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| KWK > SEC Filings for KWK > Form 10-K on 22-Mar-2013 | All Recent SEC Filings |
22-Mar-2013
Annual Report
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.
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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.
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 )
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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
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
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(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
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.
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
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(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.
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
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(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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