas and Canada negatively impacted fourth quarter
2013 production by approximately 2.4 MMcfed.


Production revenue and realized cash derivative gain/loss for the fourth
quarter of 2013 was $112 million compared to $166 million in the 2012 quarter,
which excludes approximately $3 million and $6 million, respectively, of cash
proceeds from certain derivatives that will not be recognized until future
periods to match their original settlement dates.

The average realized price for the fourth quarter of 2013 and full-year 2013
was $4.59 and $4.49, respectively, which excludes approximately $0.12 and
$0.20 per Mcfe, respectively, of cash proceeds from derivatives described

Production revenue and realized cash derivative gain/loss in the fourth
quarter of 2013 and full-year 2013 was 33% and 28% lower than the 2012 quarter
and full-year 2012, respectively, due mainly to lower production volumes as
described above and the expiration at the end of 2012 of approximately 100
MMcfe per day of commodity swaps at an average floor price of $6.91/Mcfe.


Consolidated lease operating expense for the fourth quarter of 2013 was $19
million, or $0.76 per Mcfe, compared to $23 million, or $0.73 per Mcfe in the
2012 quarter. The absolute decline is mainly attributable to asset sales, cost
containment efforts and lower production volumes. The increase in the rate per
Mcfe is the effect of the fixed portion of lease operating expenses amid
declining volume.

Consolidated gathering, processing and transportation ("GPT") expense for the
fourth quarter of 2013 was $37 million, or $1.49 per Mcfe compared to $39
million, or $1.25 per Mcfe in the 2012 quarter. The absolute decline is
attributable to asset sales and lower production volumes, offset by higher
unused committed capacity charges in the Horn River Basin.

Production and ad valorem taxes for the fourth quarter of 2013 was $2 million
compared to $5 million in the 2012 quarter. The decline is attributable to
asset sales and reductions to expected tax expenses recognized in the fourth
quarter of 2013 which were related to reduced appraisal values for properties
within the Barnett Asset.

General & Administrative expense for the fourth quarter of 2013 was $12
million, or $0.48 per Mcfe compared to $21 million, or $0.66 per Mcfe in the
2012 quarter. Excluding the impact of strategic transaction costs in each
period, G&A would have been $8 million, or $0.31 per Mcfe, in the fourth
quarter of 2013 compared to $13 million, or $0.42 per Mcfe, in the 2012
quarter. The reduction is related to the company's continued aggressive focus
on cost containment and lower executive incentive compensation in 2013.

Cash Flow, Debt and Liquidity

Operating cash flow for the fourth quarter was $29 million. Investing cash
flow was a net outflow of $18 million before purchases and maturities of
marketable securities.

As of December 31, 2013, the company had approximately $252 million utilized
under its Combined Credit Agreements, which includes $41 million of
outstanding letters of credit. Long-term debt was $2 billion consisting of the
Combined Credit Agreements and long-term notes, all with an average weighted
maturity of approximately 5 years.

Total liquidity at December 31, 2013 is approximately $353 million in the form
of $255 million of cash and marketable securities, and $98 million of
availability under the Combined Credit Agreements.

2013 Capital Spending

The company incurred approximately $26 million of capital expenditures in the
fourth quarter of 2013, of which $18 million was for drilling and completion
activities, $3 million for leasehold and midstream, and $5 million for
capitalized costs ($4 million for capitalized G&A and $1 million for
capitalized interest).

Capital incurred for the full-year 2013 was $99 million, which is $21 million
below the capital budget due to lower than anticipated spending in the West
Texas Asset and lower capitalized overhead.

2014 Capital Budget and Outlook

The company intends to invest a total of $136 million in 2014, which includes
$98 million for drilling and completion activities, primarily in the Fort
Worth Basin and the Horseshoe Canyon, $15 million for leasehold and seismic,
and approximately $23 million for overhead and interest expense that is
expected to be capitalized in the ordinary course of business.

The capital budget does not factor in proceeds from potential strategic
partnerships and assumes the completion of the Niobrara Asset sale. It also
does not include any acquisition spending which may occur during the year.

Full-year production volume is expected to be 245 - 255 MMcfe per day.
First-quarter 2014 average daily production volume is expected to be 240 - 245
MMcfe per day. Average daily production volumes are expected to consist of 85%
natural gas and 15% natural gas liquids and crude oil.

For the first quarter of 2014, expected costs, on an absolute and Mcfe basis,
are as follows:

                                         Dollar Amount    Per Mcfe
-- Lease operating expense                $18.5 - $19.2MM  $0.84 - $0.88
-- Gathering, processing & transportation $31.3 - $31.8MM  $1.43 - $1.45
-- Production and ad-valorem taxes        $3.5 - $4.0MM    $0.16 - $0.18
-- General & administrative               $12.0 - $13.0MM  $0.55 - $0.59
-- Depletion, depreciation & accretion    $13.0 - $13.7MM  $0.59 - $0.63


The company's derivative portfolio is as follows: Natural gas swaps of 170
MMcfd for 2014 at a weighted average price of $5.08 per Mcf, 150 MMcfd for
2015 at $5.23 per Mcf, and 40 MMcfd for 2016-2021 at $4.48 per Mcf, and NGL
swaps of 4,000 BBld at a weighted average price of $30.52 for January 2014 -
September 2014.

The company estimates that approximately 75% of its expected 2014 equivalent
production is covered by fixed price swaps. Expected sales at the AECO hub in
2014 are covered approximately 70% at a weighted average discount of $0.46 per
Mcf to NYMEX.


The Securities and Exchange Commission (SEC) requires proved reserve volumes
to be calculated using an average of the 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 2013
reserves reporting purposes were $3.67 per million British thermal units
(MMbtu) at NYMEX and $97.18 per barrel at WTI.

Quicksilver's preliminary year-end 2013 SEC proved reserves based on SEC
pricing total approximately 1,330 billion cubic feet of natural gas
equivalents (Bcfe), as outlined below.

In Bcfe                              United States Canada Consolidated
Proved Reserves @ 12/31/12           1,200         267    1,467
Barnett 25% sale                     (337)         —    (337)
Montana sale                         (15)          —    (15)
Other                                (5)           —    (5)
Pro forma Proved Reserves @ 12/31/12 843           267    1,110
Production                           (70)          (39)   (109)
Revisions                            240           28     268
Extensions                           51            10     61
Proved Reserves @ 12/31/13           1,064         266    1,330
Proved Developed                     910           260    1,170
Proved Undeveloped                   154           6      160

Year-end 2013 proved reserves are 20% higher compared to pro forma 2012
reserves as a result of 221 Bcfe of price revisions, 47 Bcfe of technical
revisions, and 61 Bcfe of additions resulting from the Barnett and Horseshoe
Canyon capital programs. Reserves by product are 82% natural gas and 18% NGLs
and oil.

Operational Update

United States - Barnett Shale

Production from the Barnett Shale in the fourth quarter of 2013 was an average
of 166.7 MMcfe per day. The company invested approximately $6 million in the
fourth quarter to drill 11 gross (4 net) wells in the Barnett including 6
gross (3 net) wells in its Alliance leasehold. These wells are expected to be
completed in the first quarter of 2014.

For full-year 2014, the company expects to drill up to 30 gross (16 net) wells
and complete up to 47 gross (26 net) wells.

Along with partners Tokyo Gas and Eni, Quicksilver leases approximately
135,000 gross acres in the Fort Worth Basin which is prospective of the
Barnett Shale.

United States - West Texas

Quicksilver, with its partners, are focused on evaluating and developing
approximately 52,500 gross acres in Pecos County, Texas which is believed to
be prospective of the Wolfcamp and Bone Springs formations. The joint venture
with Eni calls for Eni to spend up to $52 million to fund 100% of the drilling
and completion of up to three wells, the first of which is expected to be spud
by June 2014.

United States - Niobrara Asset

The company announced the sale of its interest in the Niobrara Asset along
with SWEPI LP's interest to Southwestern Energy Co. for gross proceeds of $180
million, expected to be split equally between Quicksilver and SWEPI. The
transaction is expected to close May 1, 2014.

Fourth-quarter 2013 average net production from the Niobrara Asset was
approximately 32 Bbld. Proved reserves at year-end 2013 was approximately 70

Canada - Horn River Basin

Production from the Horn River Basin in the fourth quarter of 2013 was an
average of 50 MMcfe per day.

In March 2014, the company executed an agreement with KKR, its partner in
Fortune Creek, to reduce the rate assessed on Horn River gathered volumes and
to amend the ending date of the remaining $120 million capital spending
requirement. As part the amendment, Quicksilver pays C$28 million to Fortune
Creek to apply against the gathering agreement requirement, thus lowering the
Fortune Creek gathering rate by $0.13 per Mcf until at least 2016. The
amendment also provides that the remaining capital spending requirement be
deferred to the later of June 30, 2016 or 12 months following consummation of
a transaction involving a material portion of the Horn River Asset. The
agreement also broadens the eligibility of allowable spending to meet the
capital spending requirement to include acquisitions of properties that
utilize partnership assets.Additionally, as a result of the amendment, KKR no
longer is required to fund the capital required for construction of a proposed
gas treatment facility, but at their option can provide funding for any
facility to be constructed by the Partnership, including the proposed gas
treatment facility. The amendment provides the company with immediate cash
flow relief by the reduction to the gathering fee paid to Fortune Creek, and
provides additional time and flexibility to complete a transaction involving
the company's Horn River Asset.

The company has acquired a site for potential LNG exports off the British
Columbia coast and is working toward completing a transaction with one or more
potential partners for its integrated Horn River project. The company
anticipates minimal capital spending in the Horn River until it completes this

Quicksilver leases approximately 130,000 net acres in the Horn River Basin in
British Columbia which is believed to hold 14Tcf of natural gas resource

Canada - Horseshoe Canyon

Production from the Horseshoe Canyon in the fourth quarter of 2013 was an
average of 49 MMcfe per day.

The company expects to invest approximately $20 million in 2014 to drill and
complete up to 100 gross (50 net) wells.

Quicksilver leases approximately 353,000 net acres in its Horseshoe Canyon
Asset in Alberta.

Conference Call Information

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

In order to access the conference call through a phone line, participants must
first register at http://emsp.intellor.com?p=414755&do=register&t=8. Upon
successful registration, a unique telephone user ID will be created, and
dial-in information will be provided via an email message. This user ID will
be required to access the conference. The company highly recommends the
registration process be completed at least 60 minutes prior to the scheduled
start of the call.

To listen to the conference through a webcast, visit the Events &
Presentations page on the company's website at http://investors.qrinc.com.

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
accessed by dialing 1-888-876-2113, using the conference PIN number 840431.

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. Adjusted net income is presented for all periods presented in the
press release to exclude the effect on net income of certain revenue, expense,
gain and loss associated with items not typically included in published
estimates, in order to enhance the user's overall understanding of current
financial performance. As part of the press release, the company has provided
a reconciliation of adjusted net income to net income, which is the most
comparable financial measure determined in accordance with accounting
principles generally accepted in the United States of America ("GAAP").
Management believes this non-GAAP measure provides useful information to both
management and investors by excluding certain revenues and expenses that may
not be indicative of our core operating results, and will enhance the ability
of management and investors to compare our results of operations from period
to period.

About Quicksilver Resources

Fort Worth, Texas-based Quicksilver Resources is a publicly traded independent
oil and gas company engaged in the exploration, development and acquisition of
oil and gas, primarily from unconventional reservoirs including shales and
coal beds in North America. Quicksilver's Canadian subsidiary, Quicksilver
Resources Canada Inc., is headquartered in Calgary, Alberta.Quicksilver's
common stock is traded on the New York Stock Exchange under the symbol "KWK."
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," "contemplate," "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; failure to satisfy our short or long-term
liquidity needs, including the ability to access necessary capital resources;
fluctuations in natural gas, NGL and oil prices; failure or delays in
achieving expected production from exploration and development projects; our
ability to achieve anticipated cost savings and other spending reductions and
operational efficiencies; failure to comply with covenants under our Combined
Credit Agreements and other indebtedness and the resulting acceleration of
debt thereunder and inability to make necessary repayments or to make
borrowings; uncertainties inherent in estimates of natural gas, NGL and oil
reserves and predicting natural gas, NGL and oil production and 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, particularly in closing the proposed
Southwestern Transaction or in contracting for a transaction involving our
Horn River Asset; failure to make the necessary expenditures under or related
to our contractual commitments, including our spending requirement pursuant to
Fortune Creek; the effects of existing or future litigation; 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.

KWK 14-03

In thousands, except for per share data - Unaudited
                        For the Three Months Ended For the Year Ended
                          December 31,               December 31,
                        2013         2012          2013       2012
Production                $105,211   $157,895    $463,491 $630,947
Sales of purchased        14,540      19,564       64,913    62,405
natural gas
Net derivative gains      (6,273)     45,345       29,928    11,444
Other                     768         1,162        3,230     4,242
Total revenue             114,246     223,966      561,562   709,038
Operating expense                                            
Lease operating           18,565      22,927       82,265    95,333
Gathering, processing and 36,504      39,277       148,569   166,316
Production and ad valorem 1,604       4,562        17,066    25,395
Costs of purchased        14,529      19,513       64,840    62,041
natural gas
Depletion, depreciation   14,700      27,156       62,612    163,624
and accretion
Impairment                1,863       557,141      1,863     2,625,928
General and               11,797      20,861       55,306    75,697
Other operating           (710)       742          3,725     1,562
Total expense             98,852      692,179      436,246   3,215,896
Gain on Tokyo Gas         (1,819)     —            339,328   —
Crestwood earn-out        —           —            —         41,097
Operating income (loss)   13,575      (468,213)    464,644   (2,465,761)
Other income (expense)    (2,796)     1,345        (17,384)  1,108
Fortune Creek accretion   (4,755)     (4,923)      (19,245)  (19,472)
Interest expense          (41,312)    (41,703)     (251,847) (164,051)
Income (loss) before      (35,288)    (513,494)    176,168   (2,648,176)
income taxes
Income tax (expense)      3,513       (35,005)     (14,550)  295,570
Net income (loss)         $(31,775)  $(548,499)  $161,618 $(2,352,606)
Earnings (loss) per       $(0.18)    $(3.22)     $0.92    $(13.83)
common share - basic
Earnings (loss) per       $(0.18)    $(3.22)     $0.92    $(13.83)
common share - diluted

In thousands, except share data - Unaudited
                                                    December 31, December 31,
                                                     2013         2012
Current assets                                                   
Cash and cash equivalents                            $89,103    $4,951
Marketable securities                                166,343     —
Total cash, cash equivalents and marketable          255,446     4,951
Accounts receivable - net of allowance for doubtful  58,645      64,149
Derivative assets at fair value                      57,523      113,367
Other current assets                                 22,346      25,046
Total current assets                                 393,960     207,513
Property, plant and equipment - net                              
Oil and gas properties, full cost method (including
unevaluated costs of $221,605 and $307,267,          640,443     780,960
Other property and equipment                         220,362     248,098
Property, plant and equipment - net                  860,805     1,029,058
Derivative assets at fair value                      73,357      105,270
Other assets                                         41,604      39,947
                                                    $1,369,726 $1,381,788
LIABILITIES AND EQUITY                                           
Current liabilities                                              
Accounts payable                                     $28,822    $37,131
Accrued liabilities                                  102,850     130,660
Derivative liabilities at fair value                 3,125       —
Total current liabilities                            134,797     167,791
Long-term debt                                       1,988,946   2,063,206
Partnership liability                                126,132     130,912
Asset retirement obligations                         106,256     115,949
Derivative liabilities at fair value                 323         17,485
Other liabilities                                    19,242      19,242
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 183,994,879 and 179,015,118 shares   1,840       1,790
issued, respectively
Additional paid in capital                           770,092     751,394
Treasury stock of 6,698,640 and 5,921,102 shares,    (51,422)    (49,495)
Accumulated other comprehensive income               109,881     161,493
Retained deficit                                     (1,836,361) (1,997,979)
Total stockholders' equity                           (1,005,970) (1,132,797)
                                                    $1,369,726 $1,381,788

In thousands - Unaudited
                                                 For the Year Ended
                                                   December 31,
                                                 2013         2012
Operating activities:                                          
Net income (loss)                                  $161,618   $ (2,352,606)
Adjustments to reconcile net income (loss) to net              
cash provided by (used in) operating activities:
Depletion, depreciation and accretion              62,612      163,624
Impairment expense                                 1,863       2,625,928
Write-off of MLP related fees and expenses         —           7,505
Gain on Tokyo Gas Transaction                      (339,328)   —
Crestwood earn-out                                 —           (41,097)
Deferred income tax expense (benefit)              21,581      (289,981)
Non-cash (gain) loss from hedging and derivative   3,904       57,826
Stock-based compensation                           17,979      22,246
Non-cash interest expense                          26,920      9,854
Fortune Creek accretion                            19,245      19,472
Other                                              6,783       1,037
Changes in assets and liabilities                              
Accounts receivable                                (3,994)     30,950
Prepaid expenses and other assets                  322         (4,435)
Accounts payable                                   (7,133)     (8,895)
Income taxes payable                               7,828       1,183
Accrued and other liabilities                      (31,900)    (14,884)
Net cash provided by (used in) operating           (51,700)    227,727
Investing activities:                                          
Capital expenditures                               (101,288)   (485,479)
Proceeds from Tokyo Gas Transaction                463,999     —
Proceeds from Synergy Transaction                  42,297      —
Proceeds from Crestwood earn-out                   —           41,097
Proceeds from sale of properties and equipment     7,171       72,725
Purchases of marketable securities                 (213,738)   —
Maturities and sales of marketable securities      47,603      —
Net cash provided by (used in) investing           246,044     (371,657)
Financing activities:                                          
Issuance of debt                                   1,237,352   467,959
Repayments of debt                                 (1,308,382) (310,430)
Debt issuance costs paid                           (26,296)    (3,022)
Distribution of Fortune Creek Partnership funds    (14,965)    (14,285)
Proceeds from exercise of stock options            —           11
Purchase of treasury stock                         (1,927)     (3,144)
Net cash provided by (used in) financing           (114,218)   137,089
Effect of exchange rate changes in cash            4,026       (1,354)
Net change in cash                                 84,152      (8,195)
Cash and cash equivalents at beginning of period   4,951       13,146
Cash and cash equivalents at end of period         $89,103    $4,951

                                          Quarter ended     Year ended
                                           December 31,      December 31,
                                          2013     2012     2013     2012
Average Daily Production:                                          
Natural Gas (MMcfd)                        220.6   274.9   246.5   288.5
NGL (Bbld)                                 7,363   10,525  7,747   11,121
Oil (Bbld)                                 233     725     475     784
Total (MMcfed)                             266.1   342.4   295.8   360.0
Average Realized Prices, including                                 
Natural Gas (per Mcf)                      $4.46  $4.87  $4.33  $4.62
NGL (per Bbl)                              $29.17 $ 38.50 $28.12 $ 39.69
Oil (per Bbl)                              $92.31 $ 78.55 $89.53 $ 85.98
Total (Mcfe)                               $4.59  $5.26  $4.49  $5.11
Average Realized Prices, excluding                                 
Natural Gas (per Mcf)                      $3.30  $3.20  $3.32  $2.59
NGL (per Bbl)                              $30.94 $ 29.84 $28.60 $ 33.92
Oil (per Bbl)                              $92.31 $ 78.55 $89.53 $ 86.00
Total (Mcfe)                               $3.67  $3.65  $3.66  $3.31
Expense per Mcfe:                                                  
Lease operating expense:                                           
Expense                                    $0.74  $0.72  $0.75  $0.71
Equity compensation                        0.02    0.01    0.01    0.01
Total lease operating expense:             $0.76  $0.73  $0.76  $0.76
Gathering, processing and transportation   $1.49  $1.25  $1.38  $1.26
Production and ad valorem taxes            $0.07  $0.14  $0.16  $0.19
Depletion, depreciation and accretion      $0.60  $0.86  $0.58  $1.24
General and administrative expense:                                
Expense                                    $0.14  $0.24  $0.28  $0.31
Audit and accounting fees                  0.02    0.03    0.02    0.05
Strategic transaction costs                0.17    0.23    0.06    0.06
Equity compensation                        0.15    0.16    0.15    0.16
Total general and administrative expense   $0.48  $0.66  $0.51  $0.58
Cash expense on debt outstanding           1.63    1.39    1.53    1.31
Fees paid on letters of credit outstanding —       0.01    —       —
Net premium paid on senior notes purchased —       —       0.62    —
Non-cash interest                          0.13    0.05    0.25    0.07
Capitalized interest                       (0.07)  (0.13)  (0.07)  (0.14)
Total interest expense                     1.69    1.32    2.33    1.24

per day basis, by operating area
                 Quarter ended December 31,  Year ended December 31,
                 2013           2012         2013        2012
Barnett Shale     166.7         247.1       187.3      274.8
Other U.S.        0.2           3.3         1.9        3.5
Total U.S.        166.9         250.4       189.2      278.3
Horseshoe Canyon  49.3          53.7        49.7       54.6
Horn River        49.9          38.3        56.9       27.1
Total Canada      99.2          92.0        106.6      81.7
Total Company     266.1         342.4       295.8      360.0

In thousands, except per share data - Unaudited
                           Quarter Ended            Year ended
                            December 31,             December 31,
                           2013        2012         2013       2012
Net income (loss)           $(31,775) $ (548,499) $161,618 $ (2,352,606)
Gain on sale of assets      1,818      —           (339,328) —
Unrealized (gain)/loss on   13,372     (38,326)    (8,700)   31,354
commodity derivatives
Termination of NGTL PEA     —          —           12,817    —
Debt issuance and           —          —           85,943    2,789
retirement related expenses
Foreign exchange loss on    —          —           2,456     —
debt paydown
Impairment of assets        2,266      557,141     6,722     2,625,928
Acceleration of stock       —          900         2,228     4,137
compensation expense
Audit and accounting fees   —          —           —         3,479
Strategic transaction costs 4,192      7,505       6,885     8,503
Crestwood earn-out          —          —           —         (41,097)
Other                       5,493      —           6,319     1,130
Total adjustments before    27,141     527,220     (224,658) 2,636,223
income tax expense
Income tax expense for      (662)      30,201      31,522    (291,387)
above adjustments
Total adjustments after tax 26,479     557,421     (193,136) 2,344,836
Adjusted net income (loss)  (5,296)    8,922       (31,518)  (7,770)
Adjusted net income (loss)  $(0.03)   $0.05      $(0.18)  $(0.05)
per common share - diluted
Diluted weighted average    171,860    170,260     171,659   170,106
common shares outstanding

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

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