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KWK > SEC Filings for KWK > Form 10-K on 22-Mar-2013All Recent SEC Filings

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Form 10-K for QUICKSILVER RESOURCES INC


22-Mar-2013

Annual Report


ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following Management's Discussion and Analysis ("MD&A") is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report. Until the sale of all of our interests in KGS, we conducted our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis. Our MD&A includes the following sections:

•         Overview of quarter restatement - a description of the restatement of
          our historical quarterly financial statements


•         Overview - a general description of our business; the value drivers of
          our business; and key indicators


•         2012 Highlights - a summary of significant activities and events
          affecting Quicksilver


•         2013 Capital Program - a summary of our planned capital expenditures
          during 2013


•         Financial Risk Management - information about debt financing and
          financial risk management


•         Results of Operations - an analysis of our consolidated results of
          operations for the three years presented in our financial statements


•         Liquidity, Capital Resources and Financial Position - an analysis of
          our cash flows, sources and uses of cash, contractual obligations and
          commercial commitments


•         Critical Accounting Estimates - a discussion of critical accounting
          estimates that represent choices between acceptable alternatives and/or
          require management judgments and assumptions.

OVERVIEW OF QUARTER RESTATEMENT
As part of our year-end 2012 procedures, we concluded that the documentation for our derivatives designated during 2012 that had fair value on the dates they were initially designated as hedges failed to give consideration to all sources of ineffectiveness. Specifically, our documentation did not include an assessment of whether interest rate changes could cause the instruments to not be effective over the life of the contract, which was required given the presence of fair value at the date of hedge designation. Management had documented its assessment of interest rate risk in 2011 on similar derivatives and concluded its effect to be immaterial and, thus, did not document the risk in 2012. Accordingly, these derivatives did not qualify for hedge accounting in 2012 and their changes in value must be recognized in earnings.
Because the derivatives did not qualify for hedge accounting, their inclusion in the U.S. and Canadian full cost ceiling was inappropriate. Thus, our full cost ceiling calculations were revised and resulted in restatements to impairment expense recognized in earlier quarters. Also, we determined that the deferred taxes used in our Canadian ceiling test for the first two quarters of 2012 included temporary differences for non-property related items. We have restated the ceiling impairments from the interim quarters to correct for these inclusions. The impairment expense that resulted from the ceiling calculation restatements also caused reductions to our depletion rates for the quarters and we have restated depletion expense. Income taxes have also been restated for each of the 2012 quarters to reflect the foregoing restated items.
The following table and subsequent section discuss the effect of the restatement for impacted line items on the consolidated statement of income (loss) for the first three quarters in 2012. Amounts related to derivatives previously classified in other revenue have been reclassified to derivative gains (losses), net. The total impact to the income statement is shown in the Supplemental Selected Quarterly Financial Statements included in Item 8 to this Annual Report.


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                          For the Three Months Ended        For the Three Months Ended       For the Three Months Ended
                                March 31, 2012                    June 30, 2012                  September 30, 2012
                       As previously                       As previously                   As previously
                          reported        As restated        reported       As restated       reported        As restated

Production revenue       171,820              166,454        150,503           150,311       157,699             156,288
Derivative gain
(loss), net                    -               (6,664 )            -            33,139             -             (60,377 )
Total revenue            145,469              172,866        168,562           194,018       177,702             118,188
Depletion,
depreciation and
accretion                 54,439               54,439         51,942            48,016        43,209              34,014
Impairment                62,746              317,928        991,921         1,199,726       546,835             551,132
Operating income
(loss)                   (40,200 )           (267,985 )     (974,589 )      (1,153,012 )    (521,935 )          (576,551 )
Income (loss) before
income taxes             (85,018 )           (312,803 )   (1,019,430 )      (1,197,853 )    (569,410 )          (624,026 )
Income tax (expense)
benefit                   25,094              101,238        346,889           395,831       (82,352 )          (166,494 )
Net income (loss)        (59,924 )           (211,565 )     (672,541 )        (802,022 )    (651,762 )          (790,520 )
Earnings (loss) per
common share - diluted     (0.35 )              (1.24 )        (3.96 )           (4.72 )       (3.83 )             (4.65 )

Quarter Ended March 31, 2012
The derivative restatement adjustment decreased production revenue by $3.6 million and $1.8 million for the U.S. and Canada, respectively, while derivative gains increased $20.7 million and $12.0 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $115.7 million and $139.5 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $41.9 million and $34.2 million for the U.S. and Canada, respectively. Our consolidated net loss increased $151.6 million. The restatement increased diluted net loss per share by $0.89, from diluted net loss per share of $0.35 as previously reported, to diluted net loss per share of $1.24.
Quarter Ended June 30, 2012
The derivative restatement adjustment increased production revenue by $1.3 million for the U.S. and decreased production revenue by $1.5 million for Canada, while derivative gains increased $22.2 million and $3.5 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $144.0 million and $63.8 million for the U.S. and Canada, respectively, while depletion expense decreased $1.3 million and $2.6 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $34.3 million and $14.6 million for the U.S. and Canada, respectively. Our consolidated net loss increased $129.5 million. The restatement increased diluted net loss per share by $0.76, from diluted net loss per share of $3.96 as previously reported, to diluted net loss per share of $4.72.
Quarter Ended September 30, 2012
The derivative restatement adjustment decreased production revenue by $0.3 million and $1.1 million for the U.S. and Canada, respectively, while derivative losses increased $42.8 million and $15.3 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $43.4 million for the U.S. and decreased impairment expense by $39.1 million for Canada, while depletion expense decreased $3.3 million and $5.9 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax expense of $75.3 million and $8.8 million for the U.S. and Canada, respectively. Our consolidated net loss increased $138.8 million. The restatement increased diluted net loss per share by $0.82, from diluted net loss per share of $3.83 as previously reported, to diluted net loss per share of $4.65.
OVERVIEW
We are an independent oil and gas company engaged primarily in the acquisition, exploration, development, and production of onshore oil and gas based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions such as fractured shales, coalbeds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, NGLs and oil. We conduct acquisition, exploration, development, and production activities to replace the reserves that we produce.
At December 31, 2012, 76% and 23% of our proved reserves were natural gas and NGLs, respectively. Consistent with one of our business strategies, we continue to develop our unconventional resources by applying our expertise to our development projects in our Barnett Shale Asset, Horseshoe Canyon Asset and Horn River Asset, which had 81%, 11% and 7%, respectively, of our proved reserves at December 31, 2012. During 2012, based on the success of our exploration in our Horn River Asset, we began to consider this a development area, particularly in the southern portion of our acreage. Our acreage in


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our Horn River Asset provides us the most immediate additional opportunity for further application of our unconventional resources expertise. Our focus for 2013 is on the execution of strategic transactions and the improvement of our capital structure through deleveraging and the extension of our debt maturities. If we are successful with these priorities in 2013, we would expect that we would focus on three other value drivers in the future:
•reserve growth;
•production growth; and
•maximizing our operating margin. Our reserve growth depends on our ability to fund a drilling program. It also relies on our ability to apply our technical and operational expertise to explore and develop unconventional reservoirs. We strive to increase reserves and production through aggressive management of our operations and through relatively low-risk developmental drilling. All of our development and exploratory programs are aimed at providing us with opportunities to develop unconventional reservoirs. We believe the acreage we hold in our core operating areas is well suited for production increases through developmental drilling. We perform workover and infrastructure projects to reduce ongoing operating costs and enhance current and future production rates. We regularly review the properties we operate to determine if steps can be taken to efficiently increase reserves and production. In evaluating the results of our efforts, we consider the capital efficiency of our drilling program and also measure the following key indicators, whose recent results are shown below:

                                                       Years Ended December 31,
                                                   2012 (2)       2011        2010
Organic reserve growth (1)                             (42 )%         1 %        19 %
Production volume (Bcfe)                             131.8        150.6       129.6
Cash flow from operating activities (in millions) $  227.7      $ 253.1     $ 397.7
Diluted earnings (loss) per share                 $ (13.83 )    $  0.52     $  2.50

(1) This ratio is calculated by subtracting beginning of the year proved reserves from adjusted end of the year proved reserves and dividing by beginning of the year proved reserves. Adjusted end of the year reserves are calculated by adding back divested reserves and production and deducting acquired reserves from end of the year reserves.

(2) During 2012, Quicksilver recognized substantial negative reserve revisions due to lower average SEC commodity prices compared to prior periods. As such, we recognized a 1.2 Tcfe negative revision for all of 2012, which represents a 44% decline compared to 2011 year-end reserves. Organic reserve adds in 2012 were approximately 49 Bcfe, which represents less than 2% growth from 2011. The modest level of reserve additions results from two main factors: 1) approximately 85% of the 22 gross wells drilled in the Barnett Shale in 2012 were PUD locations at year-end 2011. Therefore, no new reserves were recognized for these PUD locations after bringing them on line; and 2) we did not recognize significant additional PUD locations at year-end 2012 due the influence of commodity prices on the five-year development profile. Customarily, we would recognize additional PUD locations to offset drilled locations during the year provided the new PUDs meet the SEC's standards, including the five-year limitation.

The organic reserve growth ratio is a supplemental measure that we use to assess how successfully we are implementing our business strategy of pursuing disciplined organic growth. We believe that total reserve growth is a multi-year key value driver of which organic reserve growth is a component. Reserve estimation has inherent limitations which are detailed in our Risk Factors in Item 1A and include assumptions regarding future production rates, timing and amount of future development expenditures, results of geological, geophysical, production and engineering data and economic factors. Any inaccuracies in these assumptions could materially affect the estimated quantities of proved reserves. Item 8 "Supplemental Oil and Gas Information" contains additional information about our reserves.

2012 HIGHLIGHTS
Joint Venture Update
On December 28, 2012, we entered into an agreement with SWEPI LP to jointly develop our oil and gas interests in the Niobrara formation of the Sand Wash Basin and to establish an Area of Mutual Interest ("AMI") covering in excess of 850,000 acres. Each party assigned to the other a 50% working interest in the majority of its combined acreage so that each party owns a 50% interest in more than 320,000 acres and has the right to a 50% interest in any acquisition within the AMI. SWEPI paid us an equalization payment for 50% of the acreage contributed by us in excess of the acreage that SWEPI contributed. SWEPI is


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the operator of the majority of the jointly owned lands. This relationship is strategic to the development of the Niobrara Asset as it created contiguous acreage blocks, which will lead to a more orderly and cost-effective development of the basin.
Quicksilver is engaged in confidential negotiations with a potential buyer to sell a non-operated minority working interest in its Barnett Shale Asset. We continue our efforts to achieve a joint venture in our Horn River Asset in Northeast British Columbia, with the downstream marketing of the gas a top priority. We plan minimal capital spending in our Horn River Asset pending completion of a joint venture.
Horn River Development
We completed our first multi-well pad in our Horn River Asset during June and July 2012. The initial instantaneous production results from these new wells ranged between 23 MMcfd and 34 MMcfd, which exceeded our expectations. Production was curtailed from the new eight-well pad since August 2012 due to a delay in commissioning of a third-party's treating facility and limitations of surface equipment. In December 2012, we secured temporary alternative treating and transportation and increased gross production to 100 MMcfd within 15 days. We do not have a firm date for when the new treating facility, at which we have firm capacity, will be operable, but we believe we have sufficient treating and transportation capacity in the interim to meet our needs.
On January 30, 2013, the Canadian NEB issued its report recommending against approval of NGTL's Komie North Project, which included a 75-mile pipeline that would connect NGTL's Alberta system to a meter station planned to be constructed on our acreage in the Horn River Basin. We believe the NEB's recommendation against the Komie North 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. We believe NGTL will undertake efforts to secure additional shipper support for this pipeline.
We had previously provided $30 million in letters of credit, which were reduced to $14 million during March 2013. We believe future financial assurances, upon a revised application, which we expect may be delayed by up to two years, would be reduced proportionately relative to additional shipper support. Likewise, we are planning to defer drilling in the Horn River Basin until 2014 and have the ability to defer construction of a natural gas treating facility until at least 2016 to coincide with the revised timelines for the Komie North Project. Our 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.
Emerging Basins
During 2012, we drilled and completed three vertical wells in the Sand Wash Basin using a variety of stimulation methods and drilled one well. We are currently conducting exploratory activities and have eight producing wells as of December 31, 2012.
During 2012, we continued to build an oil prospective acreage position in the Bone Springs and Wolfcamp formations in the Midland and Delaware basins in West Texas. Our leases total 125,000 acres across Reeves, Pecos, Jeff Davis, Upton and Crockett Counties. We drilled and completed our first short-lateral well in Pecos County in August 2012, which targeted the Third Bone Springs formation, and we drilled and completed another short-lateral well in Upton County in December 2012, which targeted the Wolfcamp formation. Master Limited Partnership
In February 2012, we filed a Form S-1 with the SEC to begin the registration and sale of limited partnership interests in a master limited partnership holding certain of our mature properties in our Barnett Shale Asset. We amended the registration statement in May to include financial statements for 2011 and to address comments received from the SEC and again in June to include financial statements for the first quarter of 2012 and to address further comments received from the SEC. In July 2012, we were informed that the SEC had no further comments. During the fourth quarter of 2012 we recognized an expense for the deferred filing fees associated with this offering since the transaction has been dormant since June 2012. This accounting treatment does not preclude us from updating the registration document at a later date and we will continue to monitor market conditions to assess the timing of an offering, which may be influenced by a joint venture covering our Barnett Shale Asset.


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Significant Contract Revisions
In August 2012, we amended our Combined Credit Agreements primarily to relax the financial covenants through the second quarter of 2014. Specific changes to the Combined Credit Agreements are outlined in Note 11 to the consolidated financial statements in Item 8.

2013 CAPITAL PROGRAM
We expect our 2013 capital program to be spent in the following areas:
                  (In millions)
Barnett Shale    $            10
Niobrara                      35
West Texas                     6
Total U.S.                    51
Horn River                    29
Horseshoe Canyon               3
Total Canada                  32
Corporate (1)                 37
Total Company    $           120

(1) Includes capitalized interest expense and capitalized internal costs. We expect our 2013 production volume to be between 335 and 345 MMcfe per day.
FINANCIAL RISK MANAGEMENT
We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil production is one of the several risks that we face. We seek to manage this risk by entering into derivative contracts. We have mitigated the downside risk of adverse price movements through the use of these derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. Our commodity price strategy enhances our ability to execute our development and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression. Item 7A of this Annual Report contains details of our commodity price and interest rate risk management.


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RESULTS OF OPERATIONS
"Other U.S." refers to the combined amounts for our operations in our Niobrara Asset, West Texas Asset and Southern Alberta Asset. Revenue
We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Historically, we have used hedge accounting and combining these items mirrors our views of the derivatives' usefulness and provides more comparability. Production Revenue and Realized Cash Gains (Losses) on derivatives by operating area:

                           Natural Gas                             NGL                               Oil                               Total
                  2012        2011        2010        2012        2011        2010        2012       2011       2010       2012        2011        2010

                                                                              (In millions)
Barnett Shale   $ 200.9     $ 376.5     $ 321.2     $ 137.5     $ 216.6     $ 160.6     $ 10.9     $ 11.8     $ 11.8     $ 349.3     $ 604.9     $ 493.6
Other U.S.          0.6         1.1         2.3         0.5         0.6         0.5       13.7       12.3       10.0        14.8        14.0        12.8
Hedging           151.3       100.2       250.2        23.5       (46.1 )     (24.1 )        -          -          -       174.8        54.1       226.1
U.S.              352.8       477.8       573.7       161.5       171.1       137.0       24.6       24.1       21.8       538.9       673.0       732.5
Horseshoe
Canyon             48.2        79.2        90.4         0.1         0.1         0.2          -          -          -        48.3        79.3        90.6
Horn River         23.9        17.4        10.6           -           -           -          -          -          -        23.9        17.4        10.6
Hedging            19.8        30.8        22.7           -           -           -          -          -          -        19.8        30.8        22.7
Canada             91.9       127.4       123.7         0.1         0.1         0.2          -          -          -        92.0       127.5       123.9
Consolidated
production
revenue         $ 444.7     $ 605.2     $ 697.4     $ 161.6     $ 171.2     $ 137.2     $ 24.6     $ 24.1     $ 21.8     $ 630.9     $ 800.5     $ 856.4

U.S. realized
cash derivative
gains              23.0           -           -           -           -           -          -          -          -        23.0           -           -
Canada realized
cash derivative
gains              19.8           -           -           -           -           -          -          -          -        19.8           -           -
Consolidated
realized cash
derivative
gains              42.8           -           -           -           -           -          -          -          -        42.8           -           -
Consolidated
production
revenue and
realized cash
derivative
gains (1)       $ 487.5     $ 605.2     $ 697.4     $ 161.6     $ 171.2     $ 137.2     $ 24.6     $ 24.1     $ 21.8     $ 673.7     $ 800.5     $ 856.4

(1) Realized cash derivative gains from derivatives not treated as hedges are included in derivative gains (losses), net. Unrealized derivative gains and losses and hedge ineffectiveness make up the the remainder of derivative gains (losses), net as reported on our statement of income. A discussion of derivative gains (losses), net is found elsewhere in our discussion of our results of operation. Total revenue is comprised of production revenue, derivative gains (losses), net, sales of purchased natural gas and other revenue.

Average Daily Production Volume by operating area:

                         Natural Gas                        NGL                           Oil                   Equivalent Total
                  2012      2011      2010       2012       2011       2010      2012     2011     2010     2012      2011      2010

                           (MMcfd)                         (Bbld)                        (Bbld)                     (MMcfed)
Barnett Shale    206.2     261.8     207.9     11,090     12,117     11,913      333      352      433     274.8     336.6     281.9
Other U.S.         0.6       0.8       1.5         26         24         25      451      396      397       3.5       3.3       4.0
U.S.             206.8     262.6     209.4     11,116     12,141     11,938      784      748      830     278.3     339.9     285.9
Horseshoe Canyon  54.6      58.4      61.2          5          6          8        -        -        -      54.6      58.5      61.2
Horn River        27.1      14.1       8.0          -          -          -        -        -        -      27.1      14.1       8.0
Canada            81.7      72.5      69.2          5          6          8        -        -        -      81.7      72.6      69.2
Consolidated     288.5     335.1     278.6     11,121     12,147     11,946      784      748      830     360.0     412.5     355.1


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Average Realized Price by operating area:

                         Natural Gas                            NGL                                 Oil                         Equivalent Total
                  2012       2011       2010       2012        2011        2010        2012        2011        2010        2012       2011       2010

                          (per Mcf)                          (per Bbl)                           (per Bbl)                         (per Mcfe)
Barnett Shale   $ 2.66     $ 3.94     $ 4.23     $ 33.87     $ 48.98     $ 36.93     $ 89.85     $ 91.83     $ 74.71     $ 3.47     $ 4.92     $ 4.80
. . .
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