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

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

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 million.

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 MMcfed.

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 oil.

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 CO2 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 2018.

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
Total (Bcfe)
Proved Reserves, December 31, 2011 2,160 102,156 3,035 2,791
Revisions (944) (45,378) (479) (1,219)
Extensions, Discoveries, and Other Additions 26 3,518 345 49
Production (106) (4,070) (287) (132)
Acquisitions & Dispositions, net (21) (42) (85) (22)
Proved Reserves, December 31, 2012 1,115 56,184 2,529 1,467
Reserve pricing (first of month trailing 12-month average) 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 performance.

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
December 31,
For the year ended
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 transportation 39,277 48,359 166,316 190,560
Production and ad valorem taxes 4,562 5,382 25,395 29,226
Costs of purchased natural gas 19,513 26,144 62,041 85,398
Depletion, depreciation and accretion 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 BBEP 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 taxes (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 share - basic $ (6.47) $ 0.14 $ (14.61) $ 0.53
Earnings (loss) per common share - diluted $ (6.47) $ 0.14 $ (14.61) $ 0.52
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 accounts 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, respectively) 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 issued, respectively 1,790 1,770
Additional paid in capital 760,341 737,015
Treasury stock of 5,921,102 and 5,379,702 shares, respectively (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 derivative activities 96,058 (51,780)
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 distributions 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 activities (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 funds (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 activities 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 period 13,146 54,937
Cash and cash equivalents at end of period $ 4,951 $ 13,146
Unaudited Selected Operating Results
Quarter ended
December 31,
Year ended
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 expense $ 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
December 31,
Year ended
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
December 31,
Year Ended
December 31,
2012 2011 2012 2011
Net income (loss) (1,100,922) 23,531 (2,485,149) 90,046
Unrealized (gain)/loss on commodity derivatives 3,000 (45,852)
Restructure of hedge contracts 200 14,755
Loss (gain) from hedge ineffectiveness (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 hedges 21,670
Equity portion of interest rate derivatives from BBEP 38 (739)
Equity portion of commodity derivatives from BBEP (23,609) 20,063
Equity portion -loss from sale of properties from BBEP
Gain on BBEP units sold and conveyed (84,646) (217,894)
Inventory adjustment 1,708 1,708
Debt retirement - related expenses 2,943
Interest expense related to debt restructure 1,030 2,789 2,047
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 tax asset 325,847 609,477
Reduction of uncertain tax position liability (9,219)
Acceleration of stock compensation expense 900 4,137
Other 1,130
Total adjustments before income tax expense 1,494,887 (44,037) 3,375,494 (117,187)
Income tax expense for above adjustments (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 share - diluted $ (0.01) $ — $ (0.27) $ 0.12
Diluted weighted average common shares outstanding 170,260 169,409 170,106 169,375

Source:Quicksilver Resources