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Quicksilver Resources 10-K 2009 Documents found in this filing:Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
FORM 10-K/A
(Amendment No. 3)
For the fiscal year ended December 31, 2008
OR
For the transition period from to
Commission file number: 001-14837
QUICKSILVER RESOURCES INC.
(Exact name of registrant as specified in its charter)
817-665-5000
(Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Exchange Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large
accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
As of June 30, 2008, the aggregate market value of the registrant’s common stock held by
non-affiliates of the registrant was $4,067,732,259 based on the closing sale price of $38.64 as
reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as
of the latest practicable date.
DOCUMENTS INCORPORATED BY REFERENCE
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Explanatory Note
This
Amendment No. 3 to the Annual Report on Form 10-K (this
“Amendment No. 3” or this “Report”) of Quicksilver Resources Inc.
(“Quicksilver”) for the year ended December 31, 2008,
originally filed on March 3, 2009 (as amended on March 9, 2009 and June 1, 2009, the
“Original
Form 10-K”) is being filed to correct certain footnote
disclosures regarding amounts reported for Quicksilver’s guarantor and non-guarantor
subsidiaries and to include disclosure of information for restricted
subsidiaries that was not previously presented. Notes 14 and 21
in the Original Form 10-K have been corrected for these matters.
In Note 21 Condensed Consolidating
Financial Information, the Company has identified and corrected
errors in the presentation of its guarantor and non-guarantor
condensed consolidating financial information. Also, as
previously disclosed in Note 14 Long Term Debt, the Company
indicated that it was in compliance with its long term debt, other
notes and loans. Subsequent to the issuance of the Original Form
10-K, the Company determined that financial information about the
Company and its restricted subsidiaries should be included in the
notes to the consolidated financial statements pursuant to its
supplemental indentures. Accordingly, Note 14
has been restated to reference the inclusion within Notes 21 and 27 of
the condensed consolidating
financial information about the Company and its restricted subsidiaries. Note 27
in Item 8 of this Amendment No. 3 contains added and restated
guarantor and non-guarantor unaudited interim condensed consolidating
financial information.
Management’s Discussion and Analysis of Financial Condition
and Results of Operation in Item 7 has also been revised to
provide information about the
Company and its restricted subsidiaries. Also, Item 9A Controls and
Procedures has been amended to report the material weaknesses
associated with the restatement described above and the risk
factors in Item 1A Risk Factors have been similarly
updated. Items previously included in the Original Form 10-K not
affected by the restatement have been omitted.
Except for the adoption of accounting pronouncements more fully discussed below, this Amendment No. 3 does not alter or adjust the consolidated results of operation, financial
position or cash flows in the Original 10-K.
Unless otherwise noted, all of the information in this Amendment No.
3 is as of December 31, 2008 and reflects no events after that date
other than the restatement and the adoption of accounting
pronouncements described below. Our previously filed Quarterly Report
on Form 10-Q for the three months ended March 31, 2009 originally
filed on May 7, 2009 will also be amended and filed.
The consents of Schlumberger Data and Consulting Services, LaRoche Petroleum Consultants, Ltd.,
Netherland, Sewell & Associates Inc., PricewaterhouseCoopers LLP
and Deloitte & Touche LLP and new certifications of Quicksilver’s principal chief executive officer and
principal financial officer are also filed as exhibits to this Amendment No. 3 under Item 15.
Quicksilver is also amending the Original Form 10-K to revise certain financial information to correspond to the
manner in which Quicksilver presents such financial information following
its adoption
of the accounting pronouncements described below. All changes to
consolidated financial information solely relate to the adoption of
accounting pronouncements and are unrelated to the error correction
discussed above.
As
previously disclosed in the Quarterly Report on Form 10-Q for the three months ended March 31, 2009, on
January 1, 2009, we adopted the following accounting pronouncements (collectively the
“Adopted Pronouncements”):
This
Report revises financial information
to reflect the Company’s retrospective application of the Adopted
Pronouncements including:
Except as otherwise specified and unless the context otherwise
requires, references to the “Company,”
“Quicksilver,” “we,” “us,” and
“our” refer to Quicksilver Resources Inc. and its
subsidiaries.
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As
further discussed in Note 21 (Restated) to our
consolidated financial statements in Item 8 to this Report the
Company has corrected financial information previously reported and has included information about the Company and its restricted subsidiaries, and
the following risk factors have been updated to reflect risks
associated therewith.
You should carefully consider the following risk factors together with all of the other
information included in this annual report, including the financial statements and related notes,
when deciding to invest in us. You should be aware that the occurrence of any of the events
described in this Risk Factors section and elsewhere in this annual report could have a material
adverse effect on our business, financial position, results of operations and cash flows.
Natural gas, NGL and crude oil prices fluctuate widely, and low prices could have a material
adverse impact on our business, financial condition, results of operations and cash flows.
Our revenue, profitability and future growth depend in part on prevailing natural gas, NGL and
crude oil prices. These prices also affect the amount of cash flow available to service our debt,
pay for our capital expenditures and fund our other liquidity needs, as well as our ability to
borrow, raise additional capital and comply with the terms of our debt agreements. Among other
things, the amount we can borrow under our Senior Secured Credit Facility is subject to periodic
redetermination based in part on changing expectations of future prices. Lower prices may also
reduce the amount of natural gas, NGLs and crude oil that we can economically produce.
While prices for natural gas and crude oil may be favorable at any point in time, they
fluctuate widely, particularly as evidenced by price movements in the latter half of 2008. Among
the factors that can cause these fluctuations are:
Due to the volatility of natural gas and crude oil prices and our inability to control the
factors that influence them, we cannot predict future pricing levels.
If natural gas, NGL or crude oil prices decrease, our exploration and development efforts are
unsuccessful or our costs increase substantially, we may be required to recognize impairment of
our oil and gas properties, which could have a material adverse effect on our financial condition,
our results of operations and our ability to borrow under and comply with our debt agreements.
We employ the full cost method of accounting for our oil and gas properties, whereby all costs
associated with acquiring, exploring for, and developing natural gas and crude oil reserves are
capitalized and accumulated in separate country cost centers. These capitalized costs are
amortized based on production from the reserves for each country cost center. Each capitalized
cost pool cannot exceed the net present value of the underlying natural gas, NGL and crude oil
reserves. Impairment to the carrying value of our oil and gas properties was recognized in the
fourth quarter of 2008 and could occur again in the future if natural gas, NGL or crude oil prices
at a reporting period end result in decreased value of our reserves. Increased operating and
capitalized costs without incremental increases in natural gas and crude oil reserves could also
trigger impairment based on decreased value of our reserves. In the event of impairment of our oil
and gas properties, we reduce their carrying value and recognize expense in the amount of the
impairment, which could be material and could adversely affect our financial condition and results
of operations and our ability to borrow under and comply with the terms of our debt agreements.
Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material
inaccuracies in these reserve estimates or underlying assumptions may materially affect the
quantities and present value of our reserves.
The process of estimating natural gas, NGL and crude oil reserves is complex. It requires
interpretations of available technical data and various assumptions, including assumptions relating
to economic factors. Any significant inaccuracies in these interpretations or assumptions could
materially affect the estimated quantities and present value of reserves disclosed in our filings
with the SEC.
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In order to prepare these estimates, we and independent reserve engineers engaged by us must
project production rates and timing of development expenditures. We and the engineers must also
analyze available geological, geophysical, production and engineering data, and the extent, quality
and reliability of this data can vary. The process also requires economic assumptions with respect
to natural gas and crude oil prices, drilling and operating expenses, capital expenditures, taxes
and availability of funds. Therefore, estimates of natural gas, NGL and crude oil reserves are
inherently imprecise.
Actual future production, natural gas, NGL and crude oil prices and revenue, taxes,
development expenditures, operating expenses and quantities of recoverable natural gas and crude
oil reserves most likely will vary from our estimates. Any significant variance could materially
affect the estimated quantities and present value of reserves disclosed in this annual report. In
addition, we may adjust estimates of proved reserves to reflect production history, results of
exploration and development, prevailing petroleum prices and other factors, which may be beyond our
control.
At December 31, 2008, approximately 37% of our estimated proved reserves were undeveloped.
Undeveloped reserves, by their nature, are less certain than comparable developed reserves.
Recovery of undeveloped reserves requires additional capital expenditures and successful drilling
and completion operations. Our reserve data assumes that we will make significant capital
expenditures to develop our reserves. Although we have prepared estimates of our reserves and the
costs associated with them in accordance with industry standards, there is risk that the estimated
costs are inaccurate, that development will not occur as scheduled or that actual results will not
be as estimated.
The present value of future net cash flows disclosed in Item 8 of this annual report is not
necessarily the fair value of our estimated proved natural gas and crude oil reserves. In
accordance with SEC requirements, the estimated discounted future net cash flows from proved
reserves are based on prices and costs as of period end. Actual future prices and costs may be
materially higher or lower than the prices and costs as of the date of the estimate. Any changes
in consumption by natural gas, NGL and crude oil purchasers or in governmental regulations or
taxation will also affect actual future net cash flows. The timing of both the production and the
expenses from the development and production of natural gas and crude oil properties will affect
the timing of actual future net cash flows from proved reserves and their present value. In
addition, the 10% discount factor, which is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the most appropriate
discount factor. The effective interest rate at various times and the risks associated with our
business or the oil and natural gas industry in general will affect the appropriateness of the 10%
discount factor in arriving at the reserves’ actual fair value.
Our production is concentrated in a small number of geographic areas.
Approximately 75% of our 2008 production was from Texas and approximately 24% was from
Alberta, Canada. Because of our concentration in these geographic areas, any regional events that
increase costs, reduce availability of equipment or supplies, reduce demand or limit production,
including weather and natural disasters, may impact us more than if our operations were more
geographically diversified.
Our Canadian operations present unique risks and uncertainties, different from or in addition to
those we face in our domestic operations.
In addition to the various risks associated with our U.S. operations, risks associated with
our operations in Canada, where we have substantial operations, include, among other things, risks
related to increases in taxes and governmental royalties, changes in laws and policies governing
operations of foreign-based companies, currency restrictions and exchange rate fluctuations. Laws
and policies of the United States affecting foreign trade and taxation may also adversely affect
our Canadian operations.
We may have difficulty financing our planned growth.
We have experienced capital expenditure and working capital needs, particularly as a result of
our property acquisition and drilling activities. For 2009, we plan to operate our capital program
within our operating cash flows. However, in the future, we may require additional financing above
the level of cash generated by our operations to fund our growth. If revenue decreases as a result
of lower petroleum prices or otherwise, our ability to expend the
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capital necessary to replace our reserves or to maintain production of current levels may be
limited, resulting in a decrease in production over time. If our cash flow from operations is not
sufficient to satisfy our capital expenditure requirements, we cannot be certain that additional
financing will be available to us on acceptable terms or at all. In the event additional capital
resources are unavailable, we may curtail our activities or be forced to sell some of our assets on
an untimely or unfavorable basis.
We are vulnerable to operational hazards, transportation dependencies, regulatory risks and other
uninsured risks associated with our activities.
The oil and natural gas business involves operating hazards such as well blowouts, explosions,
uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal
pressures, treatment plant “downtime”, pipeline ruptures or spills, pollution, releases of toxic
gas and other environmental hazards and risks, any of which could cause us to experience
substantial losses. Also, the availability of a ready market for our natural gas and crude oil
production depends on the proximity of reserves to, and the capacity of, natural gas and crude oil
gathering systems, treatment plants, pipelines and trucking or terminal facilities.
U.S. and Canadian federal, state and provincial regulation of oil and natural gas production
and transportation, tax and energy policies, changes in supply and demand and general economic
conditions could adversely affect our ability to produce and market our natural gas, NGLs and crude
oil. In addition, we may be liable for environmental damage caused by previous owners of
properties purchased or leased by us.
As a result of operating hazards, regulatory risks and other uninsured risks, we could incur
substantial liabilities to third parties or governmental entities. We maintain insurance against
some, but not all, of such risks and losses in accordance with customary industry practice.
Generally, environmental risks are not fully insurable. The occurrence of an event that is not
covered, or not fully covered, by insurance could have a material adverse effect on our business,
financial condition and results of operations.
The failure to replace our reserves could adversely affect our production and cash flows.
Our future success depends upon our ability to find, develop or acquire additional reserves
that are economically recoverable. Our proved reserves will generally decline as reserves are
produced, except to the extent that we conduct successful exploration or development activities or
acquire properties containing proved reserves. In order to increase reserves and production, we
must continue our development drilling and recompletion programs or undertake other replacement
activities. Our current strategy is to maintain our focus on low-cost operations while increasing
our reserve base and production through exploration and development of our existing properties.
Our planned exploration or development projects or any acquisition activities that we may undertake
might not result in meaningful additional reserves and we might not have continuing success
drilling productive wells. Furthermore, while our revenue may increase if prevailing petroleum
prices increase materially, our finding costs also could increase.
We have risk through our investment in BBEP.
We own a 41% limited partner interest in BBEP from which we expect to receive distributions.
We have no management oversight over BBEP, its financial condition, its operating results or its
financial reporting process and are subject to the risks associated with BBEP’s business and
operations. Moreover, the management of BBEP has discretion over the amount, if any, that they
distribute to unitholders.
The nature of our ownership interest in a publicly-traded entity subjects us to market risks
associated with most ownership interests traded on a public exchange. Sales of substantial amounts
of BBEP limited partner units, or a perception that such sales could occur, and various other
factors, could adversely affect the market price of BBEP limited partner units. Impairment to the
carrying value of BBEP limited partnership units was recognized in the forth quarter of 2008, and
could occur again in the future if the market price for BBEP units declines further. In the event
of impairment of our BBEP units, we reduce the carrying value of our BBEP units and recognize
expense in the amount of the impairment, which could be material and could adversely affect our
financial condition and results of operations and our ability to borrow under and comply with the
provisions of our debt agreements.
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We have risk through our ownership of KGS.
Through our ownership interest in KGS, we share in KGS’ results of operations and may be
entitled to distributions from KGS. Accordingly, we have diminished control over assets owned by
KGS and assets which KGS has a right to acquire. We are also subject to the risks associated with
KGS’ business and operations, including, but not limited to:
We cannot control the operations of gas processing and transportation facilities we do not own or
operate.
We deliver our Canadian production to market primarily by either the TransCanada or ATCO
systems. We have no influence over the operation of these facilities and must depend upon their
owners to minimize any loss of processing and transportation capacity.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent on a relatively small group of key management personnel,
including our executive officers. There is a risk that the services of all of these individuals
may not be available to us in the future. Because competition for experienced personnel in our
industry can be intense, we may be unable to find acceptable replacements with comparable skills
and experience and their loss could have an adverse effect on us.
Competition in our industry is intense, and we are smaller and have a more limited operating
history than many of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions.
We also compete for the equipment and labor required to develop and operate our properties. Many
of our competitors have substantially greater financial and other resources than we do. In
addition, larger competitors may be able to absorb the burden of any changes in federal, state,
provincial and local laws and regulations more easily than we can, which would adversely affect our
competitive position. These competitors may be able to pay more for exploratory prospects and
productive natural gas and crude oil properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than we can. Our ability to explore for
natural gas and crude oil prospects and to acquire additional properties in the future will depend
on our ability to conduct operations, to evaluate and select suitable properties and to complete
transactions in this highly competitive environment. Furthermore, the oil and natural gas industry
competes with other industries in supplying the energy and fuel needs of industrial, commercial,
and other consumers.
Hedging our production may result in losses or limit our ability to benefit from price increases.
To reduce our exposure to petroleum price fluctuations, we have entered into financial hedging
arrangements which may limit the benefit we would receive from increases in petroleum prices.
These hedging arrangements also expose us to risk of financial losses in some circumstances,
including the following:
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The result of natural gas market prices exceeding collar ceilings requires us to make monthly
cash payments. If we choose not to engage in hedging arrangements in the future, we could be more
affected by changes in natural gas, NGL and crude oil prices than our competitors who engage in
hedging arrangements.
Delays in obtaining oil field equipment and increases in drilling and other service costs could
adversely affect our ability to pursue our drilling program and our results of operations.
As natural gas, NGL and crude oil prices increase, demand and costs for drilling equipment,
crews and associated supplies, equipment and services can increase significantly. We cannot be
certain that in a higher petroleum price environment we would be able to obtain necessary drilling
equipment and supplies in a timely manner or on satisfactory terms, and we could experience
shortages of, or material increases in the cost of, drilling equipment, crews and associated
supplies, equipment and services. Any such delays and price increases could adversely affect our
ability to pursue our drilling program and our results of operations.
Our activities are regulated by complex laws and regulations, including environmental regulations
that can adversely affect the cost, manner or feasibility of doing business.
Natural gas, NGL and crude oil operations are subject to various U.S. and Canadian federal,
state, provincial and local government laws and regulations that could change in response to
economic or political conditions. Matters that are typically regulated include:
From time to time, regulatory agencies have imposed price controls and limitations on
production by restricting the rate of flow of natural gas and crude oil wells below actual
production capacity to conserve supplies of natural gas and crude oil. We also are subject to
changing and extensive tax laws, the effects of which cannot be predicted.
The development, production, handling, storage, transportation and disposal of natural gas and
crude oil, by-products and other substances and materials produced or used in connection with our
operations are also subject to laws and regulations primarily relating to protection of human
health and the environment. The discharge of natural gas, crude oil or pollutants into the air,
soil or water may give rise to significant liabilities on our part to the government and third
parties and may result in the assessment of civil or criminal penalties or require us to incur
substantial costs of remediation.
Legal and tax requirements frequently are changed and subject to interpretation, and we are
unable to predict the ultimate cost of compliance with these requirements or their effect on our
operations. We cannot assure you that existing laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations, will not materially adversely affect
our business, results of operations and financial condition.
The risks associated with our debt could adversely affect our business, financial condition and
results of operations and the value of our securities.
Subject to the limits contained in our various debt agreements, we may incur additional debt.
Our ability to incur additional debt and to comply with the terms of our debt agreements is
affected by a variety of factors, including natural gas, NGL and crude oil prices and their effects
on our financial condition, results of operations and
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cash flows. Among other things, our ability to borrow under our Senior Secured Credit
Facility is subject to the quantity and value of our proved reserves and other assets, including
our investment in BBEP. If we incur additional debt or fail to increase the quantity and value of
our proved reserves, the risks that we now face as a result of our indebtedness could intensify.
We have demands on our cash resources in addition to interest expense, including operating
expenses, principal payments under our debt and funding of our capital expenditures. Our level of
debt, the value of our oil and gas properties and other assets, the demands on our cash resources,
and the provisions of our debt agreements could have important effects on our business and on the
value of our securities. For example, they could:
Our ability to pay principal and interest on our debt, to otherwise comply with the provisions
of our debt agreements and to refinance our debt may be affected by economic and capital markets
conditions and other factors that may be beyond our control. If we are unable to service our debt
and fund our other liquidity needs, we will be forced to adopt alternative strategies that may
include:
We cannot assure you that we would be able to implement any of these strategies on
satisfactory terms, if at all, and our inability to do so could cause the holders of our securities
to experience a partial or total loss of their investment in us.
Our debt agreements restrict our ability to engage in certain activities.
Our debt agreements restrict our ability to, among other things:
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Our debt agreements, among other things, also require the maintenance of financial covenants
that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this
annual report. Our ability to comply with these covenants and other provisions of our debt
agreements may be affected by events beyond our control, and we may be unable to comply with all
aspects of our debt agreements in the future. In addition, our ability to borrow under our Senior
Secured Credit Facility is dependent upon the quantity and value of our proved reserves and other
assets, including our investment in BBEP.
The provisions of our debt agreements may affect the manner in which we obtain future
financing, pursue attractive business opportunities and plan for and react to changes in business
conditions. In addition, failure to comply with the provisions of our debt agreements could result
in an event of default which could enable the applicable creditors, subject to the terms and
conditions of the applicable agreement, to declare the outstanding principal of that debt, together
with accrued interest, to be immediately due and payable. Moreover, any of our debt agreements that
contain a cross-default or cross-acceleration provision could also be subject to acceleration. If
we were unable to repay the accelerated amounts, the creditors could proceed against the collateral
granted to them to secure such debt. If the payment of our debt is accelerated, there can be no
assurance that our assets would be sufficient to repay such debt in full, and the holders of our
securities could experience a partial or total loss of their investment.
Parties with whom we do business may become unable or unwilling to timely perform their
obligations to us.
We enter into contracts and transactions with various third parties, including contractors,
suppliers, customers, lenders and counterparties to hedging arrangements, under which such third
parties incur performance or payment obligations to us. Any delay or failure on the part of one or
more of such third parties to perform their obligations to us could, depending upon the nature and
magnitude of such failure or failures, have a material adverse effect on our business, financial
condition and results of operations.
A small number of existing stockholders exercise significant control over our company, which could
limit your ability to influence the outcome of stockholder votes.
Members of the Darden family, together with entities controlled by them, beneficially owned
approximately 30% of our common stock as of December 31, 2008. As a result, they are generally
able to significantly affect the outcome of stockholder votes, including votes concerning the
election of directors, the adoption or amendment of provisions in our charter or bylaws and the
approval of mergers and other significant corporate transactions.
A large number of our outstanding shares and shares to be issued upon conversion of our
outstanding convertible debentures or exercise of our outstanding options may be sold into the
market in the future, which could cause the market price of our common stock to drop
significantly, even if our business is performing well.
Our shares that are eligible for future sale may adversely affect the price of our common
stock. There were more than 167 million shares of our common stock outstanding at December 31,
2008. Approximately 116 million of these shares are freely tradable without substantial
restriction or the requirement of future registration under the Securities Act. In addition, when
the conditions permitting conversion of our convertible debentures are satisfied, the holders could
elect to convert such debentures. Based on the applicable conversion rate at December 31, 2008,
the holders’ election to convert such debentures could result in an aggregate of 9,816,270 shares
of our common stock being issued. We also had 1,103,336 options outstanding to purchase shares of
our common stock at December 31, 2008 as detailed in Note 20 to the consolidated financial
statements in Item 8 of this annual report.
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Sales of substantial amounts of common stock, or a perception that such sales could occur, and
the existence of conversion and option rights to acquire shares of common stock at prices that may
be below the then current market price of the common stock, could adversely affect the market price
of our common stock and could impair our ability to raise capital through the sale of our equity
securities.
Our amended and restated certificate of incorporation, restated bylaws and stockholder rights plan
contain provisions that could discourage an acquisition or change of control without our board of
directors’ approval.
Our amended and restated certificate of incorporation and restated bylaws contain provisions
that could discourage an acquisition or change of control without our board of directors’ approval.
In this regard:
In addition, we have adopted a stockholder rights plan which could also impede a merger,
consolidation, takeover or other business combination involving us, even if that change of control
might be beneficial to stockholders, thus increasing the likelihood that incumbent directors will
retain their positions. In certain circumstances, the fact that corporate devices are in place
that will inhibit or discourage takeover attempts could reduce the market value of our common
stock.
We have identified material weaknesses in our internal controls that, if not properly
corrected, could result in material misstatements in our financial statements.
We and our auditors have identified two material weaknesses in our system of internal
control over financial reporting as of December 31, 2008. A material weakness is a deficiency, or
combination of deficiencies in internal controls over financial reporting that results in a
reasonable possibility that a material misstatement of our annual or interim financial statements
will not be prevented or detected on a timely basis.
The first material weakness related to the preparation of combined financial information
within our condensed consolidating financial information. The condensed consolidating information
previously reported contained errors that included “combining
adjustments” for non-guarantor subsidiaries being reported within “consolidating eliminations” and in the amounts reported for equity
earnings of wholly owned subsidiaries. These errors did not affect the amounts previously reported
in our consolidated financial statements. To remedy this material weakness, we have revised our
process to better structure the preparation and allow for further review of our consolidating
financial information.
The
second material weakness related to the monitoring of our financial
reporting requirements, particularly with respect to the form and
content of our condensed consolidating financial information and the
financial information about the Company and our restricted
subsidiaries. To remedy this
material weakness we have enhanced our process for documenting and satisfying the full extent of
our financial reporting requirements.
Although there can be no assurances, we believe these enhancements and improvements, when
repeated in future periods, will remediate the material weaknesses described above. If we are not
able to remedy the material weaknesses in a timely manner, we may be unable to provide our
securityholders with the required financial information in a timely and reliable manner and we may
incorrectly report financial information, either of which could subject us to litigation and regulatory
enforcement actions.
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As further discussed in Note 2 to our consolidated financial statements included in Item 8 of this Report, our consolidated financial statements for each period presented have been
adjusted for the retrospective application of the Adopted Pronouncements.
Item 6. Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, our selected
financial information which for each of the three years in the
period ended December 31, 2008 and as of December 31, 2008 and 2007 is derived from the consolidated financial statements included in Item 8. The remaining data is derived from the audited financial statements from earlier periods not included in this Report. The information should be read in conjunction with “Management’s Discussion and Analysis
of Financial Condition and Results of Operations” and our consolidated financial statements and
notes thereto contained in this Report. The following information is not necessarily indicative of
our future results.
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As further discussed in Note 2 to our consolidated financial statements included in Item 8 of this Report, our consolidated financial statements for each period presented, as well as
the financial information in the following discussion, have been adjusted for the retrospective
application of the Adopted Pronouncements. Supplemental
information has also been provided regarding the Company’s
“restricted” subsidiaries under the caption
“Quicksilver Resources Inc. and its Restricted
Subsidiaries” below.
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 the reader
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. We conduct our operations in two segments: (1) our more dominant
exploration and production segment, and (2) our significantly smaller gathering and processing
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
We are a Fort Worth, Texas-based independent oil and gas company engaged in the acquisition,
exploration, exploitation, development and production of natural gas, NGLs, and crude oil. We focus
primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological
conditions such as fractured shales, coal beds and tight sands. We generate revenue, income and
cash flows by producing and selling natural gas, NGLs and crude oil. Our production generates
earnings and cash flow that allow us to conduct acquisition, exploration, exploitation, development
and production activities to replace the reserves that we produce.
At December 31, 2008, approximately 99% of our proved reserves were natural gas and NGLs.
Consistent with one of our business strategies, we have developed and applied the expertise gained
in developing our now divested Northeast Operations to our projects in Alberta, Canada and our
Barnett Shale interests in Texas. Our Texas and Alberta reserves made up approximately 84% and 15%,
respectively, of our proved reserves at December 31, 2008. Our acreage in the Horn River Basin in
British Columbia will provide additional opportunity for further application of this expertise.
For 2009, we plan to continue our focus on the development and exploitation of our properties
in Texas and Alberta and to begin exploration in the Horn River Basin. We have allocated $400
million of our 2009 consolidated capital budget of $600 million for drilling and completion
activities. Approximately $330 million is allocated to projects in Texas and approximately $57
million is allocated to our Canadian projects. Approximately $155 million of the 2009 capital
budget has been allocated to construction of natural gas processing and gathering assets, including
$35 million to be funded directly by KGS.
Our Company focuses on three key value drivers:
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Our reserve growth relies on our ability to apply our technical and operational expertise in
our core operating areas to develop, exploit and explore unconventional natural gas reservoirs. We
strive to increase reserves and production through aggressive management of operations and through
relatively low-risk development and exploitation drilling. We will also continue to identify
high-potential exploratory projects with comparatively higher levels of financial risk. All of our
development and exploratory programs are aimed at providing us with opportunities to develop and
exploit unconventional natural gas reservoirs which align our technical and operational expertise.
Our core operating areas and the acreage that we hold are well suited for production increases
through development and exploitation drilling. We perform workover and infrastructure projects to
reduce ongoing operating costs and increase current and future production rates. We regularly
review our operated properties to determine if steps can be taken to profitably increase reserves
and production.
In evaluating the result of our efforts, we consider the capital efficiency of our drilling
program and also measure the following key indicators: reserve growth; production volumes; cash
flow from operating activities; and earnings per share.
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 crude oil
production is among the several risks that we face. We seek to manage this risk by entering into
financial hedges. We have mitigated the downside risk of adverse price movements through the use of
derivatives but, in doing so, have also limited our ability to benefit from favorable price
movements. This commodity price strategy enhances our ability to execute our development,
exploitation and exploration programs, meet debt service requirements and pursue acquisition
opportunities even in periods of price volatility.
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RESULTS OF OPERATIONS
Revenue
Natural Gas, NGL and Crude Oil
Production Revenue:
Average Daily Production Volumes:
Average Realized Prices:
The following table summarizes the changes in our natural gas, NGL and crude oil revenue:
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Our natural gas revenue for 2008 increased as a result of both a $1.37 per Mcf increase in
realized prices and a 22.8 MMcfd increase in volumes as compared to 2007. Natural gas production in
the U.S. increased 72.7 MMcfd as a result of the impact of new wells placed into production
partially offset by production declines for existing wells, primarily in the Fort Worth Basin. The
November 2007 divestiture of our Northeast Operations reduced our natural gas production by 56.1
MMcfd and the Alliance Acquisition increased production by 17.0 MMcfd on an annualized basis.
Additional wells on our Canadian interests increased production by 6.2 MMcfd from 2007.
NGL revenue for 2008 increased as a result of production increases and realized prices that
were $2.21 per Bbl higher than 2007 NGL realized prices. Additional Texas natural gas production in
the high-BTU area of the Barnett Shale and processing improvements during 2008 increased NGL
volumes 5,030 Bbld when compared to 2007. Partially offsetting the Texas production and pricing
increases was the absence of production due to the divestiture of the Northeast Operations.
Crude oil revenue for 2008 was higher than 2007 due to a $14.96 per Bbl increase in realized
prices. Production increases of 524 Bbld from the Fort Worth Basin in 2008 partially offset the
divested production from the Northeast Operations.
Our natural gas revenue for 2007 increased from 2006 as a result of both a $0.68 per Mcf
increase in realized natural gas prices and a 17.4 MMcfd increase in volumes as compared to 2006.
Natural gas revenue in the U.S. increased 10.6 MMcfd as a result of new wells placed into
production, primarily in the Fort Worth Basin. The November 2007 divestiture of our Northeast
Operations reduced our natural gas production as did natural production declines in this area.
Additional wells on our Canadian interests increased production by 6.8 MMcfd from 2006.
NGL revenue for 2007 was almost three times higher than 2006, which primarily resulted from an
incremental 1,724 MBbl increase in NGL production resulting from additional Texas natural gas
production in the high-BTU area of the Barnett Shale during 2007. Also, more favorable pricing of
$4.38 per Bbl contributed to the increase when compared to 2006 NGL revenue.
Crude oil revenue for 2007 was higher than 2006 due to a $3.88 per Bbl increase in realized
prices. Fort Worth Basin production in 2007 increased to partially offset the impact of the
divestiture of our Northeast Operations.
Other Revenue
Other revenue, consisting primarily of revenue from the processing, gathering and marketing of
natural gas, was $19.9 million for 2008, an increase of $3.7 million compared with 2007. Throughput
from third parties in our gathering and processing assets operated by KGS increased other revenue
by $6.2 million. Partially offsetting the increase was the
absence of $4.9 million of Canadian
government grants for new drilling techniques we received in 2007.
Other revenue was $16.2 million for 2007, an increase of $12.3 million compared with 2006.
This increase is primarily due to $5.1 million from higher throughput from third parties in our
gathering and processing assets operated by KGS and $4.3 million more in Canadian government grants
for new drilling techniques compared to 2006. Hedge ineffectiveness in 2007 also increased other
revenue $1.0 million compared to 2006.
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Operating Expenses
Oil and Gas Production Expenses
Oil and gas production expense for 2008 was almost unchanged from 2007. The absence of
production expense of $48.9 million for the divested Northeast Operations was offset by the growth
of our operations in the Fort Worth Basin and Canada that increased production expense $39.2
million and $5.5 million, respectively, as production volumes increased 117% and 11%, respectively,
for 2008 as compared to 2007, as discussed previously.
Although oil and gas production expense for our Fort Worth Basin operations were $39.2 million
higher for 2008, production expense per Mcfe decreased 21% to $1.30 per Mcfe when compared to 2007.
The improvement in production expense on a Mcfe-basis was primarily the result of higher production
levels, cost containment initiatives, new completion techniques used in our capital program and
higher utilization of automation during 2008. Canadian production expense increased primarily as a
result of the 11% increase in production volumes and an increase in personnel costs plus higher
prevailing exchange rates during 2008.
Oil and gas production expense for 2007 increased by $41.7 million from 2006 levels, primarily
due to costs associated with higher production levels. On a Mcfe-basis, our costs increased 14%
compared to 2006 levels. Although overall costs increased in Texas, our production and number of
producing properties increased while our cost per Mcfe of production decreased. Our 2007 production
costs for the Northeast Operations reflected $6.3 million of employee severance cost associated
with its divestiture. Northeast Operations unit costs were also impacted by production declines.
The total cost increases reflect salary increases of $3.7 million associated with headcount
increases. Canadian production expense increased $8.5 million due to an estimated $1.4 million for
currency effects of the strengthening Canadian dollar, $1.2 million higher gathering and processing
costs, $2.0 million in increased direct operating cost associated with new producing properties and
more than $5.0 million of overhead costs, including higher salaries, stock-based compensation,
incentive compensation and rent.
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Production and Ad Valorem Taxes
Production and ad valorem tax expense for 2008 increased slightly as compared to 2007.
Production and ad valorem taxes increased $11.2 million due to the development of our Fort Worth
Basin properties and increased production. This increase was nearly offset by the absence of
production and ad valorem taxes associated with the divested Northeast Operations. We have
historically experienced low severance tax expense for our Texas production as a result of
exemptions and rate reductions for development of our acreage positions with wells deemed by the
taxing authorities to be “high cost wells.” We expect severance tax rates in Texas to increase in
future quarters as fewer of our wells to be drilled in 2009 and beyond will qualify for severance
tax exemptions and rate reductions because we expect our Fort Worth Basin drilling and completion
costs to continue to decrease while the cost threshold for exemptions and rate reductions will
increase.
Production and ad valorem tax expense for 2007 was relatively flat when compared to 2006 as a
$2.1 million increase in ad valorem tax expense was mostly offset by a decrease in production
taxes. Ad valorem tax expense increased primarily as a result of the growth in our Texas and
Canadian property values associated with our 2007 capital expenditure program while production tax
expense decreased as a result of a higher percentage of our production in Texas that is partially
or fully exempted from production taxes.
Depletion, Depreciation and Accretion
Higher depletion expense for 2008 resulted from a 31% increase in the depletion rate and a 23%
increase in production volumes. Our 2008 depletion rate was impacted by the addition of the proved
oil and gas properties obtained in the Alliance Acquisition as well as the capital costs incurred
for proved reserves added from our existing properties and increases in estimated future capital
expenditures. Depreciation expense for 2008 was $10.4 million higher than 2007 primarily due to
additions of Fort Worth Basin field compression and KGS midstream infrastructure, partially offset
by the absence of $4.1 million of depreciation expense associated with the divested Northeast
Operations depreciable assets. We expect depreciation expense will further increase when KGS places
its $110 million Corvette Plant into service in the first quarter of 2009 and we expect that
depletion for our U.S. properties will be approximately $1.80 per Mcfe after the impairment
recognized in the fourth quarter of 2008.
Depletion expense in 2007 increased from 2006 primarily as a result of a 27% increase in
production. Our 2007 consolidated depletion rate increased $0.21 per Mcfe as a result of increased
future development costs due in part to a higher percentage of undeveloped proved reserves for 2007
year-end as compared to 2006, and higher finding costs in 2007 in Texas. Depreciation expense for
2007 was $7.7 million higher than 2006 primarily resulting from increased capacity at our Cowtown
Gas Plant, additions to our Cowtown Pipeline and new Canadian gas processing facilities.
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Impairment of Oil and Gas Properties
We recognized a noncash pretax charge of $633.5 million ($411.8 million after tax) for
impairment related to our U.S. oil and gas properties in December 2008. As required under full cost
accounting rules, we performed a ceiling test by comparing the book value of our oil and gas
properties, net of related deferred tax liability and asset retirement obligations, to the year-end
ceiling limitation, which is the after-tax value of the future net cash flows from proved oil and
gas reserves, including the effect of hedges. As also required under full cost accounting rules
prescribed by the SEC, the ceiling amount was based upon year-end prices and costs, discounted at
10% per year. Under these rules, management has little ability to influence the ceiling amounts
with respect to such factors as pricing, discount rate, cost structure and timing. Consequently,
the ceiling amount is not necessarily indicative of the fair value of our oil and gas properties,
which could have a wide range of potential fair values. Included below is an alternate valuation of
our oil and gas reserves that supplements the ceiling amount and which management believes is more
indicative of our oil and gas properties’ fair value as it incorporates the valuation techniques we
employ in making investment decisions. The alternate value presented below would have, if permitted
in place of the ceiling amount, eliminated any recognition of impairment during 2008. This
valuation was calculated in the same manner as the scenario used in the ceiling test, except for
the following changes:
Management’s alternate pretax valuation related to its proved oil and gas reserves at December 31,
2008 as described above was as follows:
General and Administrative Expense
We recognized a charge of $9.6 million in 2008 as a result of the settlement of litigation as
discussed in Note 17 to our consolidated financial statements in Item 8 of this Report. The
most significant increase in recurring general and administrative expense for 2008 was a $14.4
million increase in employee compensation and benefits, including increases of $4.2 million of
non-cash expense for vesting of stock-based compensation and $1.3 million in performance-based
compensation. The remaining $8.9 million increase in employee compensation is related to additional
headcount which was necessary to bring our infrastructure to a level needed to accommodate growth
in our operations and production. After consideration of the BreitBurn Transaction investment
banking fees of $2.0 million recognized in 2007, fees for legal, accounting and other professional
services increased general and administrative expense by approximately $2.8 million, which resulted
from additional regulatory filing requirements, litigation costs, expenses associated with
evaluation of complex business transactions and the full year effect of KGS being a publicly-traded
partnership.
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General and administrative expense for 2007 increased due to a $4.1 million increase in
stock-based compensation and $1.9 million in performance-based compensation. These increases relate
to increased headcount at our corporate offices to develop additional capabilities necessary to
support our growth. General and administrative costs increased year over year by $4.1 million for
legal and professional fees which relate to professional services provided for the KGS IPO and our
Northeast Operations divestiture.
Other Components of Operating Income
During 2007, we recognized a gain of $628.7 million as a result of our divestiture of the
Northeast Operations, and we recorded a loss on the Michigan Sales Contract related to delivery of
volumes in Michigan. Further information regarding these transactions is included in Item 8
of this Report.
BreitBurn-Related Income and Expenses
During 2008, we recognized $93.3 million associated with the equity earnings in our investment
in BBEP for the period from November 1, 2007, when we acquired the BBEP units, through September
30, 2008. This amount reflects our prevailing ownership interests for the applicable period before
and after our ownership increased from 32% to 41% by virtue of BBEP’s purchase and retirement of
units during 2008. BBEP has experienced significant volatility in their net earnings due to changes
in value of their derivative instruments, for which they do not employ hedge accounting.
During the fourth quarter of 2008, the Company considered the fair value of the BBEP units
along with the fair value trend of its peers, the trend and future petroleum strip prices and the
limited availability of credit which occurred in the latter half of 2008. Based on these factors,
the Company determined that the decrease in fair value of BBEP units was other-than-temporary and
recorded a pretax charge of $320.4 million to reduce the carrying value of our investment in BBEP
to its fair value. Management believes that certain alternative fair value measures, such as BBEP’s
liquidation value, the estimated value of its properties and reserves, the present value of
existing distribution levels and other calculations would have eliminated or materially lowered the
impairment charge. However, the prescriptive nature of the relevant GAAP requires the Company to
ignore these alternative measures based upon availability of Level 1 inputs as described in SFAS
No. 157.
Interest Expense
Interest costs for 2008 were higher than 2007 primarily because of higher average debt
outstanding due to the issuance of our Senior Notes and our Senior Secured Second Lien Facility due
in 2013, partially offset by a decrease in our average consolidated interest rate. The higher debt
levels in 2008 relate to the Alliance Acquisition and the funding of our 2008 capital program. The
increase in capitalized interest relates to more projects and costs within those projects being
subject to capitalization. Interest was capitalized in 2008 for our exploration projects in the
Horn River Basin and West Texas and construction of the Corvette Plant by KGS.
For 2007, interest expense increased $26.9 million from 2006 primarily as a result of both
higher debt balances and higher prevailing rates on the variable portion of our debt. The increases
in 2007 debt balances primarily relate to the drilling and midstream expansion programs undertaken
in 2007, but were partially offset by our debt reductions in November, funded by proceeds from our
Northeast Operations’ divestiture.
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Income Taxes
The 2008 provision for income taxes changed dramatically from 2007 due to the loss generated
by U.S. operations for 2008. Pretax results for 2008 compared with 2007 were most significantly
influenced by the impairment charges recognized on U.S. oil and gas properties and on our
investment in BBEP. Also, 2007 results included the gain resulting from our divestiture of our
Northeast Operations. Higher Canadian pretax income and the absence of tax credits received in 2007
increased the provision for income taxes in Canada by $11.1 million. In 2008, the effective rate
exceeds the statutory rate of 35% due to the benefit of lower taxes in Canada partially offset by
impact of permanent differences for executive compensation and meals and entertainment.
Income tax expense for 2007 was $254.4 million which yielded the effective rate of 34.8%. The
620 basis point increase in the effective rate is principally due to taxes on the gain associated
with the divestiture of our Northeast Operations at the U.S. statutory rate, which is higher than
the comparable Canadian rate. Thus our taxable income was more
heavily weighted toward the U.S. in
2007 compared with 2006. Also, the recognition in 2007 of tax expenses pursuant to FIN 48 and a
decrease in the tax credits generated by our Canadian operations increased the effective rate,
offset in part by a reduction for the effect of a future tax rate reduction in Canada. Our U.S.
income tax expense of approximately 35.5% was established using the statutory U.S. federal rate of
35% plus the effects of the Texas margin tax that was enacted in May 2006. Our Canadian tax expense
was established using the combined federal and provincial rate of 29% and the effects of tax rate
reductions that were enacted in 2007.
Quicksilver
Resources Inc. and its Restricted Subsidiaries
The indentures under both the Company’s Senior Notes and the Company’s Senior Subordinated
Notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries. The Company’s
unrestricted subsidiaries consist of:
All of the Company’s other subsidiaries are restricted subsidiaries (collectively, the “Restricted
Subsidiaries”). The Company and its Restricted Subsidiaries
conduct all of the Company’s exploration and
production activities, and the “unrestricted subsidiaries” only conduct midstream
operations.
The combined results of operations for the Company and its restricted subsidiaries are
substantially similar to the Company’s consolidated results of operations, which are
discussed above under “Results of Operations.” The combined financial position
of the Company and its restricted subsidiaries and the Company’s consolidated financial
position are materially the same except for the property, plant and equipment purchased by
the unrestricted subsidiaries since the KGS IPO, the borrowings under the KGS credit
facility and the equity of the unrestricted subsidiaries. The other balance sheet items
are discussed below in “Financial Position.” The combined operating cash flows,
financing cash flows and investing cash flows for the Company and its restricted subsidiaries
are substantially similar to the Company’s consolidated operating cash flows, financing
cash flows and investing cash flows, which are discussed below in “Liquidity, Capital
Resources and Financial Position.” Further information regarding the Company, its
restricted subsidiaries and its unrestricted subsidiaries is included in Item 8 of this Report.
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LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Cash Flow Activity
Operating Cash Flows
Cash flows provided by operating activities in 2008 were $456.6 million, an increase of $137.5
million or 43% from 2007. The increase in operating cash flows results from a 23% production
increase and a 16% increase in realized price per Mcfe. Payments of $46.6 million for income taxes
and other uses of working capital partially offset the increase in
net income.
Cash flows provided by operating activities in 2007 were $319.1 million, an increase of $76.9
million or 32% from 2006. The cash flows increased due to a 27% production increase, an 11%
realized price increase and higher cash flows provided by working capital.
Investing Cash Flows
For each of the three years ended December 31, 2008, we have spent significant cash resources
for the development of our large acreage positions in our core areas in the Fort Worth Basin and
the CBM properties in Alberta. In addition, our expenditures for gas processing and gathering
assets have grown significantly as part of our growth in the Barnett Shale. In 2008 and 2007, our
investing cash flows included the $1.0 billion cash portion of the Alliance Acquisition and net
cash proceeds of $741.1 million from the divestiture of our Northeast Operations, respectively. Of
the $2.3 billion of cash paid for property, plant and equipment during 2008, 88% was invested in
our oil and natural gas properties and 12% was invested in our gas processing and gathering
operations.
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Our 2008 purchases of property, plant and equipment reflect our expansion in our two core
operating areas, the Fort Worth Basin and the Western Canadian Sedimentary Basin in Alberta. In
2008, we purchased approximately 90 producing wells in the Alliance Acquisition and drilled 296
(259.7 net) wells in the Fort Worth Basin and 373 (156.9 net) wells in Canada. Additionally, the
assets purchased in the Alliance Acquisition included a gathering system and we invested $230.4
million and $4.3 million for Fort Worth Basin and Canadian gas processing and gathering facilities,
respectively.
Capital costs incurred for development, exploitation and exploration activities in 2007 were
$852.5 million, primarily for expansion in our two core operating areas. In 2007, we drilled 244
(219.4 net) wells in the Fort Worth Basin and an additional 356 (184.1 net) wells in Canada.
Additionally, we invested $168.5 million and $3.4 million for Fort Worth Basin and Canadian gas
processing and gathering facilities, respectively.
Capital costs incurred for development, exploitation and exploration activities in 2006 were
$544.7 million. Those expenditures also reflect our two core operating areas. In 2006, we drilled
123 (111.3 net) wells in the Fort Worth Basin and an additional 400 (215.2 net) wells in Canada.
Additionally, we invested $82.3 million and $7.6 million for Fort Worth Basin and Canadian gas
processing and gathering facilities, respectively.
We currently estimate that our spending for property, plant and equipment in 2009 will be
approximately $600 million, of which we have allocated $400 million for drilling activities, $155
million for gathering and processing facilities (including $35 million to be funded directly by
KGS), $40 million for acquisition of additional leasehold interest and $5 million for other
property and equipment.
Financing Cash Flows
Net cash flows from financing activities during 2008 were significantly impacted by the
Alliance Acquisition and our 2008 capital program. We funded our capital program in excess of
operating cash flow through the issuance of our Senior Notes and additional borrowing under our
Senior Secured Credit Facility. The Alliance Acquisition was funded by a $700 million five-year
Senior Secured Second Lien Facility and additional borrowing under our Senior Secured Credit
Facility.
Net cash flows from financing activities during 2007 were significantly impacted by the KGS
IPO and the divestiture of our Northeast Operations. The KGS IPO resulted in cash proceeds of $110
million primarily used to repay debt. The divestiture of our Northeast Operations generated net
cash proceeds of $741.1 million included in investing activities, however those proceeds were used
to pay down debt previously outstanding which affected financing cash flows.
Liquidity and Borrowing Capacity
On February 9, 2007, we extended our Senior Secured Credit Facility to February 9, 2012. The
facility provides for revolving loans, swingline loans and letters of credit from time to time in
an aggregate amount not to exceed the borrowing base which is calculated based on several factors.
As of December 31, 2008, the borrowing base was equal to $1.2 billion, and is subject to annual
redeterminations and certain other redeterminations. The lenders agreed to provide $1.2 billion of
revolving credit commitments and the Company has an option to increase the facility to $1.45
billion. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds,
with U.S. currency available for borrowing by the Company and either U.S. or Canadian currency
available for borrowing in Canada. The facility offers the option to extend the maturity up to two
additional years with lender approval. U.S. borrowings under the facility are secured by, among
other things, Quicksilver’s and its domestic subsidiaries’ oil and gas properties including
applicable reserves. Canadian borrowings under the facility are secured by, among other things, all
of our oil and gas properties including applicable reserves. The Company also pledged the equity
interests in BBEP it received as part of the BreitBurn Transaction to secure its obligations under
the Senior Secured Credit Facility.
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The credit facility contain covenants that are more fully described in Note 14 to the
consolidated financial statements in Item 8 of this Report. At December 31, 2008,
approximately $369 million was available for borrowing under our Senior Secured Credit Facility and
we were in compliance with all covenants. As of January 31, 2009, we had borrowed an additional
$130 million under the credit facility. Our ability to remain in compliance with the financial
covenants in our credit facility may be affected by events beyond our control, including market
prices for our products. Any future inability to comply with these covenants, unless waived by the
requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further
under our credit facilities and by accelerating the maturity of our indebtedness.
In connection with the KGS IPO, KGS entered into a five-year $150 million senior secured
revolving credit facility (“KGS Credit Agreement”). In October 2008, the lenders increased the
facility to $235 million. Additionally, the revised KGS Credit Agreement features an accordion
option of $115 million that allows for the facility to increase to $350 million upon lender
approval. KGS must maintain certain financial ratios that can limit its borrowing capacity. The KGS
Credit Agreement contains covenants that are more fully described in Note 14 to the consolidated
financial statements in Item 8 of this Report. At December 31, 2008, KGS’ borrowing capacity
was $235 million, and KGS had $175 million in borrowings outstanding under the KGS Credit
Agreement. KGS was in compliance with all covenants as of December 31, 2008. KGS’s ability to
remain in compliance with the financial covenants in its credit facility may be affected by events
beyond our control. Any future inability to comply with these covenants, unless waived by the
requisite lenders, could adversely affect our liquidity by rendering KGS unable to borrow further
under its credit facility and by accelerating the maturity of its indebtedness.
As of December 31, 2008, 2007 and 2006, our total capitalization was as follows:
We believe that our capital resources are adequate to meet the requirements of our existing
business. We anticipate that our 2009 capital expenditure budget of approximately $600 million will
be funded by cash flow from operations, including application of anticipated income tax refunds and
cash distributions received from BBEP. We may, from time to time during 2009, make borrowings under
the credit facility, but expect that for all of 2009 to require no incremental borrowings from
ending 2008 levels.
Depending upon conditions in the capital markets and other factors, we will from time to time
consider the issuance of debt or other securities, other possible capital markets transactions or
the sale of assets, the proceeds of which could be used to refinance current indebtedness or for
other corporate purposes. We will also consider from time to time additional acquisitions of, and
investments in, assets or businesses that complement our existing asset portfolio. Acquisition
transactions, if any, are expected to be financed through cash on hand and from operations, bank
borrowings, the issuance of debt or other securities or a combination of those sources.
Financial Position
The following impacted our balance sheet as of December 31, 2008, as compared to our balance
sheet as of December 31, 2007:
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Contractual Obligations and Commercial Commitments
Contractual Obligations. Information regarding our contractual and scheduled interest
obligations, at December 31, 2008, is set forth in the following table.
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Commercial Commitments. We had the following commercial commitments as of December 31, 2008:
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CRITICAL ACCOUNTING ESTIMATES
Our consolidated financial statements are prepared in accordance with GAAP. In connection with
the preparation of our financial statements, we are required to make assumptions and estimates
about future events, and apply judgments that affect the reported amounts of assets, liabilities,
revenue, expenses and the related disclosures. We base our assumptions, estimates and judgments on
historical experience, current trends and other factors that management believes to be relevant at
the time we prepare our consolidated financial statements. On a regular basis, management reviews
the accounting policies, assumptions, estimates and judgments to ensure that our financial
statements are presented fairly and in accordance with GAAP. However, because future events and
their effects cannot be determined with certainty, actual results could differ materially from our
assumptions and estimates.
Our significant accounting policies are discussed in Item 8 of this Report. Management believes that the following
accounting estimates are the most critical in fully understanding and evaluating our reported
financial results, and they require management’s most difficult, subjective or complex judgments,
resulting from the need to make estimates about the effect of matters that are inherently
uncertain. Management has reviewed these critical accounting estimates and related disclosures with
our Audit Committee.
Full Cost Ceiling Calculations
Policy Description
We use the full cost method to account for our oil and gas properties. Under the full cost
method, all costs associated with the development, exploration and acquisition of oil and gas
properties are capitalized and accumulated in cost centers on a country-by-country basis. This
includes any internal costs that are directly related to development and exploration activities,
but does not include any costs related to production, general corporate overhead or similar
activities. Proceeds received from disposals are credited against accumulated cost except when the
sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The
application of the full cost method generally results in higher capitalized costs and higher
depletion rates compared to its alternative, the successful efforts method. The sum of net
capitalized costs and estimated future development and dismantlement costs for each cost center is
depleted on the equivalent unit-of-production basis using estimated proved oil and gas reserves.
Excluded from amounts subject to depletion are costs associated with unevaluated properties.
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost
reduced by the related net deferred tax liability and asset retirement obligations or the cost
center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue,
discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs,
adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas
revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii)
the lower of cost or market value of unproved properties included in the cost being amortized less
(iv) income tax effects related to differences between the book and tax bases of the oil and gas
properties. If the net book value reduced by the related net deferred income tax liability and
asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment
charge is required.
Judgments and Assumptions
The discounted present value of future net revenue for our proved oil, natural gas and NGL
reserves is a major component of the ceiling calculation, and represents the component that
requires the most subjective judgments. Estimates of reserves are forecasts based on engineering
data, projected future rates of production and the timing of future expenditures. The process of
reserve estimation requires substantial judgment, resulting in imprecise determinations,
particularly for new discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data.
The passage of time provides more qualitative information regarding estimates of reserves, and
revisions are made to prior estimates to reflect updated information. In the past five years,
annual revisions to our reserve estimates, which have been both increases and decreases in
individual years, have averaged approximately 1% of the previous year’s estimate (excluding
revisions due to price changes). However, there can be no assurance that more significant revisions
will not be necessary in the future. If future significant revisions are necessary that reduce
previously estimated reserve quantities, it could result in a ceiling test-related impairment. In
addition to the impact of the estimates of proved reserves on the calculation of the ceiling
limitation, estimation of proved reserves is also a significant component of the calculation of
depletion expense.
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While the quantities of proved reserves require substantial judgment, the associated prices of
natural gas, NGL and crude oil reserves, and the applicable discount rate, that are used to
calculate the discounted present value of the reserves do not require judgment. The ceiling
calculation requires that a 10% discount factor be used and that prices and costs in effect as of
the last day of the period are held constant indefinitely. Therefore, the future net revenue
associated with the estimated proved reserves is not based on our assessment of future prices or
costs. Rather, they are based on such prices and costs in effect as of the end of each period when
the ceiling calculation is performed. In calculating the ceiling, we adjust the period-end price by
the effect of derivative contracts in place that hedge future prices. This adjustment requires
little judgment as the period-end price is adjusted using the contract prices for such hedges.
Because the ceiling calculation dictates that prices in effect as of the last day of the
applicable year are held constant indefinitely, and requires a 10% discount factor, the resulting
value is not necessarily indicative of the fair value of the reserves or the oil and gas
properties. Oil and natural gas prices have historically been volatile. At any period end, prices
can be either substantially higher or lower than our long-term price forecast. Also, marginal
borrowing rates may be well below the required 10% used in the calculation. Rates below 10%, if
they could be utilized, would have the effect of increasing the otherwise calculated ceiling
amount. Therefore, oil and gas property ceiling test-related impairments that result from applying
the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to
reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of
a reduction of the ultimate value of the related reserves.
Oil and Gas Reserves
Policy Description
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs
that geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions. Prices include
consideration of changes in existing prices provided only by contractual arrangements, which do not
include financial derivatives that hedge our oil and gas revenue. Our estimates of proved reserves
are made and reassessed at least annually using available geological and reservoir data as well as
production performance data. Revisions may result from changes in, among other things, reservoir
performance, prices, economic conditions and governmental restrictions.
Judgments and Assumptions
All of the reserve data in this annual report are based on estimates. Estimates of our crude
oil, natural gas and NGL reserves are prepared in accordance with guidelines established by the
SEC. Reservoir engineering is a subjective process of estimating underground accumulations of crude
oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of
proved crude oil and natural gas reserves. Uncertainties include the projection of future
production rates and the expected timing of development expenditures. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, reserve estimates may be different from the quantities of
crude oil, natural gas and NGLs that are ultimately recovered. Estimates of proved crude oil,
natural gas and NGL reserves significantly affect our depletion expense. For example, if estimates
of proved reserves decline, the depletion rate will increase, resulting in a decrease in net
income.
Derivative Instruments
Policy Description
We enter into financial derivative instruments to mitigate risk associated with the prices
received from our production. We may also utilize financial derivative instruments to hedge the
risk associated with interest rates on our outstanding debt. We account for our derivative
instruments by recognizing qualifying derivative instruments on our balance sheet as either assets
or liabilities measured at their fair value determined by reference to published future market
prices and interest rates. For derivative instruments that qualify as cash flow hedges, the
effective portions of gains or losses are deferred in other comprehensive income and recognized in
earnings during the period in which the hedged transactions are realized. Gains or losses on
qualified derivative instruments terminated prior to their original expiration date are deferred
and recognized as income or expense in the period in which the hedged transaction is recognized. If
the hedged transaction becomes probable of not occurring, the deferred gain or loss would be
immediately recorded to earnings. The ineffective portion of the hedge relationship is recognized
currently as a component of other revenue.
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The fair value of our natural gas derivatives and associated firm sales commitments as of
December 31, 2008 was estimated based on published market prices of natural gas for the periods
covered by the contracts. Estimates were determined by applying the net differential between the
prices in each derivative and commitment and market prices for future periods, to the volumes
stipulated in each contract to arrive at an estimated value of future cash flow streams. These
estimated future cash flow values were then discounted for each contract at rates commensurate with
federal treasury instruments with similar contractual lives to arrive at estimated fair value.
Judgments and Assumptions
The estimates of the fair values of our commodity derivative instruments require substantial
judgment. Valuations are based upon multiple factors such as futures prices, volatility data from
major oil and gas trading points, time to maturity and interest rates. We compare our estimates of
fair value for these instruments with valuations obtained from independent third parties and
counterparty valuation confirmations. The values we report in our financial statements change as
these estimates are revised to reflect actual results.
Stock-based Compensation
Policy Description
SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R) requires the measurement and
recognition of compensation expense for all share-based payment awards made to employees and
directors based on estimated fair value.
Judgments and Assumptions
Option-pricing models and generally accepted valuation techniques require management to make
assumptions and to apply judgment to determine the fair value of our awards. These assumptions and
judgments include estimating the future volatility of our stock price, expected dividend yield,
future employee turnover rates and future employee stock option exercise behaviors. Changes in
these assumptions can materially affect the fair value estimate.
We do not believe there is a reasonable likelihood that there will be a material change in the
future estimates or assumptions that we use to determine stock-based compensation expense. However,
if actual results are not consistent with our estimates or assumptions, we may be exposed to
changes in stock-based compensation expense that could be material. If actual results are not
consistent with the assumptions used, the stock-based compensation expense reported in our
financial statements may not be representative of the actual economic cost of the stock-based
compensation.
Income Taxes
Policy Description
Deferred income taxes are established for all temporary differences between the book and the
tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect
tax rates that we expect will be in effect during years in which we expect the temporary
differences will reverse. Canadian taxes are computed at rates in effect in Canada. U.S. deferred
tax liabilities are not recognized on profits that are expected to be permanently reinvested in
Canada and thus are not considered available for distribution to us. Net operating loss carry
forwards and other deferred tax assets are reviewed annually for recoverability, and if necessary,
are recorded net of a valuation allowance.
Judgments and Assumptions
We must assess the likelihood that deferred tax assets will be recovered from future taxable
income and provide judgment on the amount of financial statement benefit that an uncertain tax
position will realize upon ultimate settlement. To the extent that we believe that a more than 50%
probability exists that some portion or all of the deferred tax assets will not be realized, we
must establish a valuation allowance. Significant management judgment is required in determining
any valuation allowance recorded against deferred tax assets and in determining the amount of
financial statement benefit to record for uncertain tax positions. We consider all available
evidence, both positive and negative, to determine whether, based on the weight of the evidence, a
valuation allowance is needed and consider the amounts and probabilities of the outcomes that could
be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances
and information available at the reporting date to establish the appropriate amount of financial
statement benefit. Evidence used for the valuation allowance includes information about our current
financial position and results of operations
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for the current and preceding years, as well as all currently available information about
future years, including our anticipated future performance, the reversal of deferred tax assets and
liabilities and tax planning strategies available to the Company. To the extent that a valuation
allowance or uncertain tax position is established or changed during any period, we would recognize
expense or benefit within our consolidated tax expense.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC
Regulation S-K.
RECENTLY ISSUED ACCOUNTING STANDARDS
Adoption of SFAS No. 157 — SFAS No. 157, Fair Value Measurements, was issued by the FASB in
September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value
under GAAP and expands disclosures about fair value measurements. The Statement applies under other
accounting pronouncements that require or permit fair value measurement. No new requirements are
included in SFAS No. 157, but application of the Statement has changed current practice. On
February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the
effective date of SFAS No. 157 for non-financial assets and liabilities. The delay allows companies
additional time to consider the effect of various implementation issues that have arisen, or that
may arise, from the application of SFAS No. 157. FSP FAS 157-3 was issued by the FASB on October
10, 2008 to clarify application of SFAS No. 157 when determining the fair value of a financial
asset when the market for that financial asset is not active. The Company adopted SFAS No. 157 on
January 1, 2008 for new fair value measurements of financial instruments, including its derivative
instruments, and recurring fair value measurements of non-financial assets and liabilities. All
financial instruments are measured using inputs from three levels of fair value hierarchy. The
three levels are as follows:
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or
liabilities that we have the ability to access at the measurement date.
Level 2 inputs include quoted prices for similar assets and liabilities in active markets,
quoted prices for identical or similar assets or liabilities in markets that are not active,
inputs other than quoted prices that are observable for the asset or liability and inputs
that are derived principally from or corroborated by observable market data by correlation or
other means (market corroborated inputs).
Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the
assumptions that market participants would use in pricing an asset or liability.
Adoption of SFAS No. 159 — In February 2007, the FASB issued SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement
No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain
other items at fair value that are not currently required to be measured at fair value. While SFAS
No. 159 became effective on January 1, 2008, the Company did not elect the fair value measurement
option for any of its financial assets or liabilities.
Adoption of FSP No. 39-1 — On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No.
39-1, Amendment of FASB Interpretation No. 39. The FSP amends GAAP to replace the terms
“conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined
in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. It also amends
paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts
recognized for derivative instruments
executed with the same counterparty under the same master netting arrangement. The Company
adopted FSP No. 39-1 on January 1, 2008 without significant impact.
Adoption of SFAS No. 162 — In May 2008, the FASB issued SFAS No. 162, The Hierarchy of
Generally Accepted Accounting Principles, which identifies the sources of accounting principles and
the framework for selecting the principles used in the preparation of financial statements in
conformity with GAAP in the United States. This Statement is generally viewed as a necessary step
in the ultimate convergence of global accounting rules. This Statement became effective on November
15, 2008, but had no impact on the Company’s financial statements or related disclosures.
On January 1, 2009, the Company also adopted FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1 as
more fully discussed previously.
SFAS No. 141 (revised 2007), Business Combinations, “SFAS No. 141(R)” was issued in December
2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, while retaining its fundamental
requirements that the acquisition method of accounting be used for all business combinations and
for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the
acquirer as the entity that obtains control in the business combination and it establishes the
criteria to determine the acquisition date. SFAS No. 141(R) applies to all transactions and events
in which one entity obtains control over one or more other businesses. The Statement also requires
an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values
as of the acquisition date. In addition, acquisition costs are required to be recognized as period
expenses as incurred. The Statement will apply to any acquisition entered into after January 1,
2009, but otherwise had no effect on our financial statements upon adoption.
The FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities,
in March 2008. Under SFAS No. 161, the Company will be required to disclose the fair value of all
derivative and hedging instruments and their gains or losses in tabular format and information
about credit risk-related features in derivative agreements, counterparty credit risk, and its
strategies and objectives for using derivative instruments. SFAS No. 161 was adopted with
prospective application by the Company on January 1, 2009. The adoption of SFAS No. 161 will change
the Company’s disclosures about its derivative and hedging instruments, but had no impact on the
Company’s previously reported results or financial position.
The SEC adopted revisions to its required oil and gas reporting disclosures in December 2008.
The revisions impacting the Company include: 1) use of 12-month average of the
first-day-of-the-month prices for determination of proved reserve values including in calculating
full cost ceiling limitations; 2) limitations on the types of technologies that may be relied upon
to establish the levels of certainty required to classify reserves; and 3) ability to disclose
“probable” and “possible” reserves as defined by the SEC. The SEC also updated the required
disclosure requirements and eliminated use of price recoveries subsequent to period end for use in
the ceiling test. The Company will adopt these changes within the 2009 Annual Report on Form 10-K
to be filed in 2010. The Company is still reviewing the implications of these revisions.
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Item 8. Financial Statements and Supplementary Data
QUICKSILVER RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc. Fort Worth, Texas We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and
subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated
statements of income (loss) and comprehensive income (loss), stockholders’ equity and cash flows
for each of the three years in the period ended December 31, 2008. These financial statements are
the responsibility of the Company’s management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Quicksilver Resources Inc. and subsidiaries as of December 31, 2008 and
2007, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2008, in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Notes 14 and 21 to the consolidated financial statements, the accompanying 2008
financial statements have been restated.
As discussed in Note 2 to the consolidated financial statements, the accompanying consolidated
financial statements have been adjusted for the retrospective application of Statement of Financial
Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements – an
Amendment to ARB 51 (“SFAS 160”), FASB Staff Position APB 14-1: Accounting for Convertible Debt
Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“FSP
APB 14-1”), and FASB Staff Position EITF 03-6-1: Determining Whether Instruments Granted in
Share-Based Payment Transactions are Participating Securities (“FSP EITF 03-6-1”), all of which
were adopted by the Company on January 1, 2009.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the Company’s internal control over financial reporting as of December 31,
2008, based on the criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009
(June 16, 2009 as to the effects of the material weaknesses discussed in Management’s Report on
Internal Control Over Financial Reporting, as revised) expressed an adverse opinion on the
Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
March 2, 2009 (June 16, 2009 as to the effects of the restatement as discussed in Notes 14 and 21, and as to the effects of the adoption of SFAS 160, FSP APB 14-1, and FSP EITF 03-6-1, and the related disclosures in Notes 2, 4, 12, 14, 16, 18 and 21)
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QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 In thousands, except for per share data
The accompanying notes are an integral part of these consolidated financial statements.
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QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2008 AND 2007 In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.
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QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.
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QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS END DECEMBER 31, 2008, 2007 AND 2006 In thousands
The accompanying notes are an integral part of these consolidated financial statements.
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QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006 1. NATURE OF OPERATIONS
Quicksilver Resources Inc. (“Quicksilver” or the “Company”) is an independent oil and gas
company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. Quicksilver
engages in the development, exploitation, exploration, acquisition, production and sale of natural
gas, NGLs and crude oil as well as the marketing, processing and transmission of natural gas. As of
December 31, 2008, substantial portions of Quicksilver’s oil and gas reserves and operations are
located in Texas, the U.S. Rocky Mountains and Alberta, Canada. The Company has offices located in
Fort Worth, Texas, Cut Bank, Montana, Glen Rose, Texas and in Calgary, Alberta. Until the Company
completed the BreitBurn Transaction in 2007 (see Note 5), the Company also had significant oil and
gas reserves and operations in Michigan, Indiana and Kentucky.
Quicksilver’s results of operations are largely dependent on the difference between the prices
received for its natural gas, NGL and crude oil products and the cost to find, develop, produce and
market such resources. Natural gas, NGL and crude oil prices are subject to fluctuations in
response to changes in supply, market uncertainty and a variety of other factors beyond
Quicksilver’s control. These factors include worldwide political instability, quantities of natural
gas in storage, foreign supply of natural gas and crude oil, the price of foreign imports, the
level of consumer demand and the price of available alternative fuels. Quicksilver actively manages
a portion of the financial risk relating to natural gas, NGL and crude oil price volatility through
derivative contracts.
2. ADJUSTMENTS AND SIGNIFICANT ACCOUNTING POLICIES
Adjustment for Retrospective Application of
FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1
We have adjusted the financial statements and notes thereto for the years ended December 31,
2008, 2007 and 2006 to reflect our adoption of FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1.
FSP APB 14-1, Accounting for Convertible Debt Instruments That May be Settled in Cash upon
Conversion
FSP APB 14-1 requires issuers to account separately for the liability and equity components of
certain convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt
borrowing rate when interest expense is recognized. FSP APB 14-1 requires bifurcation of the debt
and equity components of convertible debt. It also requires recognition of interest cost at an
issuer’s effective interest rate instead of the stated or coupon rate. The Company adopted FSP APB
14-1 January 1, 2009, which also requires retrospective application to the terms of the Company’s
instruments as they existed for all periods presented. The adoption of FSP APB 14-1 affects the
accounting for the Company’s Convertible Debentures issued in 2004 and due 2024. The retrospective
application of this pronouncement affects each of the years included
in these consolidated financial statements and earlier periods and generally results in lower
net earnings by virtue of higher interest expense.
SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements. SFAS No. 160 amends ARB No. 51 to establish accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary, formerly referred to as
minority interest, is an ownership interest in the consolidated entity that should be reported as
equity. Among other requirements, SFAS No. 160 requires consolidated net income to include the
amounts attributable to both the parent and the noncontrolling interest. It also requires
disclosure of the amounts of consolidated net income attributable to the parent and to the
noncontrolling interest on the face of the consolidated income statement. The retrospective
application of this pronouncement affects years 2006 through 2008, but only affects the amounts
reported on the balance sheet and the placement of amounts within the income statement. It has no
effect on the net earnings (loss) or cash flows previously reported.
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FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payments Transactions Are
Participating Securities
Under FSP EITF 03-6-1, unvested share-based payment awards that contain nonforfeitable rights
to dividends (whether paid or unpaid) are participating securities and should be included in the
computation of earnings per share pursuant to the two-class method. The Company’s restricted stock
grants issued as part of employees’ stock-based compensation have been identified as participating
securities and have been included in the basic earnings per share calculation for the periods
contained in this Report. The retrospective application of this
pronouncement affects each of the years
included in these consolidated financial statements and earlier
periods, but only affects earnings per share and has no impact on net earnings (loss), cash
flow or balance sheet amounts as previously reported.
The following table summarizes the effect of the retrospective application of the Adopted
Pronouncements on certain previously reported line items:
Summarized Consolidated Statements of Operations information:
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Consolidated Balance Sheet information:
In addition, the adjustments pursuant to application of the Adopted Pronouncements resulted in
changes to our consolidated statements of cash flows and
stockholders’ equity and Notes 3, 4, 12, 14,
16, 18, 21 and 26.
Significant Accounting Policies
Basis of Presentation
The Company’s consolidated financial statements include the accounts of Quicksilver and all
its majority-owned subsidiaries and companies over which the Company exercises control through
majority voting rights. We eliminate all inter-company balances and transactions in preparing
consolidated financial statements. The Company accounts for its ownership in unincorporated
partnerships and companies, including BBEP, under the equity method as it has significant influence
over those entities, but because of terms of the ownership agreements, Quicksilver does not meet the criteria for control which would trigger
consolidation of the entities. The Company also consolidates its share of oil and gas joint
ventures.
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Stock Split
On January 7, 2008, Quicksilver announced that its Board of Directors declared a two-for-one
stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The
stock dividend was payable on January 31, 2008, to holders of record at the close of business on
January 18, 2008. The split had no effect on shares held in treasury. The capital accounts, all
share data and earnings per share data included in these consolidated financial statements for all
years presented have been adjusted to retroactively reflect the January 2008 stock split.
Use of Estimates
The preparation of financial statements in conformity with GAAP in the U.S. requires
management to make estimates and assumptions that affect the reported amounts of certain assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses, including stock compensation expense,
during each reporting period. Management believes its estimates and assumptions are reasonable;
however, such estimates and assumptions are subject to a number of risks and uncertainties, which
may cause actual results to differ materially from the Company’s estimates. Significant estimates
underlying these financial statements include the estimated quantities of proved natural gas, NGL
and crude oil reserves used to compute depletion expense and future net cash flows from reserve
production, estimates of current revenue based upon expectations for actual deliveries and prices
received, the estimated fair value of financial derivative instruments and the estimated fair value
of asset retirement obligations.
Cash and Cash Equivalents
Cash equivalents consist of time deposits and liquid debt investments with original maturities
of three months or less at the time of purchase.
Accounts Receivable
The Company’s customers are natural gas, NGL and crude oil purchasers. Each customer and/or
counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit
and on a regular basis thereafter. Although the Company does not require collateral, appropriate
credit ratings are required and, in some instances, parental guarantees are obtained. Receivables
are generally due in 30-60 days. When collections of specific amounts due are no longer reasonably
assured, an allowance for doubtful accounts is established. During 2008, two purchasers
individually accounted for 17% and 10% of the Company’s consolidated natural gas, NGL and crude oil
revenue. During 2007 and 2006, one purchaser accounted for approximately 13% and 10%, respectively,
of the Company’s consolidated natural gas, NGL and crude oil revenue.
Hedging and Derivatives
The Company enters into financial derivative instruments to mitigate risk associated with the
prices received from its natural gas, NGL and crude oil production. The Company may also utilize
financial derivative instruments to hedge the risk associated with interest rates on its
outstanding debt. All derivatives are recognized as either an asset or liability on the balance
sheet measured at their fair value determined by reference to published future market prices and
interest rates. For derivatives instruments that qualify as cash flow hedges, the effective
portions of gains and losses are deferred in other comprehensive income and recognized in revenue
or interest expense in the period in which the hedged transaction is recognized. Gains or losses on
derivative instruments terminated prior to their original expiration date are deferred and
recognized as earnings during the period in which the hedged transaction is recognized. If the
hedged transaction becomes probable of not occurring, the deferred gain or loss would be
immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are
recognized currently as a component of other revenue.
Until December 2007, the Michigan Sales Contract, which required delivery of 25 MMcfd of owned
or controlled natural gas at a floor of $2.49 per Mcf through March 2009, had been excluded from
derivatives as it was designated as a normal sales contract under accounting rules. In December
2007 and in connection with the divestiture of the Northeast Operations, the Company decided it
would cease delivering a portion of its natural gas production to supply the contractual volumes.
As the contract no longer qualified under the normal sales exclusion under derivative GAAP, the
Company recognized a loss of $63.5 million at that time.
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Until May 2007, the Company also had another long-term contract (the “CMS Contract”) for
delivery of 10 MMcfd of owned or controlled natural gas at a floor price of $2.47 that was treated
as a normal sales contract under SFAS No. 133. See Note 17 to these financial statements for more
information regarding the CMS Contract.
Parts and Supplies
Parts and supplies consist of well equipment, spare parts and supplies carried on a first-in,
first-out basis at the lower of cost or market.
Investments in Equity Affiliates
Income from equity affiliates is included as a component of operating income when the
operations of the affiliates are associated with processing and transportation of the Company’s
natural gas production.
The Company accounts for it investment in BBEP using the equity method. The Company reviews
its investment for impairment whenever events or circumstances indicate that the investment’s
carrying amount may not be recoverable. The Company records its portion of BBEP’s earnings during
the quarter in which their financial statements become publicly available. Thus, the Company’s 2008
results of operations reflect BBEP’s earnings from November 1, 2007, when the Company acquired the
BBEP units, through September 30, 2008. The Company is not aware of any significant events or
transactions subsequent to September 30, 2008 that will affect BBEP’s results of operations after
that date. See Note 10 for more information on the BBEP investment.
Property, Plant, and Equipment
The Company follows the full cost method in accounting for its oil and gas properties. Under
the full cost method, all costs associated with the acquisition, exploration and development of oil
and gas properties are capitalized and accumulated in cost centers on a country-by-country basis.
This includes any internal costs that are directly related to development and exploration
activities, but does not include any costs related to production, general corporate overhead or
similar activities. Proceeds received from disposals are credited against accumulated cost except
when the sale represents a significant disposal of reserves, in which case a gain or loss is
recognized. The sum of net capitalized costs and estimated future development and dismantlement
costs for each cost center is depleted on the equivalent unit-of-production method, based on proved
oil and gas reserves. Excluded from amounts subject to depletion are costs associated with
unevaluated properties.
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost
reduced by the related net deferred tax liability and asset retirement obligations or the cost
center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue,
discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs,
adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas
revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii)
the lower of cost or market value of unproved properties included in the cost being amortized less
(iv) income tax effects related to differences between the book and tax basis of the natural gas
and crude oil properties. If the net book value reduced by the related net deferred income tax
liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash
impairment charge is required. Note 11 to these financial statements contains further discussion of
the ceiling test.
All other properties and equipment are stated at original cost and depreciated using the
straight-line method based on estimated useful lives ranging from five to forty years.
Revenue Recognition
Revenue is recognized when title to the products transfer to the purchaser. The Company uses
the “sales method” to account for its production revenue, whereby the Company recognizes revenue on
all natural gas, NGL or crude oil sold to its purchasers, regardless of whether the sales are
proportionate to the Company’s ownership in the property. A receivable or liability is recognized
only to the extent that the Company has an imbalance on a specific property greater than the
expected remaining proved reserves. As of December 31, 2008 and 2007, the Company’s aggregate
production imbalances were not material.
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Environmental Compliance and Remediation
Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as
incurred. Environmental remediation costs, which improve the condition of a property, are
capitalized.
Income Taxes
Deferred income taxes are established for all temporary differences between the book and the
tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect
tax rates expected to be in effect in years in which the temporary differences reverse. Canadian
taxes are calculated at rates in effect in Canada. U.S. deferred tax liabilities are not recognized
on profits that are expected to be permanently reinvested in Canada and thus not considered
available for distribution to the parent company. Net operating loss carry forwards and other
deferred tax assets are reviewed annually for recoverability, and if necessary, are recorded net of
a valuation allowance.
Stock-based Compensation
The Company measures and recognizes compensation expense for all share-based payment awards
made to employees and directors based on their estimated fair value. At the discretion of the board
of directors, the Company may issue awards payable in cash. For all awards, the Company recognizes
the expense associated with the awards over the vesting period. The liability for fair value of
cash awards is reassessed at every balance sheet date, such that the vested portion of the
liability is adjusted to reflect revised fair value through compensation expense.
Disclosure of Fair Value of Financial Instruments
The Company’s financial instruments include cash, time deposits, accounts receivable, notes
payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term
debt is estimated at the present value of future cash flows discounted at rates consistent with
comparable maturities for credit risk. The carrying amounts reflected in the balance sheet for
financial assets classified as current assets and the carrying amounts for financial liabilities
classified as current liabilities approximate fair value. SFAS No. 157, Fair Value Measurements,
was adopted on January 1, 2008 and applied to fair value measurements of the Company’s financial
instruments, including its financial derivative instruments. Additional information regarding the
Company’s implementation of the accounting standard is found under “Recently Issued Accounting
Standards” in this Note.
Noncontrolling Interest in Consolidated Subsidiaries
Noncontrolling interest reflects the fractional outside ownership of the Company’s
majority-owned and consolidated subsidiaries. Noncontrolling interest does not necessarily reflect
the fair value of that outside ownership.
Foreign Currency Translation
The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. All
balance sheet accounts of the Canadian operations are translated into U.S. dollars at the
period-end rate of exchange and statement of income items are translated at the weighted average
exchange rates for the period. The resulting translation adjustments are made directly to a
component of accumulated other comprehensive income within stockholders’ equity. Gains and losses
from foreign currency transactions are included in the consolidated statement of income.
Earnings per Share
Basic earnings per common share is computed by dividing the net income attributable to common
stockholders by the weighted average number of shares of common stock outstanding during the
period. Diluted net income or loss per common share is computed using the treasury stock method,
which also considers the impact to net income and common shares for the potential dilution from
stock options, unvested restricted stock and convertible debt.
The following is a reconciliation of the numerator and denominator used for the computation of
basic and diluted net income per common share. Total per share amounts may not add due to rounding.
For the year ended December 31, 2008, all dilutive securities were excluded from the diluted net
loss per share calculation as they were antidilutive. No outstanding options were excluded from the
diluted net income per share calculation for the years ended December 31, 2007 and 2006.
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Recently Issued Accounting Standards
Adoption of SFAS No. 157 — SFAS No. 157, Fair Value Measurements, was issued by the FASB in
September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value
under GAAP and expands disclosures about fair value measurements. The Statement applies under other
accounting pronouncements that require or permit fair value measurement. No new requirements are
included in SFAS No. 157, but application of the Statement has changed current practice. On
February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the
effective date of SFAS No. 157 for non-financial assets and liabilities. The delay allows companies
additional time to consider the effect of various implementation issues that have arisen, or that
may arise, from the application of SFAS No. 157. FSP FAS 157-3 was issued by the FASB on October
10, 2008 to clarify application of SFAS No. 157 when determining the fair value of a financial
asset when the market for that financial asset is not active. The Company adopted SFAS No. 157 on
January 1, 2008 for new fair value measurements of financial instruments, including its derivative
instruments, and recurring fair value measurements of non-financial assets and liabilities. All
financial instruments are measured using inputs from three levels of fair value hierarchy. The
three levels are as follows:
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or
liabilities that we have the ability to access at the measurement date.
Level 2 inputs include quoted prices for similar assets and liabilities in active markets,
quoted prices for identical or similar assets or liabilities in markets that are not active,
inputs other than quoted prices that are observable for the asset or liability and inputs
that are derived principally from or corroborated by observable market data by correlation or
other means (market corroborated inputs).
Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the
assumptions that market participants would use in pricing an asset or liability.
Adoption of SFAS No. 159 — In February 2007, the FASB issued SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement
No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain
other items at fair value that are not currently required to be measured at fair value. While SFAS
No. 159 became effective on January 1, 2008, the Company did not elect the fair value measurement
option for any of its financial assets or liabilities.
Adoption of FSP No. 39-1 — On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No.
39-1, Amendment of FASB Interpretation No. 39. The FSP amends GAAP to replace the terms
“conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined
in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. It also amends
paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts
recognized for derivative instruments
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executed with the same counterparty under the same master netting arrangement. The Company
adopted FSP No. 39-1 on January 1, 2008 without significant impact.
Adoption of SFAS No. 162 — In May 2008, the FASB issued SFAS No. 162, The Hierarchy of
Generally Accepted Accounting Principles, which identifies the sources of accounting principles and
the framework for selecting the principles used in the preparation of financial statements in
conformity with GAAP in the United States. This Statement is generally viewed as a necessary step
in the ultimate convergence of global accounting rules. This Statement became effective on November
15, 2008, but had no impact on the Company’s financial statements or related disclosures.
On January 1, 2009, the Company also adopted FSP APB 14-1, SFAS No. 160 and FSP EITF 03-6-1 as
more fully discussed previously.
SFAS No. 141 (revised 2007), Business Combinations, “SFAS No. 141(R)” was issued in December
2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, while retaining its fundamental
requirements that the acquisition method of accounting be used for all business combinations and
for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the
acquirer as the entity that obtains control in the business combination and it establishes the
criteria to determine the acquisition date. SFAS No. 141(R) applies to all transactions and events
in which one entity obtains control over one or more other businesses. The Statement also requires
an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values
as of the acquisition date. In addition, acquisition costs are required to be recognized as period
expenses as incurred. The Statement will apply to any acquisition entered into after January 1,
2009, but otherwise had no effect on our financial statements upon adoption.
The FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities,
in March 2008. Under SFAS No. 161, the Company will be required to disclose the fair value of all
derivative and hedging instruments and their gains or losses in tabular format and information
about credit risk-related features in derivative agreements, counterparty credit risk, and its
strategies and objectives for using derivative instruments. SFAS No. 161 was adopted with
prospective application by the Company on January 1, 2009. The adoption of SFAS No. 161 will change
the Company’s disclosures about its derivative and hedging instruments, but had no impact on the
Company’s previously reported results or financial position.
The SEC adopted revisions to its required oil and gas reporting disclosures in December 2008.
The revisions impacting the Company include: 1) use of 12-month average of the
first-day-of-the-month prices for determination of proved reserve values including in calculating
full cost ceiling limitations; 2) limitations on the types of technologies that may be relied upon
to establish the levels of certainty required to classify reserves; and 3) ability to disclose
“probable” and “possible” reserves as defined by the SEC. The SEC also updated the required
disclosure requirements and eliminated use of price recoveries subsequent to period end for use in
the ceiling test. The Company will adopt these changes within the 2009 Annual Report on Form 10-K
to be filed in 2010. The Company is still reviewing the implications of these revisions.
3. ALLIANCE ACQUISITION
In August 2008, Quicksilver completed the Alliance Acquisition, under which the Company
acquired leasehold, royalty and midstream assets in the Barnett Shale in northern Tarrant and
southern Denton Counties of Texas. The purchase price which was funded, in part, using $318 million
of borrowings under its existing Senior Secured Credit Facility and proceeds of $674.5 million from
the Senior Secured Second Lien Facility more fully described in Note 14:
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Quicksilver’s preliminary purchase price allocation is presented below:
The preliminary purchase price allocation is based on preliminary estimates of oil and gas
reserves and other valuations and estimates by management and is subject to final closing
adjustments and determination of the valuation of tangible assets related to wells, pipelines and
facilities. The Company expects to finalize the purchase price allocation during the quarter ending
September 30, 2009.
Pro Forma Information
The following table reflects the Company’s unaudited consolidated pro forma statements of
income as though the Alliance Acquisition, associated borrowings and issuance of Company common
stock had occurred on January 1 for each year presented. The revenue and expenses for the
acquisition are included in the Company’s 2008 consolidated results beginning from the date of
closing. The pro forma information is not necessarily indicative of the results of operations that
would have been achieved had the acquisition been effective at January 1 each year presented.
4. QUICKSILVER GAS SERVICES LP
On August 10, 2007, the Company’s majority-owned subsidiary, KGS, completed its underwritten
IPO. KGS, a limited partnership engaged in the business of gathering and processing natural gas
produced from the Barnett Shale formation, sold 5,000,000 common units for $95.0 million, net of
underwriters’ discount and other offering costs. On September 7, 2007, the underwriters of the KGS
IPO exercised their option to purchase an additional 750,000 common units for approximately $14.6
million, net of underwriters’ discount.
Upon completion of the IPO, KGS paid Quicksilver approximately $112.1 million in cash and
issued Quicksilver a subordinated note with a principal amount of $50 million as a return of
investment capital contributed and reimbursement for capital expenditures advanced which eliminated
the Company’s investment in the KGS-predecessor. Due to a portion of the
Company’s common interests in KGS being subordinated, Quicksilver initially deferred recognition
of a gain of approximately $79.3 million related to its post-IPO ownership in KGS.
The gain was originally expected to be recognized in earnings when the subordination period
terminated, however the adoption of SFAS No. 160, as more fully described in Note 2,
caused this amount to reclassified to stockholders’ equity on a retrospective basis for all periods
subsequent to the KGS IPO.
As of December 31, 2008, KGS’ ownership is summarized in the following table:
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The subordinated units will convert into an equal number of common units upon termination of
the subordination period. The subordination period is expected to end in February 2011, assuming
KGS has earned and paid at least $0.30 per quarter on each outstanding common unit through that
time.
The Company includes the results of operations and financial position of KGS in the
consolidated financial statements of Quicksilver, and recognizes the portion of KGS’ results of
operations attributable to unaffiliated unitholders as net income attributable to noncontrolling
interests.
5. DIVESTITURE OF NORTHEAST OPERATIONS
In November 2007, Quicksilver closed on an agreement (the “BreitBurn Transaction”) to
contribute all of its oil and gas properties and facilities in Michigan, Indiana and Kentucky
(collectively the “Northeast Operations”) to BBEP. Total consideration for the BreitBurn
Transaction was $750 million of cash and 21.348 million common units of BBEP, equaling total
consideration of $1.47 billion based on closing market prices on that date. Upon closing, the
Company used $654 million of proceeds from the BreitBurn Transaction to repay all U.S. borrowings
then outstanding under its Senior Secured Credit Facility. Under the terms of the transaction, the
Company must retain 50% of the acquired units until May 1, 2009, but may now freely trade the other
acquired units.
Concurrent with closing the BreitBurn Transaction, the Company agreed to provide certain
one-time benefits to 141 terminated employees, including settling unvested stock-based compensation
in cash and providing cash severance and retention benefits payable in multiple installments over
two years. The Company anticipates the total expense associated with the termination-related
employees benefits to be approximately $10.2 million which was recognized approximately 60% in 2007
and 20% in 2008 plus an expected 20% in 2009. The $6.3 million recognized in oil and gas production
costs in the latter half of 2007 was comprised of expenses to settle unvested stock-based
compensation of $4.9 million and severance payments of $1.4 million associated with services
rendered through the end of 2007 by affected employees. The $2.1 million recognized in 2008 and
amounts to be recognized in 2009 are attributable to the services rendered or expected to be
rendered by the affected employees over these periods and are payable only in the event of their
continued employment by BBEP.
A portion of the Company’s hedging program that was designated to the Northeast Operations for
the period subsequent to the closing of the BreitBurn Transaction no longer qualifies for hedge
accounting treatment. Accordingly, concurrent with the completion of the BreitBurn Transaction, the
Company reclassified the amounts included in accumulated other comprehensive income for the
affected Northeast Operations hedges and recognized the changes in fair value for such contracts.
This aggregate recognition totaled approximately $0.8 million, which increased other revenue in the
2007 consolidated statements of income. In the fourth quarter of 2007, the Company re-designated
the hedges for the Northeast Operations as hedges of other U.S. production and applied hedge
accounting treatment for prospective changes in value.
The Company was considered to have a “continuing interest” in the assets and subsidiaries sold
in the BreitBurn Transaction as the Company owned approximately 32% of BBEP’s outstanding common
units at the time of the BreitBurn Transaction. Thus, the Company deferred $294 million, or 32%, of
the $923 million calculated book gain and recorded its investment in BBEP units, with an aggregate
value of $724 million, net of the $294 million deferred gain for a net carrying value of $430
million at December 31, 2007. The Company accounts for its investment in the BBEP common units
using the equity method, utilizing a one quarter lag from BBEP’s publicly available information.
See Note 10 for recent developments regarding the Company’s investment in BBEP.
In completing the BreitBurn Transaction, the Company utilized investment banking services.
Approximately $2 million of expense related to such services was included in general and
administrative expense during the third quarter of 2007, with an additional approximately $8.2
million recognized in the fourth quarter of 2007 as a reduction of proceeds generated by the
BreitBurn Transaction.
Under the full cost method of accounting, the Company’s U.S. exploration and production assets
are considered a single asset. The divestiture of the Northeast Operations, therefore, represents a
fractional divestiture of a single asset which precludes reporting the Northeast Operations’
financial position and results of operations as discontinued operations within the consolidated
financial statements.
6. DERIVATIVES AND FAIR VALUE MEASUREMENTS
In accordance with the fair value hierarchy described in SFAS No. 157, the following table
shows the fair value of the Company’s financial assets and liabilities that are required to be
measured at fair value as of December 31, 2008.
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The Company’s derivative instruments at December 31, 2008 and 2007 include the Michigan Sales
Contract that requires delivery of 25 MMcfd of natural gas for $2.49 per Mcf through March 2009. In
December 2007 and in connection with the divestiture of the Northeast Operations, the Company
decided to cease delivering a portion of its natural gas production to supply the contract. As the
contract no longer qualified for the normal sales exclusion under GAAP, the Company recognized a
$63.5 million loss at that time. In January 2008, the Company entered into two fixed-price natural
gas swaps covering all volumes for the remaining contract period, which served to largely eliminate
future earnings exposure for the Company’s remaining obligation under the Michigan Sales Contract.
During 2008, the Company paid $48.2 million, net of derivative settlements, to meet its obligations
under the Michigan Sales Contract.
The change in carrying value of the Company’s derivatives and the contractual fixed-price sale
commitments in the Company’s balance sheet since December 31, 2007 principally resulted from the
decrease in market prices for natural gas, NGL and oil relative to the prices in our derivative
instruments and, to a lesser degree, from settlements made during 2008. The change in fair value of
the effective portion of all cash flow hedges was reflected in accumulated other comprehensive
income, net of deferred tax effects. The Company recorded $1.6 million and $1.0 million of net
gains and a $0.1 million net loss in other revenue as the result of derivative hedge
ineffectiveness for the years ended December 31, 2008, 2007 and 2006, respectively.
The estimated fair values of all derivatives and fixed-price firm sale commitments of the
Company as of December 31, 2008 and 2007 are provided below. The associated carrying values of
these derivatives are equal to the estimated fair values for each period presented. The assets and
liabilities recorded in the balance sheet are netted where derivatives with both gain and loss
positions are held by a single third party where rights of offset exists.
Hedge derivative assets and liabilities of $176.6 million and $1.9 million, respectively have
been classified as current at December 31, 2008 based on the maturity of the derivative
instruments, resulting in $115.1 million of after-tax gains expected to be reclassified from
accumulated other comprehensive income in 2009.
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7. FINANCIAL INSTRUMENTS
Commodity Price Risk
The Company enters into financial derivative contracts to mitigate its exposure to commodity
price risk associated with anticipated future natural gas production and to increase the
predictability of our revenue. As of December 31, 2008, approximately 150 MMcfd and 40 MMcfd of
natural gas price collars and swaps, respectively, have been put in place to hedge 2009 anticipated
natural gas production. Also, approximately 160 Mmcfd of natural gas collars have been executed to
hedge anticipated 2010 natural gas production.
The following tables summarize our open derivative positions as of December 31, 2008 related
to the Company’s natural gas production:
As discussed in Note 6, the Company also has an obligation through March 2009 to deliver 25
MMcfd of natural gas under the Michigan Sales Contract, which has a floor price of $2.49 per Mcf.
In January 2008, the Company entered into two fixed-price natural gas swaps covering all remaining
volumes for the remaining contract period that have served to effectively eliminate any significant
net earnings exposure for the Company’s remaining obligations. During 2008, the Company paid $48.2
million of net cash in settlement of its obligations under the Michigan Sales Contract.
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Utilization of our financial hedging program will most often result in the Company’s realized
prices from the sale of its natural gas, NGL and crude oil to vary from market prices. As a result
of settlements of derivative contracts, the Company’s revenue from natural gas, NGL and crude oil
production was $18.4 million lower for 2008 and $51.1 million and $15.5 million higher for 2007 and
2006, respectively.
Interest Rate Risk
There were no interest rate swaps utilized during 2008 or 2007. However, interest expense for
2006 was $0.1 million lower as a result of interest rate swaps.
Credit Risk
Credit risk is the risk of loss as a result of non-performance by counterparties of their
contractual obligations. The Company sells a portion of its natural gas production at spot or
short-term contract prices. All its production is sold to large trading companies and energy
marketing companies, refineries and other users of petroleum products. The Company also enters into
hedge derivatives with financial counterparties. The Company monitors exposure to counterparties by
reviewing credit ratings, financial statements and credit service reports. Exposure levels are
limited and parental guarantees and collateral are used to manage our exposure to counterparties
according to the Company’s established policy. Each customer and counterparty is reviewed as to
credit worthiness prior to the extension of credit and on a regular basis thereafter. The Company
has not experienced any significant credit losses during any of the three years ended December 31,
2008.
Performance Risk
Performance risk results when a financial counterparty fails to fulfill its contractual
obligations such as commodity pricing or volume commitments. Typically, such risk obligations are
defined within the trading agreements. The Company manages performance risk through its management
of credit risk. Each customer and counterparty is reviewed as to credit worthiness prior to the
extension of credit and on a regular basis thereafter.
Foreign Currency Risk
The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. To the
extent that business transactions in Canada are not denominated in Canadian dollars, the Company is
exposed to foreign currency exchange rate risk. For 2008, 2007 and 2006, non-functional currency
transactions resulted in losses of $3.3 million, $0.8 million and $0.1 million, respectively,
included in net earnings. Furthermore, the Senior Secured Credit Facility permits Canadian
borrowings to be made in either U.S. or Canadian-denominated amounts. However, the aggregate
borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent.
Accordingly, there is a risk that exchange rate movements could impact the available borrowing
capacity.
Although cross-currency transactions are minimized, the result of a 10% change in the
Canadian-U.S. exchange rate would increase or decrease stockholders’ equity by approximately $28
million at December 31, 2008.
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8. ACCOUNTS RECEIVABLE
Accounts receivable consisted of the following:
9. OTHER CURRENT ASSETS
Other current assets consisted of the following:
10. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.
In 2007, the Company received common units of BBEP, a publicly traded limited partnership, as
part of the BreitBurn Transaction, which is more fully described in Note 5. On June 17, 2008, BBEP
announced that it had repurchased and retired 14.4 million units, which represented approximately
22% of the units previously outstanding. The resulting reduction in the number of BBEP common units
outstanding increased the Company’s ownership from approximately 32% to approximately 41%.
During the fourth quarter of 2008, the Company evaluated its investment in BBEP for impairment
in response to decreases in both prevailing commodity prices and BBEP’s unit price. The Company
considered numerous factors in evaluating whether this decline was other-than-temporary. In final
reflection, the length of time at which BBEP traded below the Company’s net carrying value per
unit, prevailing petroleum prices and broad limitations on available capital resulted in the
determination that the decline in value was other-than-temporary. While the Company believes that
the market forces that influence commodity and equity prices are under duress, the accounting rules
that govern fair value assessments are rigid in their requirement to utilize the quoted market
prices for determination of fair value. Accordingly, the impairment analysis utilized the December
31, 2008 price of $7.05 per BBEP unit. This resulted in an aggregate fair value of $150.5 million
for the portion of BBEP units owned by the Company, which was then compared to the carrying value
of $470.9 million. The difference of $320.4 million was recognized as an impairment charge during
2008.
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Summarized estimated financial information for BBEP is as follows:
11. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
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Ceiling Test Analysis
As described in Note 2, the Company is required to perform a quarterly ceiling test for each
of its cost centers. The ceiling test incorporates assumptions regarding pricing and discount rates
over which management has no influence in the determination of present value. Additionally, the
Company’s ceiling test for its U.S. cost center ignores any effects of the benefits attendant to
the ownership and consolidation of KGS. In arriving at the ceiling amount for the fourth quarter of
2008, the Company used $5.71 per Mcf of natural gas, $44.60 per Bbl of oil and $21.65 per Bbl of
NGL for its U.S. properties’ production horizon. When the present value of the U.S. reserves was
calculated, the carrying value exceeded the ceiling limit by $624.3 million and resulted in the
impairment charge recognized during the fourth quarter of 2008. The Company has the ability to
examine price recoveries subsequent to December 31, 2008 for incorporation into a revised ceiling
calculation; however, such changes were insufficient to eliminate the impairment charge. The
Company’s Canadian ceiling test required no impairment of its Canadian oil and gas properties.
During the fourth quarter of 2008, the Company determined that the exploration costs for the
Delaware Basin of West Texas would become part of the U.S. full-cost pool and no longer remain
excluded from depletion. The Company also evaluated its midstream assets in West Texas for
impairment, recording an impairment charge of $9.2 million to reduce those midstream assets to
their estimated fair values.
Unevaluated Natural Gas and Crude Oil Properties Not Subject to Depletion
Under full cost accounting, the Company may exclude certain unevaluated property costs from
the amortization base pending determination of whether proved reserves have been discovered or
impairment has occurred. A summary of the unevaluated properties not subject to depletion at
December 31, 2008 and 2007 and the year in which they were incurred follows:
The following table summarizes the unevaluated property costs not subject to depletion.
Costs are transferred into the amortization base on an ongoing basis, as the projects are
evaluated and proved reserves established or impairment determined. Pending determination of proved
reserves attributable to the above costs, the Company cannot assess the future impact on the
amortization rate. Unevaluated acquisition costs will require an estimated eight to ten years of
exploration and development activity before evaluation is complete.
Other Matters
Capitalized overhead costs that directly relate to exploration and development activities were
$16.8 million, $7.0 million and $3.2 million for the years ended December 31, 2008, 2007 and 2006,
respectively. Depletion per Mcfe was $1.68, $1.28 and $1.07 for the years ended December 31, 2008,
2007 and 2006, respectively.
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12. OTHER ASSETS
Other assets consisted of the following:
Costs related to the acquisition of debt are deferred and amortized over the term of the debt.
13. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
14. LONG-TERM DEBT (Restated)
Except for issues arising from the failure to provide certain financial information
about the Company and its restricted subsidiaries required to be disclosed under its
supplemental indentures and as described in Note 21, as of December 31, 2008, the
Company was in compliance with all covenants associated with its long-term debt, other
notes and loans. On June 15, 2009, the Company completed receipt of acknowledgements
from its lenders for the senior secured credit facility wherein they
agreed to waive any defaults associated with the provision of financial information
about the Company and its restricted subsidiaries. The Company
believes that the
provision of the financial information about the Company and its restricted subsidiaries
herein satisfies the reporting requirements for all previous periods and requires no further
waivers from lenders, and accordingly has made no change to the anticipated maturities
of the outstanding debt, as previously reported.
Notes 21 and 27 have also been
restated to reflect inclusion of this financial information.
Long-term debt consisted of the following:
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Maturities are as follows
Senior Secured Credit Facility
The Company’s Senior Secured Credit Facility matures February 9, 2012. The facility provides
for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount
not to exceed the borrowing base, which is calculated based on several factors. The borrowing base
is subject to at least annual redeterminations. In September 2008, the lenders agreed to a
borrowing base of $1.2 billion. The lenders also agreed to $1.2 billion of revolving credit
commitments and, with lender approval, the Company has an option to increase the facility to $1.45
billion. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds,
with the U.S. currency available for borrowing by U.S. subsidiaries and either U.S. or Canadian
currency available for borrowing in Canada. The facility has the option to extend the maturity up
to two additional years. U.S. borrowings under the facility are guaranteed by most of Quicksilver’s
domestic subsidiaries and are secured by, among other things, Quicksilver’s and its domestic
subsidiaries’ oil and gas properties and quantities of proved reserves of natural gas, NGLs and
crude oil attributable to them. Canadian borrowings under the facility are guaranteed by
Quicksilver and most of Quicksilver’s domestic subsidiaries and are secured by, among other things,
the Company’s Canadian, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and
gas properties and quantities of proved reserves of natural gas, NGLs and crude oil attributable to
them. In 2007, the Company agreed to pledge the equity interests in BBEP it received as part of the
BreitBurn Transaction to secure its obligations under the credit facility. At December 31, 2008,
the Company had approximately $369 million available borrowing capacity under this facility.
Senior Secured Second Lien Facility
On August 8, 2008, the Company entered into a $700 million five-year senior secured second
lien facility (“Senior Secured Second Lien Facility”) pursuant to the Alliance Acquisition. Net
proceeds were $674.5 million after discount and issuance costs. The Senior Secured Second Lien
Facility features LIBOR or ABR rate options with minimum floors plus a spread. On the last day of
each quarter, the Company must make a principal payments of $1.6 million which will be adjusted
should the Company make unscheduled loan repayments. In connection with the Senior Secured Second
Lien Facility, Quicksilver entered into collateral agreements pursuant to which Quicksilver’s
obligations under the Senior Secured Second Lien Facility, its Senior Notes due 2015 and its
domestic subsidiaries’ guaranty obligations with respect to the Senior Secured Second Lien Facility
and the Senior Notes have been secured equally and ratably by a second lien on substantially all of
the assets of Quicksilver and such domestic subsidiaries and the
equity of certain domestic subsidiaries.
Senior Notes
On June 27, 2008, the Company issued $475 million of Senior Notes due 2015 (“Senior Notes”),
which are secured, senior obligations of the Company. Interest of 8.25% is payable semiannually
on February 1 and August 1. Net proceeds of $457 million after discount and issuance costs were
used to pay down balances then outstanding under the senior secured credit facility.
Senior Subordinated Notes
On March 16, 2006, the Company issued the senior subordinated notes due 2016 (“Senior
Subordinated Notes”), which are unsecured, senior subordinated obligations of the Company and bear
interest at an annual rate of 7.125% payable semiannually on April 1 and October 1.
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Convertible Debentures
The convertible debentures due November 1,
2024 are contingently convertible into shares of
Quicksilver’s common stock. The debentures bear interest at an annual rate of 1.875% payable
semi-annually on May 1 and November 1. The Company recognizes interest expense at a rate of 6.75%,
which represents the rate at the time that the convertible debentures were issued. The Company
recognized an aggregate discount of $42.7 million upon issuance of the convertible debentures, which
will be amortized through October 2011. Additionally, holders of the debentures can require the
Company to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a
price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are
convertible into Quicksilver common stock at a rate of 65.4418 shares for each $1,000 debenture,
subject to adjustment. Generally, except upon the occurrence of specified events, holders of the
debentures are not entitled to exercise their conversion rights unless the closing price of
Quicksilver’s stock price is at least $18.34 (120% of the conversion price per share) for at least
20 trading days during the period of 30 consecutive trading days ending on the last trading day of
the preceding fiscal quarter. Upon conversion, the Company has the option to deliver any
combination of Quicksilver common stock and cash. Should all debentures be converted to Quicksilver
common stock, an additional 9,816,270 shares would become outstanding; however, as of January 1,
2009, the debentures were not convertible.
The
following summarizes information related to the convertible
debentures after giving effect to the adoption of FSP APB 14-1:
KGS Credit Agreement
Concurrent with its IPO, KGS entered into a five-year $150 million senior secured revolving
credit facility (“KGS Credit Agreement”), with an option exercisable by KGS to extend the facility
for up to two additional years. In October of 2008, the lenders increased the facility to $235
million and approved an accordion option of $115 million to allow for future expansion of the
facility to $350 million upon lender approval. The KGS Credit Agreement provides for revolving
credit loans, swingline loans and letters of credit. Borrowings under the facility are guaranteed
by KGS’ subsidiaries and are secured by substantially all of the assets of KGS and each of its
subsidiaries. The facility features LIBOR and U.S. prime rate interest options for revolving loans
and a specified rate for swingline loans. Each interest rate option includes a margin which flexes
based upon KGS’ leverage ratio.
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Summary of All Outstanding Debt
The following table summarizes significant aspects of our
long-term debt.
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15. ASSET RETIREMENT OBLIGATIONS
The Company records the fair value of the liability for asset retirement obligations in the
period in which it is legally or contractually incurred. Upon initial recognition of the asset
retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of
the asset by the same amount as the liability. In periods subsequent to initial measurement, the
asset retirement cost is recognized as expense through depletion or depreciation over the asset’s
useful life. Changes in the liability for the asset retirement obligations are recognized for (a)
the passage of time and (b) revisions to either the timing or the amount of estimated cash flows.
Accretion expense is recognized for the impacts of increasing the discounted fair value to its
estimated settlement value.
The following table provides a reconciliation of the changes in the estimated asset retirement
obligation from January 1, 2007 through December 31, 2008.
16. INCOME TAXES
In 2006, the Texas business tax was amended by replacing the taxable capital and earned
surplus components of the current franchise tax with a new “taxable margin” component. As the tax
base for computing Texas margin tax is derived from an income-based measure, the Company recognizes
this tax as an income tax. The Company has recorded a deferred tax provision of $1.9 million and
$2.5 million for the Texas margin tax in 2008 and 2007, and a current state income tax provision
for the Texas margin tax in 2007 of $1.0 million.
Tax rate reductions were enacted during 2007 by the Canadian federal government and by Alberta
Province. The Company’s Canadian deferred income tax balances were revalued to reflect the changes
in these tax rates. The Company recorded $4.9 million of income tax benefits in 2007 as a result of
the enactment of Canadian rate reductions. No further rate changes occurred in 2008.
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The Company’s current and deferred tax positions have been significantly impacted by the
November 2007 divestiture of the Northeast Operations and the resulting gain, the impairment of
U.S. oil and gas properties in 2008 and the impairment of its investment in BBEP in 2008.
Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2008
and 2007 are as follows:
The components of income tax expense for 2008, 2007 and 2006 are as follows:
The following table reconciles the statutory federal income tax rate to the effective tax rate
for 2008, 2007 and 2006:
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The Company incurred a $641 million net operating tax loss in 2008. Approximately $137 million
of this loss will be carried back to 2007. The remaining $504 million is included in deferred tax
assets at December 31, 2008. The net operating loss will expire in 2028. The net operating loss was
not reduced by a valuation allowance, because management believed that future taxable income would
more likely than not be sufficient to utilize substantially all of its operating loss tax carry
forwards prior to their expiration.
During 2007, the Company recognized $2.8 million in income tax benefits associated with the
exercise of employee stock options as an increase to additional paid in capital. No such income tax
benefits were recognized in 2008 because of the availability of net operating loss tax carry
forwards to the Company.
The Company adopted FIN 48 on January 1, 2007. In connection with the adoption the Company
recorded an adjustment to retained earnings of approximately $0.3 million for unrecognized tax
benefits, all of which would affect our effective tax rate if recognized. The Company also reported
unrecognized tax benefits for research and experimental development credits for Canadian taxes in
the first quarter of 2007 of $1.1 million. The following schedule reconciles the total amounts of
unrecognized tax benefits for 2008 and 2007.
Approximately $8.9 million of these unrecognized tax benefits at December 31, 2008, if
recognized, would impact the effective tax rate. Interest and penalties of $0.6 million related to
unrecognized tax benefits were recognized as interest expense for 2007 and subsequently reversed in
2008. The Company remains subject to examination by the Internal Revenue Service (“IRS”) for the
years 2001 through 2007 except for 2004. An audit was completed by the IRS for 2004 and the statute
of limitations has now expired for this year. The Company does not expect that the total amounts of
unrecognized tax benefits will significantly increase or decrease.
17. COMMITMENTS AND CONTINGENCIES
Contractual Obligations.
Information regarding our contractual and scheduled interest obligations, at December 31,
2008, is set forth in the following table.
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Commitments
The Company had commitments outstanding of approximately $3.4 million to purchase components
for our drilling program as of December 31, 2008. In addition, the Company had approximately $3.0
million in letters of credit outstanding against the credit facility and approximately $41.3
million in surety bonds issued to fulfill contractual, legal or regulatory requirements. All surety
bonds and letters of credit have an annual renewal option.
Contingencies
On November 7, 2001, the Company filed a lawsuit against CMS Marketing Services and Trading
Company (“CMS”) in Texas. The suit alleged that CMS committed fraud when it entered into a 10-year
contract with the Company on March 1, 1999 for the purchase and sale of 10,000 MMBtud of natural
gas at a minimum price of $2.47 per MMBtu and breached the contract afterward by failing to comply
with a provision of the contract requiring that, if the gas could be scheduled or delivered to
derive additional value, the parties would share equally in the additional revenue. On May 15,
2007, the district court entered a final judgment in favor of the Company against CMS (“CMS”),
declaring the Company’s contract with CMS to be void and rescinded as of that date. CMS appealed
this judgment. The Company also appealed seeking to have the contract voided from its inception and
seeking to recover jury-awarded punitive damages of $10 million. Pending final judgment by the
appellate court, CMS and the Company agreed to a settlement based upon the decision to be rendered
by the appellate court. The settlement agreement specifies that CMS will pay the Company all costs
paid by it for all bonds posted on appeal and the Company shall have no obligation under its
contract with CMS if the appellate decision affirms the original district court decision. If the
appellate court voids the contract from its inception, CMS shall pay the Company $5 million plus
all costs paid by the Company for all bonds posted on appeal. If the appellate court reverses the
district court judgment, the Company will pay $5 million to CMS. If the appellate court finds that
the Company is entitled to punitive damages, CMS will pay the Company $5 million. If the appellate
court remands the matter back to the lower courts for any action other than for punitive damages,
the parties agreed to forego further adjudication of the matter without payment.
On October 13, 2006, the Company filed suit in district court in Texas against Eagle Drilling,
LLC and Eagle Domestic Drilling Operations, LLC (together “Eagle”) regarding three contracts for
drilling rigs in which the Company alleged that the first rig furnished by Eagle exhibited
operating deficiencies and safety defects and that the other rigs failed to conform to
specifications set forth in the drilling contracts. On January 19, 2007, Eagle Domestic Drilling
Operations, LLC and its parent, Blast Energy Services, Inc. filed for Chapter 11 bankruptcy. The
Company’s suit against Eagle in Tarrant County was ultimately transferred to the bankruptcy court
in Houston and has been consolidated with the Eagle/Blast bankruptcy, described more fully below.
On September 17, 2007, Eagle Drilling, LLC, and Rod and Richard Thornton, sued the Company and its
Executive Vice President Operations, in district court in Oklahoma for approximately $29 million in
damages and an unspecified amount of punitive damages resulting from the Company’s repudiation of
the rig contracts.
In September 2008, the Company entered into a settlement agreement with Eagle Domestic
Drilling Operations, LLC and its parent, Blast Energy Services, Inc. (“Eagle/Blast”) that was
approved in October by the district court in Texas. Under the settlement agreement, the Company
agreed to pay Eagle/Blast $10 million over a three-year period, including $5 million on the
settlement date. The Company recorded a $9.6 million charge to general and administrative expense
during the quarter ended September 30, 2008 for the net present value of these payments. The other
cases involving Eagle and its affiliates were not directly affected by this settlement. Based upon
information currently available, the Company believes that the final resolution of this matter will
not have a material effect on its financial condition, results of operations, or cash flows.
On October 31, 2008, the Company filed a lawsuit in district court in Texas against BBEP,
BreitBurn GP, LLC, BreitBurn Operating L.P., Provident Energy Trust and certain individuals who
serve as, or have previously served as, directors and/or officers of these entities (collectively,
the “Defendants”). The Company alleges that, among other things, one or more of the Defendants
breached the agreement pursuant to which the Company acquired its ownership interest in BBEP, and
violated the Texas Securities Act and the Texas Business & Commerce Code, committed common law
fraud, fraudulent inducement, negligent misrepresentation and civil conspiracy. The Company has
requested, among other things, relief for actual and exemplary damages, and for injunctive and
declaratory relief.
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18. NONCONTROLLING INTERESTS
As a result of the KGS IPO, the outside ownership of KGS increased, however the Company
continues to own 100% of KGS’ general partner and, therefore, continues to consolidate KGS into the
Company’s financial statements. However, by virtue of the elevated outside ownership, the carrying
value of the Company’s noncontrolling interests is much larger than years prior to KGS’ IPO.
19. EMPLOYEE BENEFITS
Quicksilver has a 401(k) retirement plan available to all U.S. full time employees who are at
least 21 years of age. The Company makes matching contributions and a fixed annual contribution and
has the ability to make discretionary contributions to the plan. Expenses associated with company
contributions were $2.4 million, $1.6 million and $1.4 million for 2008, 2007 and 2006,
respectively.
The Company has a retirement plan available to all Canadian employees. The plan provides for a
match of employees’ contributions by the Company and a fixed annual contribution. Expenses
associated with company contributions were $0.8 million, $0.7 million and $0.5 million for the
2008, 2007 and 2006, respectively.
The Company maintains a self-funded health benefit plan that covers all eligible U.S.
employees. The plan has been reinsured on an individual claim and total group claim basis.
Quicksilver is responsible for payment of the first $75,000 for each individual claim and also
purchased aggregate level reinsurance for payment of claims up to $1 million over the estimated
maximum claim liability. For 2008, 2007 and 2006 the Company recognized expenses of $4.4 million,
$3.2 million and $2.5 million, respectively, for this plan.
20. STOCKHOLDERS’ EQUITY
Common Stock, Preferred Stock and Treasury Stock
The Company is authorized to issue 400 million shares of common stock with a par value per
share of one cent and 10 million shares of preferred stock with a par value per share of one cent.
At December 31, 2008, the Company had 167,169,904 shares of common stock outstanding.
The following table shows common share and treasury share activity since January 1, 2006:
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Stockholder Rights Plan
In 2003, the Company’s Board of Directors declared a dividend distribution of one preferred
share purchase right for each outstanding share of common stock then outstanding. Each right, when
it becomes exercisable, entitles stockholders to buy one one-thousandth of a share of the Company’s
Series A Junior Participating Preferred Stock at an exercise price of $90, after adjustments to
reflect the two-for-one stock split in January 2008.
The rights will be exercisable only if such a person or group acquires 15% or more of the
common stock of Quicksilver or announces a tender offer the consummation of which would result in
ownership by such a person or group (an “Acquiring Person”) of 15% or more of the common stock of
the Company. This 15% threshold does not apply to certain members of the Darden family and
affiliated entities, which collectively owned, directly or indirectly, approximately 30% of the
Company’s common stock at December 31, 2008.
If an Acquiring Person acquires 15% or more of the outstanding common stock of the Company,
each right will entitle its holder to purchase, at the right’s then-current exercise price, a
number of common shares of the Company having a market value of twice such price. If Quicksilver is
acquired in a merger or other business combination transaction after an Acquiring Person has
acquired 15% or more of the outstanding common stock of the Company, each right will entitle its
holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s
common shares having a market value of twice such price.
Prior to the acquisition by an Acquiring Person of beneficial ownership of 15% or more of the
common stock of Quicksilver, the rights are redeemable for $0.01 per right at the option of the
Board of Directors of the Company.
Employee Stock Plans
1999 and 2004 Plans
In 1999, the Board of Directors adopted the Company’s 1999 Stock Option and Retention Stock
Plan (the “1999 Plan”), which was approved at the annual stockholders’ meeting held in June 2000.
Under the 1999 Plan, 7.8 million shares of common stock could be issued via incentive stock
options, non-qualified stock options, stock appreciation rights and retention stock awards.
Pursuant to an amendment approved at the annual shareholders meeting held in May 2004, an
additional 7.2 million shares were reserved for issuance pursuant to the 1999 Plan. As of December
31, 2008, a total of 219,321 shares and 193,842 options to purchase shares granted under the 1999
plan remain unvested.
In February 2004, the Board of Directors adopted the Company’s 2004 Non-Employee Director
Equity Plan (the “2004 Plan”), which was approved at the annual stockholders’ meeting held in May
2004. There were 1.5 million shares reserved under the 2004 Plan, which permits issuance of
non-qualified options and restricted stock awards to Quicksilver’s non-employee directors.
Under terms of the 1999 Plan and 2004 Plan, equity awards to officers, employees and
non-employee directors reflect an exercise price of not less than the fair market value on the date
of grant. Incentive stock options and non-qualified options’ lives may not exceed ten years from
date of grant. Although shares were still available for issuance under the 1999 and 2004 Plans, in
approving the 2006 Equity Plan, the Company agreed to make no further issuances under these plans.
2006 Equity Plan
In 2006, the Board of Directors and the shareholders approved the Company’s 2006 Equity Plan.
Upon approval of the 2006 Equity Plan, 14 million shares of common stock were reserved for issuance
as grants of stock options, appreciation rights, restricted shares, restricted stock units,
performances shares, performance units and senior executive plan bonuses. Executive officers, other
employees, consultants and non-employee directors of the Company are eligible to participate in the
2006 Equity Plan. Under the 2006 Equity Plan, options reflect an exercise price of not less than
the fair market value on the date of grant and have a life of 10 years. At December 31, 2008,
12,176,203 shares (including 107,482 shares surrendered to the Company to satisfy participants’ tax
withholding obligations which then became available for future issuance under the 2006 Equity Plan)
of common stock were available for issuance under the 2006 Equity Plan.
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Stock Options Under All Plans
The following summarizes the values from and assumptions for the Black-Scholes option pricing
model:
The following table summarizes the Company’s stock option activity for 2008:
The Company estimates that a total of 1,086,497 stock options will become vested including
those options already exercisable. These options have a weighted average exercise price of $13.94
and a weighted average remaining contractual life of 3.7 years.
Compensation expense related to stock options of $1.6 million and $0.1 million was recognized
for 2008 and 2007, respectively. Cash received from the exercise of stock options totaled $1.2
million, $21.4 million and $19.7 million for the years 2008, 2007 and 2006, respectively. The total
intrinsic value of options exercised during 2008, 2007 and 2006, was $6.7 million, $30.5 million
and $26.9 million, respectively.
Restricted Stock Under All Plans
The following table summarizes the Company’s restricted stock and stock unit activity for
2008:
At December 31, 2007, the Company had unvested compensation cost of $15.2 million. During
2008, $13.5 million of compensation expense was recognized for restricted stock and stock units. As
of December 31, 2008, the unrecognized compensation cost related to outstanding unvested restricted
stock was $17.6 million, which is expected to be recognized in expense over the next twelve months.
For 2007 and 2006, compensation expense of $11.0 million and $5.8 million, respectively, was
recognized.
The total fair value of shares vested during 2008, 2007 and 2006 was $15.1 million, $6.4
million and $2.1 million, respectively.
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KGS Restricted Phantom Units
Awards of phantom units have been granted under KGS’ 2007 Equity Plan, which permits the
issuance of up to 750,000 units. The following table summarizes information regarding the phantom
unit activity:
At January 1, 2008, KGS had total unvested compensation cost of $1.9 million related to
unvested phantom units. KGS recognized compensation expense of approximately $1.4 million during
2008, including $0.4 million for remeasuring awards to be settled in cash to their revised fair
value. Grants of phantom units during the year ended December 31, 2008 had an estimated grant date
fair value of $3.6 million. KGS has unearned compensation of $2.3 million which will be recognized
in expense over the next 1.9 years. Phantom units that vested during the year ended December 31,
2008 had a fair value of $0.7 million.
21.
ANNUAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Restated)
The
following information reflects corrections to amounts previously
reported. The previously reported information contained errors, most notably that certain
combining adjustments for non-guarantor subsidiaries were reported as consolidating
adjustments and certain earnings of consolidated non-guarantors were
not appropriately reflected in their guarantor owners’
consolidated financial information. The following table illustrates the effects of the
errors and the adoption of new accounting pronouncements as discussed
in Note 2, on previously reported annual condensed consolidating
financial information. These errors had no effect on the
consolidated amounts previously reported.
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