Quicksilver Resources Reports Third-Quarter 2013 Results

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FORT WORTH, Texas, Nov. 5, 2013 (GLOBE NEWSWIRE) -- Quicksilver Resources Inc. (NYSE:KWK) today announced preliminary 2013 third-quarter results.


  • Sold Montana Asset to Synergy Offshore LLC for $46 million
  • Executed two transactions in West Texas, the larger of which is a joint venture with Eni covering 52,500 gross acres in Pecos County (Delaware Basin)
  • Increased commodity derivative position to nearly 90% of expected remaining production in 2013 at $5.11/Mcfe and 70% of production in 2014 at $5.08/Mcfe based on flat third-quarter 2013 production
  • Reduced overall company LOE by approximately 10% and G&A costs by 20% year-to-date compared to the same period in 2012

"Quicksilver continues to progress on our deleveraging plan. We have sold additional non-core assets and executed deals in West Texas that give us significant exposure to new oil production without near-term capital outlay," said Glenn Darden, Quicksilver's Chief Executive Officer. "We are working on what we believe will be a very attractive solution for our Horn River properties, which are the assets in our portfolio with the most potential."

Financial Results

Reported net income for the third quarter of 2013 was $11 million, or $0.06 per diluted share, compared to a reported net loss of $791 million (restated), or $4.65 per diluted share in the 2012 quarter. Third quarter 2012 reported results were impacted by a $551 million non-cash impairment of properties.

Adjusted net loss for the third quarter of 2013, a non-GAAP financial measure, was $8 million, or $0.05 per diluted share, compared to adjusted net income of $5 million (restated), or $0.03 per diluted share, in the 2012 quarter.

Third-quarter 2013 adjusted net income excludes the following significant, non-operational items:

  • $25 million non-cash unrealized gain from commodity derivatives
  • $8 million adjustment to the gain on sale of 25% of the Barnett Asset
  • $2 million for other non-cash impairments

Further details of adjusted net income are included in the tables accompanying this earnings release.


Third-quarter 2013 production was 25.2 Bcfe, or an average of 274 million cubic feet of natural gas equivalent per day (MMcfed) compared to 33.3 Bcfe, or an average of 362 MMcfed in the prior-year quarter. Production volumes were impacted by the 25% sale of the Barnett Shale on April 30, 2013.

Production from the Barnett Shale was 15.4 Bcfe, or 167 MMcfed, which is lower compared to the 2012 quarter due to the aforementioned sale and continued minimal capital activity. However, early in the third quarter, the company deployed a rig in the Barnett which is expected to be utilized throughout 2014 in order to build volumes in the basin.

Production from Canada was 9.7 Bcfe, or 105 MMcfed, which is 8% higher compared to the 2012 quarter as volumes from the Horn River Basin were increased to reflect the step up in treating commitments attributable to a third-party facility commissioned in April 2013. Production from the Horseshoe Canyon declined in the third quarter of 2013 compared to the 2012 quarter due to natural decline of existing wells and minimal capital activity, partially offsetting gains in the Horn River.

On August 30, 2013, the company sold its interest in the Montana Asset, resulting in the loss of one month of third-quarter production, or approximately 11 MBbl.


Production revenue and realized cash derivative gain/loss for the third quarter of 2013 was $113 million compared to $169 million in the 2012 quarter, which excludes approximately $3 million and $7 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 third quarter of 2013 was $4.47 per Mcfe compared to $5.06 per Mcfe in the prior-year quarter, which excludes approximately $0.13 and $0.21 per Mcfe, respectively, of cash proceeds from derivatives described above.

Production revenue and realized cash derivative gain/loss in the third quarter of 2013 was 34% lower than the 2012 quarter due to lower production volumes as described above and lower contribution from commodity derivatives related to the expiration of a portion of the commodity swap derivatives and lower weighted average strike prices on the remaining swap portfolio. However, higher natural gas prices in the third quarter of 2013 compared to the 2012 quarter partially offset these factors.


Consolidated lease operating expense for the third quarter of 2013 was $19 million, or $0.74 per Mcfe, compared to $22 million, or $0.66 per Mcfe in the 2012 quarter. The absolute decline is mainly attributable to asset sales and lower production volumes.

Lease operating expense in the Barnett Shale declined approximately $1 million compared to the 2012 quarter due to the 25% sale of the Barnett and lower volumes related to natural decline of existing wells. Excluding the impact of a non-cash impairment in the third quarter of 2013, recurring lease operating expense in the Barnett Shale was approximately $9 million, or $0.60 per Mcfe.

Lease operating expense in the Horn River Basin was flat compared to the prior-year quarter, but decreased 25% on a unit basis due to the relatively fixed nature of operating expenses spread across higher production volumes.

The sale of the Montana Asset in August reduced third-quarter lease operating expense by $500,000, or an average of $0.02 per Mcfe.

Consolidated gathering, processing and transportation ("GPT") expense for the third quarter of 2013 was $36 million, or $1.41 per Mcfe compared to $41 million, or $1.24 per Mcfe in the 2012 quarter. The absolute decline is attributable to asset sales and lower U.S. production volumes, offset by higher committed capacity charges in the Horn River Basin.

GPT in the Barnett Shale was $23 million in the third quarter of 2013, which is approximately $10 million lower compared to the 2012 quarter due to the 25% sale of the Barnett and lower production volumes.

GPT in the Horn River Basin increased $5 million compared to the 2012 quarter due to higher delivered volumes related to increased treating commitments. GPT also increased $0.58 per Mcfe compared to the 2012 quarter due to higher unused firm capacity as a greater portion of the treating and transportation volume commitments were met in the 2012 quarter. Horn River GPT includes payments of $1.7 million and $1.4 million for the third quarter of 2013 and the 2012 quarter, respectively, related to volume commitments in excess of produced volumes in those periods. Volume commitments were 100 MMcfd in the third quarter of 2013 but were 30 MMcfd in the third quarter of 2012.

General & Administrative expense for the third quarter of 2013 was $10 million, or $0.41 per Mcfe compared to $17 million, or $0.53 per Mcfe in the 2012 quarter. The absolute reduction is due, in part, to reductions in employee incentive compensation during the third quarter of 2013, but the majority is related to the company's continued focus on cost containment efforts.

Capital Spending

The company incurred approximately $21 million of capital expenditures in the third quarter of 2013, of which $14 million was for drilling and completion activities, $3 million for leasehold and midstream, and $4 million for capitalized costs and corporate spending.

Capital incurred for the first nine months of 2013 was $73 million, which is within expectations set in the capital budget. Full-year 2013 capital incurred is expected to be $120 million.

Barnett Shale

The company drilled one well and completed three wells in the third quarter. The company deployed a rig in early September and expects to drill up to six Barnett wells in the fourth quarter, though these wells are not expected to be completed until the first quarter of 2014. This rig is expected to be utilized in the Barnett through 2014.

Sand Wash Basin

The company expects to participate with Shell in the drilling of three gross wells and two gross completions in the fourth quarter, which is a reduction of the drill plan by five gross wells and a reduction of the completions plan by six gross wells compared to previous guidance.

Together with Shell, Quicksilver is continuing to unitize acreage in the basin and evaluate the productive capabilities of the combined acreage block.

Cash Flow

Operating cash flow for the third quarter was approximately $10 million, which excludes a one-time $13 million payment to NOVA Gas Transmission Ltd. for costs they incurred related to the deferred Komie North pipeline project. NOVA subsequently released a $14 million letter of credit posted to the project.

Investing cash flow was a net inflow of $11 million comprised of $43 million of asset sale proceeds, an outflow of $21 million for capital expenditures, and an outflow of $11 million related to an investment in marketable securities.

Total cash and marketable securities at September 30, 2013 was $186 million.


As of September 30, 2013, the company had approximately $192 million utilized under its Combined Credit Agreements, including $42 million of outstanding letters of credit.

Total liquidity at September 30, 2013 is approximately $344 million in the form of $56 million of cash and cash equivalents, $130 million of marketable securities maturing within 12 months and $158 million of credit facility availability under the $350 million borrowing base.

Commodity Derivatives

The company entered into the following swaps during the third quarter and early fourth quarter: NGLs of 6,000 Bbld for September through December of 2013 at a weighted average price of $30.88 per Bbl and 4,000 Bbld for January through September 2014 at a weighted average price of $30.52 per Bbl, and AECO basis swaps of 40 MMcfd for 2014 at a weighted average differential of $0.46 to NYMEX.

The company's natural gas swap portfolio is as follows: 200 MMcfd for the remainder of 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.

The company estimates that approximately 88% of remaining 2013 production is hedged at a weighted average price of $5.11 per Mcfe, and, based on the assumption of flat third-quarter 2013 production, approximately 70% of 2014 production is hedged at a weighted average price of $5.08 per Mcfe. Greater than 50% of 2014 sales at AECO is expected to be covered by the AECO basis swaps.

Strategic Transaction Update

Montana Asset

In August 2013, the company sold all of its interest in approximately 143,000 acres and approximately 2.6 MMBbl of reserves located in the Southern Alberta Basin in Cut Bank, Montana to Synergy Offshore LLC for a purchase price of $46 million. The effective date of the transaction was January 1, 2013. After customary closing adjustments, net proceeds of the sale were $42 million.

West Texas

Early in the fourth quarter, the company executed two separate agreements involving the West Texas Asset, the largest of which is a joint venture with Eni whereby the two companies will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by Quicksilver in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52 million in three phases to earn a 50% interest in Quicksilver's acreage. In the first phase, Eni will fund 100% of the drilling and completion costs of up to a three-well program. Upon funding of the first phase, Eni will earn 50% of Quicksilver's interest in a 7,500 gross acre tract in Pecos County. Eni will then have the option to fund 100% of the drilling and completion costs of another two wells, and will then have the option to fully fund a 3D seismic survey of the remaining, undeveloped acreage. Upon completion of the three phases, Quicksilver and Eni will participate equally in all future revenue, operating cost and capital expenditures.

Horn River Basin

The company is in negotiations with select partners for its integrated Horn River project.

Third-party reserve analysts estimate Quicksilver's 129,000 acres in the Horn River Basin in Northeast British Columbia holds up to 14 Tcf of natural gas reserve potential. The acreage is well served by existing pipelines and treating facilities, and, based on location and size of resource, is believed to be ideally suited as a long-term feedstock for LNG exports.

Fourth-Quarter 2013 Guidance

Fourth-quarter 2013 average daily production volume is expected to be 263 - 268 MMcfe per day, resulting in full-year average production volume of 295 - 297 MMcfe per day.

Average unit expenses, on a Mcfe basis, are expected as follows:

Lease operating expense $0.72 -- $0.76
Gathering, processing & transportation $1.34 -- $1.38
Production and ad-valorem taxes $0.18 -- $0.20
General & administrative $0.50 -- $0.54
Depletion, depreciation & accretion $0.56 -- $0.58

Natural gas basis differentials to NYMEX, on an Mmbtu basis, are expected as follows:

Barnett Shale $(0.06) -- $(0.08)
Horn River Basin $(0.60) -- $(0.64)
Horseshoe Canyon $(0.58) -- $(0.62)

Conference Call Information

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

Quicksilver invites interested parties to listen to the call via the Events & Presentations page on the company's website at http://investors.qrinc.com, or by calling 1-877-313-7932, using the conference ID number 88746532, 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 accessed by dialing 1-855-859-2056, using the conference ID number 88746532. The replay will also be archived for 30 days on the company's website.

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; 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; failure to comply with debt covenants under our Combined Credit Agreements and the resulting acceleration of debt thereunder and inability 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; 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 13-29

In thousands, except for per share data - Unaudited
For the Three Months Ended
September 30,
For the Nine Months Ended
September 30,
2013 2012 2013 2012
(Restated) (Restated)
Production $ 104,546 $ 156,288 $ 358,281 $ 473,053
Sales of purchased natural gas 15,130 21,313 50,373 42,841
Net derivative gains (losses) 32,733 (60,377) 36,202 (33,902)
Other 707 964 2,462 3,080
Total revenue 153,116 118,188 447,318 485,072
Operating expense
Lease operating 18,591 22,115 63,699 72,405
Gathering, processing and transportation 35,567 41,338 112,064 127,039
Production and ad valorem taxes 4,678 6,881 15,462 20,833
Costs of purchased natural gas 15,114 21,254 50,311 42,528
Depletion, depreciation and accretion 14,390 34,014 47,911 136,469
Impairment 551,132 2,068,787
General and administrative 10,471 17,335 43,509 54,835
Other operating 2,230 670 4,435 821
Total expense 101,041 694,739 337,391 2,523,717
Tokyo Gas Transaction gain 7,974 341,146
Crestwood earn-out 41,097
Operating income (loss) 60,049 (576,551) 451,073 (1,997,548)
Other income (expense) 667 (395) (14,588) (237)
Fortune Creek accretion (4,818) (4,978) (14,490) (14,549)
Interest expense (39,355) (42,102) (210,535) (122,348)
Income (loss) before income taxes 16,543 (624,026) 211,460 (2,134,682)
Income tax (expense) benefit (5,966) (166,494) (18,063) 330,575
Net income (loss) $ 10,577 $ (790,520) $ 193,397 $ (1,804,107)
Earnings (loss) per common share - basic $ 0.06 $ (4.65) $ 1.10 $ (10.61)
Earnings (loss) per common share - diluted $ 0.06 $ (4.65) $ 1.10 $ (10.61)
In thousands, except share data - Unaudited
September 30, 2013 December 31, 2012
Current assets
Cash and cash equivalents $ 56,478 $ 4,951
Marketable securities 129,812
Total cash, cash equivalents and marketable securities 186,290 4,951
Accounts receivable - net of allowance for doubtful accounts 55,242 64,149
Derivative assets at fair value 86,003 113,367
Other current assets 22,413 25,046
Total current assets 349,948 207,513
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $291,147 and $307,267, respectively) 629,684 780,960
Other property and equipment 233,248 248,098
Property, plant and equipment - net 862,932 1,029,058
Derivative assets at fair value 75,328 105,270
Other assets 43,405 39,947
$ 1,331,613 $ 1,381,788
Current liabilities
Accounts payable $ 12,745 $ 37,131
Accrued liabilities 102,913 130,660
Total current liabilities 115,658 167,791
Long-term debt 1,926,167 2,063,206
Partnership liability 132,732 130,912
Asset retirement obligations 99,160 115,949
Derivative liabilities at fair value 3,172 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 183,685,021 and 179,015,118 shares issued, respectively 1,837 1,790
Paid in capital in excess of par value 765,815 751,394
Treasury stock of 6,545,651 and 5,921,102 shares, respectively (50,967) (49,495)
Accumulated other comprehensive income 123,379 161,493
Retained deficit (1,804,582) (1,997,979)
Total stockholders' equity (964,518) (1,132,797)
$ 1,331,613 $ 1,381,788
In thousands - Unaudited
For the Nine Months Ended September 30,
2013 2012
Operating activities:
Net income (loss) $ 193,397 $ (1,804,107)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion 47,911 136,469
Impairment expense 2,068,787
Tokyo Gas Transaction gain (341,146)
Crestwood earn-out (41,097)
Deferred income tax expense (benefit) 17,833 (326,149)
Non-cash (gain) loss from hedging and derivative activities (12,223) 88,913
Stock-based compensation 13,699 16,983
Non-cash interest expense 23,643 8,060
Fortune Creek accretion 14,490 14,549
Other 3,622 495
Changes in assets and liabilities
Accounts receivable 7,398 27,259
Prepaid expenses and other assets 344 (4,503)
Accounts payable (17,973) (24,329)
Accrued and other liabilities (32,098) (19,954)
Net cash provided by (used in) operating activities (81,103) 141,376
Investing activities:
Purchases of property, plant and equipment (78,549) (437,172)
Proceeds from Tokyo Gas Transaction 463,418
Proceeds from Synergy Transaction 42,297
Proceeds from Crestwood earn-out 41,097
Proceeds from sale of properties and equipment 2,994 3,843
Purchases of marketable securities (142,823)
Maturities and sales of marketable securities 13,178
Net cash provided by (used in) investing activities 300,515 (392,232)
Financing activities:
Issuance of debt 1,173,306 367,646
Repayments of debt (1,308,382) (111,115)
Debt issuance costs paid (25,868) (3,048)
Distribution of Fortune Creek Partnership funds (8,079) (6,520)
Proceeds from exercise of stock options 11
Excess tax deductions on stock compensation 1,089
Purchase of treasury stock (1,472) (2,810)
Net cash provided by (used in) financing activities (170,495) 245,253
Effect of exchange rate changes in cash 2,610 (107)
Net increase (decrease) in cash 51,527 (5,710)
Cash at beginning of period 4,951 13,146
Cash at end of period $ 56,478 $ 7,436
Quarter ended Sept 30, Nine months ended Sept 30,
2013 2012 2013 2012
Average Daily Production:
Natural Gas (MMcfd) 230.1 291.3 255.3 293.2
NGL (Bbld) 6,895 11,073 7,878 11,321
Oil (Bbld) 400 761 556 804
Total (MMcfed) 273.9 362.4 305.8 366.0
Average Realized Prices, including hedging:
Natural Gas (per Mcf) $ 4.29 $ 4.64 $ 4.30 $ 4.54
NGL (per Bbl) $ 28.82 $ 37.75 $ 27.79 $ 40.06
Oil (per Bbl) $ 96.83 $ 83.88 $ 89.15 $ 88.24
Total (Mcfe) $ 4.47 $ 5.06 $ 4.46 $ 5.07
Average Realized Prices, excluding hedging:
Natural Gas (per Mcf) $ 3.08 $ 2.56 $ 3.33 $ 2.41
NGL (per Bbl) $ 29.16 $ 29.45 $ 27.90 $ 35.33
Oil (per Bbl) $ 96.83 $ 83.88 $ 89.15 $ 88.24
Total (Mcfe) $ 3.46 $ 3.13 $ 3.66 $ 3.22
Expense per Mcfe:
Lease operating expense
Expense $ 0.73 $ 0.65 $ 0.75 $ 0.71
Equity compensation 0.01 0.01 0.01 0.01
Total lease operating expense $ 0.74 $ 0.66 $ 0.76 $ 0.72
Gathering, processing and transportation expense $ 1.41 $ 1.24 $ 1.34 $ 1.27
Production and ad valorem taxes $ 0.19 $ 0.21 $ 0.19 $ 0.20
Depletion, depreciation and accretion $ 0.57 $ 1.02 $ 0.58 $ 1.36
General and administrative expense
Expense $ 0.28 $ 0.27 $ 0.31 $ 0.33
Audit and accounting fees 0.01 0.03 0.02 0.05
Strategic transaction costs 0.03 0.03 0.03 0.01
Equity compensation 0.09 0.20 0.15 0.16
Total general and administrative expense $ 0.41 $ 0.53 $ 0.51 $ 0.55
Cash expense on debt outstanding $ 1.57 $ 1.32 $ 1.50 $ 1.29
Fees paid on letters of credit outstanding
Net premium paid on senior notes purchased 0.80
Non-cash interest 0.07 0.14 0.28 0.08
Capitalized interest (0.08) (0.20) (0.07) (0.14)
Total interest expense $ 1.56 $ 1.26 $ 2.51 $ 1.23
per day basis, by operating area
Quarter ended Sept 30, Nine months ended Sept 30,
2013 2012 2013 2012
Barnett Shale 166.9 261.5 194.2 284.1
Other U.S. 1.8 3.4 2.4 3.6
Total U.S. 168.7 264.9 196.6 287.7
Horseshoe Canyon 49.5 53.9 49.9 55.0
Horn River 55.7 43.6 59.3 23.3
Total Canada 105.2 97.5 109.2 78.3
Total Company 273.9 362.4 305.8 366.0
In thousands, except per share data - Unaudited
Quarter Ended
September 30,

Nine months ended September 30,
2013 2012 2013 2012
(Restated) (Restated)
Net income (loss) $ 10,577 $ (790,520) $ 193,397 $ (1,804,107)
Gain on sale of assets (7,974) (341,146)
Unrealized (gain)/loss on commodity derivatives (24,724) 72,753 (22,072) 68,960
Termination of NGTL PEA 12,817
Debt issuance and retirement related expenses 2,789 85,943 2,789
Foreign exchange loss on debt paydown 2,456
Impairment of assets 2,266 551,132 4,456 2,068,787
Acceleration of stock compensation expense 2,228
Audit and accounting fees 788 3,479
Strategic transaction costs 823 2,693
Crestwood earn-out (41,097)
Other 25 4,565 826 5,365
Total adjustments before income tax expense (29,584) 632,027 (251,799) 2,108,283
Income tax expense for above adjustments 10,531 163,694 32,182 (321,335)
Total adjustments after tax (19,053) 795,721 (219,617) 1,786,948
Adjusted net income (loss) (8,476) 5,201 (26,220) (17,159)
Adjusted net income (loss) per common share - diluted $ (0.05) $ 0.03 $ (0.15) $ (0.1)
Diluted weighted average common shares outstanding 171,993 170,179 171,573 170,054

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

Source:Quicksilver Resources