UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31,
2009
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period from
to
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Commission file number:
001-14837
QUICKSILVER
RESOURCES INC.
(Exact
name of registrant as specified in its charter)
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Delaware
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75-2756163
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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777 West Rosedale St., Fort Worth, Texas
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76104
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(Address of principal executive offices)
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(Zip Code)
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817-665-5000
(Registrants
telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which
registered
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Common Stock, $0.01 par value per share
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New York Stock Exchange
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Preferred Share Purchase Rights,
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$0.01 par value per share
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New York Stock Exchange
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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 whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§232.405 of this chapter) during the preceding
12 months (or shorter period that the registrant was
required to submit and post such
files). Yes o 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 registrants 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. þ
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.
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o Smaller
reporting
company o
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, 2009, the aggregate market value of the
registrants common stock held by non-affiliates of the
registrant was $1,087,255,512 based on the closing sale price of
$9.29 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the
registrants classes of common stock, as of the latest
practicable date.
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Class
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Outstanding at February 15,
2010
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Common Stock, $0.01 par value per share
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170,222,678 shares
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DOCUMENTS
INCORPORATED BY REFERENCE
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Document
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Parts Into Which Incorporated
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Proxy Statement for the Registrants May 19,
2010 Annual Meeting of Stockholders
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Part III
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DEFINITIONS
As used in this Annual Report unless the context otherwise
requires:
Bbl or Bbls means barrel
or barrels
Bbld means barrel or barrels per day
Bcf means billion cubic feet
Bcfd means billion cubic feet per day
Bcfe means Bcf of natural gas equivalents,
calculated as one Bbl of oil or NGLs equaling six Mcf of gas
Canada means the division of Quicksilver
encompassing oil and natural gas properties located in Canada
CBM means coalbed methane
CERCLA means the Comprehensive Environmental
Response, Compensation and Liability Act
DD&A means Depletion, Depreciation and
Accretion
GHG means greenhouse gas
EPA means the U.S. Environmental
Protection Agency
LIBOR means London Interbank Offered Rate
MBbl or MBbls means
thousand barrels
MBbld means thousand barrels per day
MMBbls means million barrels
MMBtu means million British Thermal Units, a
measure of heating value, and is approximately equal to
1 Mcf of natural gas
MMBtud means million Btu per day
Mcf means thousand cubic feet
Mcfe means Mcf natural gas equivalents
calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcf means million cubic feet
MMcfd means million cubic feet per day
MMcfe means MMcf of natural gas equivalents,
calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcfed means MMcfe per day
NGL or NGLs means natural
gas liquids
NYMEX means New York Mercantile Exchange
NYSE means New York Stock Exchange
Oil includes crude oil and condensate
Tcfe means trillion cubic feet of natural gas
equivalents, calculated as one Bbl of oil or NGLs equaling six
Mcf of gas
COMMONLY
USED TERMS
Other commonly used terms and abbreviations include:
ABR means adjusted base rate
AOCI means accumulated other comprehensive
income
Alliance Acquisition means the August 8,
2008 purchase of leasehold, royalty and midstream assets in the
Barnett Shale in northern Tarrant and southern Denton counties
of Texas
Alliance Leasehold means the natural gas
leasehold and royalty interests acquired in the Alliance
Acquisition and developed thereafter
Alliance Midstream Assets means the natural
gas gathering network and processing facilities purchased by KGS
from Quicksilver in January 2010
BBEP means BreitBurn Energy Partners
L.P.
BreitBurn Transaction means the
November 1, 2007 conveyance of our Northeast Operations in
exchange for aggregate proceeds of $1.47 billion
CMS Litigation means litigation against CMS
Marketing Services and Trading Company concerning a gas supply
contract under which we agreed to deliver 10 MMcfd at a
floor price of $2.49 per Mcf
Eni means either or both Eni Petroleum US LLC
and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA
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Eni Production means production attributable
to Eni pursuant to the Eni Transaction
Eni Transaction means the June 19, 2009
conveyance of a 27.5% interest in our Alliance Leasehold
FASB means the Financial Accounting Standards
Board, which promulgates accounting standards in the U.S.
FASC means the FASB Accounting Standards
Codification, which is the single source of authoritative
U.S. GAAP not promulgated by the SEC
GAAP means accounting principles generally
accepted in the United States
Gas Purchase Commitment means the commitment
pursuant to the Eni Transaction to purchase the Eni Production
at $8.60 per MMBtu less costs related to gathering and processing
KGS means Quicksilver Gas Services LP, which
is our publicly-traded partnership that trades under the ticker
symbol KGS
KGS Credit Agreement means the KGS senior
secured revolving credit facility
KGS IPO means the KGS initial public offering
completed on August 10, 2007
KGS Secondary Offering means the public
offering of 4,000,000 KGS common units on December 16, 2009
and the underwriters option exercise to purchase an
additional 549,200 KGS common units during January 2010
Mercury means Mercury Exploration Company,
which is owned by members of the Darden family
Michigan Sales Contract means the gas supply
contract which expired in March 2009 under which we agreed to
deliver 25 MMcfd at a floor price of $2.49 per Mcf
Northeast Operations means the oil and gas
properties and facilities in Michigan, Indiana and Kentucky
which were conveyed to BBEP in November 2007
RSU means restricted stock unit
SEC means the United States Securities and
Exchange Commission
Senior Secured Credit Facility means our
U.S. senior secured revolving credit facility and our
Canadian senior secured revolving credit facility
Senior Secured Second Lien Facility means our
$700 million five-year senior secured second lien facility
which we entered into pursuant to the Alliance Transaction that
we subsequently repaid and terminated in June 2009
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INDEX TO
ANNUAL REPORT ON
FORM 10-K
For the Year Ended December 31, 2009
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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Forward-Looking
Information
Certain statements contained in this Annual Report and other
materials we file with the SEC, or in other written or oral
statements made or to be made by us, other than statements of
historical fact, are forward-looking statements as
defined in the Private Securities Litigation Reform Act of
1995. Forward-looking statements give our current expectations
or forecasts of future events. Words such as may,
assume, forecast, position,
predict, strategy, expect,
intend, plan, estimate,
anticipate, believe,
project, budget, potential,
or continue, and similar expressions are used to
identify forward-looking statements. They can be affected by
assumptions used or by known or unknown risks or uncertainties.
Consequently, no forward-looking statements can be guaranteed.
Actual results may vary materially. You are cautioned not to
place undue reliance on any forward-looking statements. You
should also understand that it is not possible to predict or
identify all such factors and should not consider the following
list to be a complete statement of all potential risks and
uncertainties. Factors that could cause our actual results to
differ materially from the results contemplated by such
forward-looking statements include:
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changes in general economic conditions;
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fluctuations in natural gas, NGL and oil prices;
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failure or delays in achieving expected production from
exploration and development projects;
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uncertainties inherent in estimates of natural gas, NGL and oil
reserves and predicting natural gas, NGL and oil reservoir
performance;
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effects of hedging natural gas, NGL and oil prices;
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fluctuations in the value of certain of our assets and
liabilities;
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competitive conditions in our industry;
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actions taken or non-performance by third parties, including
suppliers, contractors, operators, processors, transporters,
customers and counterparties;
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changes in the availability and cost of capital;
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delays in obtaining oilfield equipment and increases in drilling
and other service costs;
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operating hazards, natural disasters, weather-related delays,
casualty losses and other matters beyond our control;
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the effects of existing and future laws and governmental
regulations, including environmental and climate change
requirements;
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the effects of existing or future litigation; and
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certain factors discussed elsewhere in this Annual Report.
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This list of factors is not exhaustive, and new factors may
emerge or changes to these factors may occur that would impact
our business. Additional information regarding these and other
factors may be contained in our filings with the SEC, especially
on
Forms 10-K,
10-Q and
8-K. All
such risk factors are difficult to predict, and are subject to
material uncertainties that may affect actual results and may be
beyond our control. The forward-looking statements included in
this Annual Report are made only as of the date of this Annual
Report, and we undertake no obligation to update any of these
forward-looking statements to reflect subsequent events or
circumstances except to the extent required by applicable law.
All forward-looking statements are expressly qualified in their
entirety by the foregoing cautionary statements.
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PART I
GENERAL
Quicksilver Resources Inc., including its subsidiaries, is an
independent energy company engaged primarily in exploration,
development and production of unconventional natural gas onshore
in North America. We own producing oil and natural gas
properties in the United States, principally in Texas, Colorado,
Wyoming and Montana, and Canada in Alberta and British Columbia,
which had estimated total proved reserves of approximately
2.4 Tcfe at December 31, 2009. We have significant
exploration activities in North America, principally in the Horn
River Basin of Northeast British Columbia and the Green River
Basin of Colorado. In addition, our new ventures team actively
studies other basins in North America for unconventional natural
gas opportunities which may yield future exploration
opportunities. After completion of the KGS Secondary Offering,
we own approximately 61% of KGS, a publicly-traded midstream
master limited partnership controlled by us, and we also own
approximately 40% of the limited partner units of BBEP, a
publicly-traded oil and natural gas exploration and production
master limited partnership.
Our common stock trades under the symbol KWK on the
New York Stock Exchange. The units of KGS are publicly traded
on the NYSE under the ticker symbol KGS and the
units of BBEP are traded on the NASDAQ Global Select Market
under the ticker symbol BBEP.
FORMATION
AND DEVELOPMENT OF BUSINESS
We were organized as a Delaware corporation in 1997 and became a
public company in 1999. As of December 31, 2009, members
of the Darden family and entities controlled by them,
beneficially owned approximately 30% of our outstanding common
stock.
STRATEGIC
TRANSACTIONS
In August 2008, we completed the $1.3 billion Alliance
Acquisition that consisted of producing and non-producing
leasehold, royalty and midstream assets that we believe
complements our existing operations in the Fort Worth Basin
of North Texas. Consideration in the transaction was
$1 billion in cash, which was financed with debt, and
$262 million in Quicksilver common stock. We funded the
cash portion of the transaction by drawing $675 million on
our Senior Secured Second Lien Facility and drawing the
remainder on our Senior Secured Credit Facility. At the time of
the acquisition, there were 299 Bcf of proved natural gas
reserves and considerable opportunities for increasing our
proved reserves.
In June 2009, we completed the sale of a 27.5% working interest
in our Alliance Leasehold to Eni for total proceeds of
$280 million. In addition to the Alliance Leasehold, which
includes approximately 13,000 acres in northern Tarrant and
southern Denton counties of Texas, Quicksilver and Eni formed a
strategic alliance for acquisition, development and exploitation
of unconventional natural gas resources in an area covering
approximately 270,000 acres surrounding the Alliance
Leasehold. The sale represented approximately 121 Bcf of
proved natural gas reserves as of April 1, 2009.
In January 2010, we completed the previously announced sale of
our Alliance midstream assets to KGS for proceeds of
$95.2 million. KGS funded the purchase with approximately
$92 million of proceeds from the KGS Secondary Offering
which reduced our ownership in KGS from 73% to 61%. In December
2008, we completed the sale of the Lake Arlington Dry System to
KGS for proceeds of approximately $42 million. We believe
the sale of these midstream assets to KGS enables us to maintain
operating control and efficiently develop our natural gas
properties while redeploying the associated capital into
projects with higher expected returns. As KGS is included in
our consolidated financial statements, these transactions had no
effect on our total assets or results of operations.
BUSINESS
STRATEGY
We have a multi-pronged strategy to increase share value through
cost-effective growth in production and reserves by focusing on
unconventional natural gas plays onshore in North America. This
strategy takes
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advantage of our proven record and expertise in identifying and
developing properties containing fractured shale, coalbed
methane and tight sands. Our strategy includes the following
key elements:
Focus on core areas of repeatable, low-risk development:
We believe that operating in concentrated areas allows us to
more efficiently deploy our resources, manage costs and leverage
our base of technical expertise. We intend to invest the
majority of our 2010 capital program in low-risk development and
exploitation projects on our extensive leasehold positions in
the Fort Worth and Western Canadian Sedimentary basins. In
2010, we expect to concentrate our development drilling
primarily in our Barnett Shale properties in the Fort Worth
Basin of North Texas, and to a lesser extent, in our CBM
properties in Alberta, Canada.
Pursue disciplined organic growth opportunities: We
intend to spend approximately 10% of our 2010 capital program in
high-potential, longer cycle-time exploration projects to
replenish our inventory of development projects for the future.
Through our activities in the Fort Worth and Western
Canadian Sedimentary basins, we have developed significant
expertise in identifying, developing and producing fractured
shales, coal seams and tight sands. We are focused on
identifying and evaluating opportunities that allow us to apply
this expertise and experience to the development and operation
of other unconventional reservoirs in North America. In 2010,
we will continue to focus our exploratory activities on our
leasehold interests in the Horn River Basin of Northeast British
Columbia where we hold a 100% working interest in 130,000
prospective acres. We also expect to continue exploratory
activities in the Greater Green River Basin of northern Colorado
and southern Wyoming where we hold a 75% working interest in
approximately 105,000 acres. In addition, we may seek to
acquire similar acreage positions for future exploration
activities.
Enhance profitability through control and marketing of our
equity natural gas and oil: We seek to maximize
profitability by exercising control over the delivery of our
production to distribution pipelines owned by third parties. We
seek to achieve this by continuing to improve upon and add to
our gathering and processing infrastructure. We believe this
allows us to better manage the physical movement of our
production and the costs of our operations by decreasing
dependency on third parties. We also monitor the spot markets
for commodities and seek to sell our uncommitted production into
the most attractive markets. We continue to control our
midstream operations in the Fort Worth Basin through our
ownership of KGS.
Maintain flexible financial profile: We believe that
a flexible financial structure enables us to capitalize on
opportunities and to limit our financial risk. Our ownership
interests in KGS and BBEP provide additional financial
flexibility for the Company while enabling us to participate in
the expected market growth of both these entities. In addition,
to increase the predictability in the prices we receive for our
natural gas and oil production, we hedge the commodity price of
a substantial portion of our production with financial
derivative instruments. We regularly review the
credit-worthiness of our hedging counterparties, and our hedging
program is spread among numerous financial institutions, all of
which participate in our Senior Secured Credit Facility.
BUSINESS
STRENGTHS
High-quality asset base with long reserve life: Our
proved reserves of approximately 2.4 Tcfe as of
December 31, 2009, were approximately 99% natural gas and
NGLs and were 68% proved developed. The majority of these
reserves are located in our core areas in the Fort Worth
Basin in north Texas and the Western Canadian Sedimentary Basin
in Alberta, which accounted for 89% and 10%, respectively, of
our proved reserves. We believe our assets are characterized by
long reserve lives and predictable well production profiles.
Based on our annualized fourth-quarter 2009 average production
from these properties, our implied reserve life (proved reserves
divided by annualized fourth-quarter 2009 production) was
20.4 years and our implied proved developed reserve life
(proved developed reserves divided by annualized fourth quarter
2009 production) was 13.9 years. As of December 31,
2009, we operated properties containing 99% of our proved
reserves.
Multi-year inventory of development and exploitation drilling
projects: As of December 31, 2009, we owned leases
covering more than 500,000 net acres in our two core areas,
of which approximately 34% were undeveloped. Within the
Fort Worth Basin alone, we have identified more than 1,000
remaining drilling locations, which at the anticipated 2010
drilling rate; provide us with a
10-year
inventory of drilling locations.
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Our drilling success rate has averaged more than 99% during the
past three years. We use 3D seismic data to enhance our ongoing
drilling and development efforts as well as to identify new
targets in both new and existing fields, and our seismic library
covers more than 90% of our acreage in the Fort Worth
Basin. For 2010, we expect our capital program will be
approximately $340 million for drilling and completion
activities in the Fort Worth Basin.
Proven record of organic growth in reserves and production:
During the past three years, we have added approximately
1.0 Tcfe of proved reserves from organic development
drilling activities. We have supplemented this activity with
the Alliance Acquisition in 2008, which added 299 Bcfe of
proved reserves at the time of its purchase. We also have
divested approximately 546 Bcfe of proved reserves
associated with our former Northeast Operations in 2007 and
121 Bcf of proved reserves associated with the Eni
Transaction in 2009. Excluding acquisition and divestiture
activity, we have replaced approximately 377% of our production
during the three years ended December 31, 2009. Our growth
has resulted from our ability to acquire attractive undeveloped
acreage and apply our technical expertise to find, develop and
produce reserves. In recent years, we have demonstrated this
ability through our accomplishments in our two core areas. We
believe our current acreage position will provide opportunities
to continue our reserve and production growth.
Midstream strength: Our midstream operations, which
are primarily owned or operated by KGS, are well positioned to
complement our growth initiatives in the Fort Worth Basin
and to compete with other midstream providers for unaffiliated
business. Quicksilvers operational structure allows our
midstream operations to more accurately forecast future
gathering and processing estimates and to assess the need and
timing for capacity additions. We believe KGS assets in
the Fort Worth Basin are well positioned to expand the
gathering system footprint, increase throughput volumes and
plant utilization which we believe will ultimately increase cash
flows.
Experienced management and technical team: Our CEO,
Glenn Darden, and our Chairman, Thomas Darden, are founding
members of our company and have held executive positions at
Quicksilver since our formation. They both have been in the oil
and natural gas business their entire professional careers.
Since our formation, they, along with an experienced executive
management team, have successfully implemented a disciplined
growth strategy with a primary focus on net asset value growth
through the development of unconventional resources. Our
executive management team is supported by a core team of
technical and operational managers who have significant industry
experience, including experience in drilling and completing
horizontal wells and in unconventional reservoirs.
FINANCIAL
INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS
The consolidated financial statements included in Item 8 of
this Annual Report contain information on our segments and
geographical areas, which is incorporated herein by reference.
PROPERTIES
Substantially all of our properties consist of interests in
developed and undeveloped oil and natural gas leases and mineral
acreage. In addition, we have midstream assets, including
natural gas and NGL processing plants and related gathering and
treating systems. Our midstream operations in the
Fort Worth Basin are conducted by KGS, of which we own
approximately 61% of the partnership interests, including 100%
of its general partner. We also indirectly own interests in
other oil and natural gas properties through our ownership of
approximately 21.348 million limited partnership units in
BBEP, representing approximately 40% of their partnership
interests.
OIL AND
NATURAL GAS OPERATIONS
Our oil and natural gas operations are focused onshore in North
America, primarily in unconventional natural gas plays. Our
current production and development operations are concentrated
in the Fort Worth and Western Canadian Sedimentary basins.
At December 31, 2009, we had estimated total proved
reserves of approximately 2.4 Tcfe, 99% of which were
natural gas and NGLs and 68% of which were proved developed.
Approximately 89% of our reserves at December 31, 2009 were
located in Texas and approximately 10% were in Canada. For
2009, we had average production of 324.5 MMcfe per day and
total production of 118.5 Bcfe.
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Since going public in 1999, we have grown our reserves and
production at an approximate compound annual growth rate of 24%
and 19%, respectively.
We believe that our 2010 and 2011 reserve and production growth
will be through development of our leasehold interests in our
core areas in Texas and Alberta. We anticipate our 2010
production volumes to average in the range of 390 MMcfe to
400 MMcfe and are expected to consist of approximately 80%
natural gas and 20% NGLs and oil. In addition, we are actively
exploring the Horn River Basin in British Columbia and the Green
River Basin in Colorado and Wyoming. We may also pursue
acquisitions of additional undeveloped leasehold interests,
which could allow for further capitalization on our proven
expertise in unconventional gas plays.
Texas
Our Barnett Shale properties in the Fort Worth Basin in
North Texas contained 89% of our total estimated proved reserves
and approximately 78% of our total average daily production came
from these properties in 2009. In the fourth quarter of 2009,
our net production from our Texas wells was approximately
251 MMcfed. We expect approximately 80% of our 2010
production to come from our Texas properties.
At December 31, 2009, we held approximately
162,000 net acres in the Fort Worth Basin of which
approximately 40% is currently developed. We have identified
more than 1,000 remaining potential drilling locations in the
Fort Worth Basin. Much of our acreage in Hood and
Somervell counties contains
high-Btu
natural gas which contains NGLs within the natural gas stream.
We gather our production and process the
high-Btu
natural gas through a midstream system that is primarily owned
and operated by KGS.
KGS manages a network of natural gas gathering pipelines,
ranging up to 20 inches in diameter, all located in the
Fort Worth Basin. Additionally, KGS owns a NGL pipeline
that interconnects with pipelines owned by third parties. The
pipeline system gathers and delivers natural gas produced by our
wells and those of third parties to the processing facilities.
We expect to continue to construct additional gathering assets
as additional wells in the Fort Worth Basin are developed.
Our capital program for 2010 includes approximately
$92 million for midstream assets, including
$80 million to be funded by KGS.
During 2009, we drilled 156 gross (95.2 net) wells in the
Fort Worth Basin primarily from multi-well drilling pads.
On these multi-well pads, all the wells are drilled prior to
initiating completion activities. At December 31, 2009, we
had drilled a total of 874 gross (727.5 net) wells in the
Fort Worth Basin since we began exploration and development
operations in 2003. In 2009, we completed 97 gross (67.4
net) wells and tied 112 gross (82.6 net) wells into sales.
The portion of the 2010 capital program allocated to our Texas
interests is approximately $340 million. At
December 31, 2009, we had five drilling rigs operating for
us in the Fort Worth Basin, but we expect to utilize four
rigs in this area during most of 2010.
Rocky
Mountain Region
Our Rocky Mountain producing properties are located primarily in
Montana and Wyoming. Production from those properties is
primarily oil from established formations at depths ranging from
1,000 feet to 17,000 feet. At December 31, 2009,
our Rocky Mountain proved reserves were approximately
2.1 MMBbls of oil and 1.6 MMcfe of natural gas and
NGLs for total equivalent reserves of 14 Bcfe. Daily
production from our properties in the Rocky Mountain region
averaged 5.4 MMcfed for 2009. We also hold a 75% working
interest in approximately 105,000 acres (78,000 net) in the
Greater Green River Basin of northern Colorado and southern
Wyoming where we are currently conducting exploratory activities.
Canada
At December 31, 2009, Canadian reserves of 253 Bcfe,
primarily attributable to our CBM projects in Alberta, comprised
10% of our total proved reserves. Canadian production averaged
66.9 MMcfed, representing approximately 20% of our total
2009 production. Canadian production averaged 69 MMcfed
during the fourth quarter of 2009.
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As of December 31, 2009, we had approximately
100,000 gross (72,000 net) undeveloped acres in Alberta,
Canada. In Alberta, we had 2009 capital expenditures of
approximately $24.2 million which included the drilling of
141 gross (36.1 net) productive wells with 179 gross
(67.5 net) wells tied into sales in 2009. During 2010, we
expect to drill approximately 36 gross (29 net) wells, and
similar to 2009, we expect to totally fund these activities by
cash flows from Canadian operations.
We also have approximately 130,000 prospective acres in the Horn
River Basin of Northeast British Columbia. During 2009, we
spent $62.1 million for exploration and facilities and
infrastructure in the Horn River Basin where we have drilled and
cased two wells. The first well, which evaluated the Muskwa
formation, began producing in the third quarter of 2009 and the
second well, which evaluated the Klua formation, commenced
producing late in the fourth quarter of 2009. We expect to
drill two wells and complete one additional well in the Horn
River Basin in 2010. We also entered into a nine-year agreement
with a third party that began in May 2009 for the firm
processing and transportation of natural gas out of the Horn
River Basin with initial volumes of 3 MMcfd increasing to
100 MMcfd by May 2013.
2010
Capital Program
We intend to focus our capital spending program primarily on the
continued development of our properties in Texas and Alberta.
For 2010, we have established a capital program of
$540 million, of which we have allocated $390 million
for drilling and completion activities, $92 million for
gathering and processing facilities (including approximately
$80 million to be funded directly by KGS), $53 million
related to acquisition of additional leasehold interests and
$5 million for other property and equipment. On a regional
basis, approximately $465 million has been allocated to
Texas to drill approximately 100 wells on operated
properties and to complete and tie in approximately
130 wells. Canada has been allocated $52 million to
maintain current production levels and continue exploratory
activities in the Horn River Basin through the drilling of
approximately 38 gross (31 net) wells. The remaining
capital program is spread among our other operating areas. Our
capital program for gathering and processing expenditures for
Texas is $92 million, including $80 million to be
funded by KGS, and $7 million for Canada.
OIL AND
NATURAL GAS RESERVES
In December 2008, the SEC adopted its final rule for
Modernization of Oil and Gas Reporting. The most
significant changes incorporated into our proved reserve process
and related disclosures for 2009 include:
|
|
|
|
|
the use of an unweighted average of the preceding
12-month
first-day-of-the-month
prices for determination of proved reserve values included in
calculating full cost ceiling limitations and for annual proved
reserve disclosures;
|
|
|
limitations regarding the types of technologies that may be used
to reliably establish the classification of proved reserves;
|
|
|
reporting of investments and progress made during the year to
convert proved undeveloped reserves to proved developed
reserves; and,
|
|
|
reporting on the independence and qualifications of our
personnel and independent petroleum engineers who are
responsible for the preparation of our reserve estimates.
|
Our proved reserve estimates and related disclosures for 2009
are presented in compliance with this new guidance. Our 2008
and 2007 proved reserve estimates and related disclosures were
prepared in compliance with the SEC guidance then in effect.
The process of estimating natural gas, NGL and oil reserves is
complex. In order to prepare these estimates, we developed,
maintain and monitor our internal processes and controls for
estimating and recording reserves in compliance with the SEC
rule. Compliance with the SEC reserve guidelines is the primary
responsibility of our reservoir engineering team. We require
that reserve estimates be made by qualified reserve estimators,
as defined by the Society of Petroleum Engineers
standards. Our reservoir engineering team participates in
continuing education to maintain a current understanding of SEC
reserve reporting requirements.
10
Our reservoir engineering team, led by our Vice President -
Reservoir Engineering, is responsible for preparation and
maintenance of our engineering data and review of proved reserve
estimates with our independent petroleum engineers. Our Vice
President - Reservoir Engineering has over 20 years
experience in the oil and gas industry. The reservoir
engineering team reports directly to our Executive Vice
President - Operations and is otherwise independent from
management for our operating areas. Throughout the year, the
reservoir engineering team analyzes the performance of producing
properties for each operating area, identifies significant
reserve additions and revisions and prepares internal proved
reserve estimates. In addition, they are responsible for
maintenance of all reserve engineering data. Integrity of
reserve engineering data is maintained through restricting full
access only to the members of our reservoir engineering team.
Other personnel have read-only access or no access to reserve
engineering data.
Our U.S. and Canadian estimated proved reserves and future
net cash flows have been prepared by Schlumberger Data and
Consulting Services (Schlumberger) and LaRoche
Petroleum Consultants, Ltd. (LaRoche),
respectively. The Schlumberger technical team responsible for
calculating our U.S. reserves has extensive experience in
reservoir evaluation and reserve analysis for tight gas sand,
fractured shale and coalbed methane projects. The LaRoche
technical team responsible for calculating our Canadian reserves
has extensive experience in international reservoir evaluation
and reserve analysis including coalbed methane projects. Prior
to finalizing their reserve estimates, the independent petroleum
engineers results are reviewed in detail by our reservoir
engineering team. Reports of our estimated proved reserves
prepared by these independent petroleum engineers have been
reviewed by our Vice - President Reservoir Engineering and
executive management team.
The Audit Committee of our Board of Directors meets with
executive management, our Vice President - Reservoir
Engineering and the independent petroleum engineers to discuss
the process of and results of reserve estimation. During 2009,
we implemented enhancements to our analytical review of reserve
estimates to include comparisons of our ending proved
undeveloped estimates to our median ending ultimate recoverable
reserves for each of our operating areas and sub-areas. We also
implemented additional reviews of drilling results and proved
undeveloped estimates with our executive management team and our
Audit Committee.
Proved oil and natural gas reserves are the estimated quantities
of oil, natural gas, and NGLs which through analysis of
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic conditions and operating
methods. The term reasonable certainty implies a
high degree of confidence that the quantities of oil, natural
gas and NGLs actually recovered will equal or exceed the
estimate. To achieve reasonable certainty, the technologies
used in the estimation process have been demonstrated to yield
results with consistency and repeatable. Proved developed oil
and natural gas reserves are expected to be recovered through
existing wells with existing equipment and operating methods.
Proved undeveloped oil and natural gas reserves are expected to
be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for re-completion. Proved reserves for undrilled wells are
estimated only where it can be demonstrated that there is
continuity of production from the existing productive formation.
The reserve data presented below are only estimates and are
subject to inherent uncertainties. The determination of oil and
natural gas reserves is based on estimates that are highly
complex and interpretive. Reserve engineering is a subjective
process that depends upon the quality of available data and on
engineering and geological interpretation and judgment.
Although we believe the reserve estimates contained in this
Annual Report are reasonable, reserve estimates are imprecise
and are expected to change as additional information becomes
available. Additional information regarding risks associated
with our proved estimated proved oil and gas reserves may be
found in Item 1A of this Annual Report.
11
The following table summarizes our proved reserves and the
standardized measure of discounted future net cash flows
attributable to them at December 31, 2009 in accordance
with the rules established by the SEC. Our estimates of proved
oil and gas reserves at December 31, 2008 and 2007 were
prepared in compliance with SEC requirements then in effect.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
Proved Undeveloped Reserves
|
|
|
Total Proved Reserves
|
|
|
|
For The Years Ended December 31,
|
|
|
For The Years Ended December 31,
|
|
|
For The Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
1,044,140
|
|
|
|
756,191
|
|
|
|
379,917
|
|
|
|
511,894
|
|
|
|
550,306
|
|
|
|
282,492
|
|
|
|
1,556,034
|
|
|
|
1,306,497
|
|
|
|
662,409
|
|
Canada
|
|
|
223,300
|
|
|
|
278,668
|
|
|
|
260,029
|
|
|
|
29,753
|
|
|
|
53,903
|
|
|
|
68,352
|
|
|
|
253,053
|
|
|
|
332,571
|
|
|
|
328,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,267,440
|
|
|
|
1,034,859
|
|
|
|
639,946
|
|
|
|
541,647
|
|
|
|
604,209
|
|
|
|
350,844
|
|
|
|
1,809,087
|
|
|
|
1,639,068
|
|
|
|
990,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL (MBbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
60,997
|
|
|
|
56,181
|
|
|
|
50,738
|
|
|
|
37,264
|
|
|
|
35,746
|
|
|
|
39,317
|
|
|
|
98,261
|
|
|
|
91,927
|
|
|
|
90,055
|
|
Canada
|
|
|
13
|
|
|
|
8
|
|
|
|
10
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13
|
|
|
|
8
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
61,010
|
|
|
|
56,189
|
|
|
|
50,748
|
|
|
|
37,264
|
|
|
|
35,746
|
|
|
|
39,317
|
|
|
|
98,274
|
|
|
|
91,935
|
|
|
|
90,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
2,467
|
|
|
|
2,509
|
|
|
|
2,763
|
|
|
|
392
|
|
|
|
405
|
|
|
|
311
|
|
|
|
2,859
|
|
|
|
2,914
|
|
|
|
3,074
|
|
Canada
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,467
|
|
|
|
2,509
|
|
|
|
2,763
|
|
|
|
392
|
|
|
|
405
|
|
|
|
311
|
|
|
|
2,859
|
|
|
|
2,914
|
|
|
|
3,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
1,424,924
|
|
|
|
1,108,331
|
|
|
|
700,923
|
|
|
|
737,830
|
|
|
|
767,212
|
|
|
|
520,260
|
|
|
|
2,162,754
|
|
|
|
1,875,543
|
|
|
|
1,221,183
|
|
Canada
|
|
|
223,378
|
|
|
|
278,716
|
|
|
|
260,089
|
|
|
|
29,753
|
|
|
|
53,903
|
|
|
|
68,352
|
|
|
|
253,131
|
|
|
|
332,619
|
|
|
|
328,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,648,302
|
|
|
|
1,387,047
|
|
|
|
961,012
|
|
|
|
767,583
|
|
|
|
821,115
|
|
|
|
588,612
|
|
|
|
2,415,885
|
|
|
|
2,208,162
|
|
|
|
1,549,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009 (1)
|
|
|
2008 (2)
|
|
|
2007 (2)
|
|
|
Representative prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas Henry Hub
|
|
$
|
3.87
|
|
|
$
|
5.71
|
|
|
$
|
6.80
|
|
Natural gas AECO
|
|
|
3.76
|
|
|
|
5.44
|
|
|
|
6.35
|
|
NGL Mont Belvieu, Texas
|
|
|
24.94
|
|
|
|
21.65
|
|
|
|
57.35
|
|
Oil WTI Cushing
|
|
|
61.18
|
|
|
|
44.60
|
|
|
|
95.98
|
|
Standardized measure of discounted future net cash
flows (3),
after income tax (in millions)
|
|
$
|
1,182.7
|
|
|
$
|
1,794.3
|
|
|
$
|
2,169.2
|
|
|
|
|
|
|
(1)
|
The natural gas and crude oil
prices as of each respective year end were based, respectively,
on the unweighted average of the preceding
12-month
first-day-of-the-month
NYMEX Henry Hub and AECO prices per MMBtu and NYMEX prices per
Bbl, adjusted to reflect local differentials.
|
|
|
|
(2)
|
The natural gas and oil prices as
of December 31, 2008 and 2007 were based, respectively, on
last day-of-the-year price for NYMEX Henry Hub and AECO price
per MMBtu and NYMEX price per Bbl, adjusted to reflect local
differentials.
|
|
|
|
(3)
|
Determined based on year end
unescalated costs in accordance with the guidelines of the SEC,
discounted at 10% per annum.
|
|
PROVED
UNDEVELOPED RESERVES
As of December 31, 2009, we had total proved undeveloped
reserves of 767.6 Bcfe comprised of 737.8 Bcfe in
Texas on 281 well locations and 29.8 Bcfe in Alberta,
Canada on 260 well locations. All of the 541 well
locations are slated for development before the end of 2014.
12
Our 2009 drilling and completion activities related to our
December 31, 2008 proved undeveloped locations were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2009
|
|
|
|
Drilled
|
|
|
Completions
|
|
|
Producing
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States
|
|
|
66.0
|
|
|
|
39.9
|
|
|
|
23.0
|
|
|
|
10.9
|
|
|
|
18.0
|
|
|
|
10.6
|
|
Canada
|
|
|
37.0
|
|
|
|
18.6
|
|
|
|
30.0
|
|
|
|
14.1
|
|
|
|
24.0
|
|
|
|
10.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
103.0
|
|
|
|
58.5
|
|
|
|
53.0
|
|
|
|
25.0
|
|
|
|
42.0
|
|
|
|
20.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our gross capital costs for a Texas Barnett Shale well from
preparation of the multi-well drilling pad through the
initiation of production generally range from $2.0 million
to $5.0 million depending on factors such as the area, the
depth and lateral length of each well and its distance to
central facilities. On each multi-well drilling pad, we drill
all the wells prior to initiation of completion activities. As
a result, we maintain an inventory of drilled wells awaiting
completion. During 2010, we expect to spend $268.2 million
to drill, complete and tie-in wells on proved locations.
In Alberta, the gross capital costs for a typical CBM well from
pre-drilling preparation through the initiation of production
generally range from $0.2 million to $0.4 million
depending upon number of coal seams, depth and distance to a
gathering system. As our drilling and completion operations are
limited by the restriction of the movement of rigs and other
equipment due to wet weather and spring thaw, we expect to
maintain an inventory of drilled wells awaiting completion and
completed wells awaiting tie-in to sales lines. During 2010, we
expect to spend capital of $7.7 million to drill, complete
and tie-in wells on proved locations.
At December 31, 2009, none of our inventory of proved
undeveloped drilling locations has been recognized as proved
reserves for five years or longer. Currently, we anticipate
that all our proved undeveloped reserves will be developed prior
to the end of 2014.
DEVELOPMENT
AND EXPLORATION ACTIVITIES AT YEAR-END
At December 31, 2009, we had five drilling rigs under lease
in Texas, including one rig operating on a proved undeveloped
location, two rigs operating on unproved locations and two rigs
mobilizing, to a proved undeveloped location and an unproved
well location. Additionally, completion work was in progress on
five proved Texas wells with 207 (153.9 net) wells awaiting
completion or tie-in to sales. One drilling rig was operating
on an unproved location in British Columbia and 189 wells
(129.0 net) in Alberta were awaiting completion or tie-in to
sales lines.
13
DRILLING
ACTIVITY
During the periods indicated, we drilled the following
exploratory and development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive (1)
|
|
|
154.0
|
|
|
|
93.2
|
|
|
|
292.0
|
|
|
|
255.7
|
|
|
|
258.0
|
|
|
|
226.2
|
|
Non-productive
|
|
|
-
|
|
|
|
-
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
-
|
|
|
|
-
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive (2)
|
|
|
141.0
|
|
|
|
36.1
|
|
|
|
372.0
|
|
|
|
155.9
|
|
|
|
351.0
|
|
|
|
179.1
|
|
Non-productive
|
|
|
-
|
|
|
|
-
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
295.0
|
|
|
|
129.3
|
|
|
|
666.0
|
|
|
|
413.6
|
|
|
|
609.0
|
|
|
|
405.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
4.0
|
|
|
|
4.0
|
|
|
|
5.0
|
|
|
|
4.1
|
|
|
|
32.0
|
|
|
|
19.2
|
|
Non-productive
|
|
|
-
|
|
|
|
-
|
|
|
|
2.0
|
|
|
|
2.0
|
|
|
|
4.0
|
|
|
|
3.2
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
2.0
|
|
|
|
2.0
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5.0
|
|
|
|
5.0
|
|
Non-productive
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6.0
|
|
|
|
6.0
|
|
|
|
7.0
|
|
|
|
6.1
|
|
|
|
41.0
|
|
|
|
27.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
301.0
|
|
|
|
135.3
|
|
|
|
669.0
|
|
|
|
415.7
|
|
|
|
646.0
|
|
|
|
429.5
|
|
Non-productive
|
|
|
-
|
|
|
|
-
|
|
|
|
4.0
|
|
|
|
4.0
|
|
|
|
4.0
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
301.0
|
|
|
|
135.3
|
|
|
|
673.0
|
|
|
|
419.7
|
|
|
|
650.0
|
|
|
|
432.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
U.S. development drilling includes non-operated drilling of
37 wells (3.0 net), 36 wells (16.1 net) and
14 wells (7.2 net) for 2009, 2008 and 2007, respectively.
|
|
|
(2)
|
Canadian development drilling includes non-operated drilling of
88 wells (8.1 net), 170 wells (15.3 net) and
130 wells (16.1 net) for 2009, 2008 and 2007, respectively.
|
VOLUMES,
SALES PRICES AND OIL AND GAS PRODUCTION EXPENSE
The discussion of volumes produced from revenue generated by and
cost associated with operating our properties included in
Managements Discussion and Analysis in Item 7 of this
Annual Report is incorporated herein by reference.
DELIVERY
COMMITMENTS AND PURCHASERS OF NATURAL GAS, NGLs AND
OIL
We have a written commitment to provide a third-party
25,332 MMBtud through July 2019 at market-based prices for
delivery at the Gulf Crossing Pipeline from the Crosstex North
Texas Pipeline. We expect to deliver our natural gas production
as well as natural gas attributable to third parties from our
Alliance wells. For the month ended December 31, 2009, we
sold approximately 90,000 MMBtud from our Alliance wells.
We expect production from our Alliance properties to increase as
we continue to develop our leasehold interests in the area
through 2012 and beyond. Additionally, we estimate that we had
approximately 70,000 MMBtud available for delivery under
the commitment from our oil and gas interests in the Barnett
14
Shale in the Fort Worth Basin. We currently have no other
firm commitments for the sale of our Barnett Shale production
for a period longer than 12 months.
We sell natural gas, NGLs and oil to a variety of customers,
including utilities, major oil and natural gas companies or
their affiliates, industrial companies, large trading and energy
marketing companies and other users of petroleum products.
Because our products are commodity products sold primarily on
the basis of price and availability, we are not dependent upon
one purchaser or a small group of purchasers. Accordingly, the
loss of any single purchaser would not materially affect our
revenue. During 2009, Louis Dreyfus Natural Gas Corp., Dynegy
Liquids Marketing and Trading and BG Energy Merchants, the
largest purchasers of our products, accounted for approximately
15%, 13% and 10% of our total natural gas, NGL and oil revenue,
respectively.
ACQUISITION,
EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES
The following table summarizes our acquisition, exploration and
development costs incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved acreage
|
|
$
|
118
|
|
|
$
|
-
|
|
|
$
|
118
|
|
Unproved acreage
|
|
|
11,300
|
|
|
|
2,658
|
|
|
|
13,958
|
|
Development costs
|
|
|
341,658
|
|
|
|
24,179
|
|
|
|
365,837
|
|
Exploration costs
|
|
|
32,798
|
|
|
|
59,402
|
|
|
|
92,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
385,874
|
|
|
$
|
86,239
|
|
|
$
|
472,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved acreage
|
|
$
|
787,172
|
|
|
$
|
-
|
|
|
$
|
787,172
|
|
Unproved acreage
|
|
|
484,770
|
|
|
|
54,048
|
|
|
|
538,818
|
|
Development costs
|
|
|
836,032
|
|
|
|
68,629
|
|
|
|
904,661
|
|
Exploration costs
|
|
|
30,161
|
|
|
|
10,280
|
|
|
|
40,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,138,135
|
|
|
$
|
132,957
|
|
|
$
|
2,271,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved acreage
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Unproved acreage
|
|
|
17,031
|
|
|
|
31,448
|
|
|
|
48,479
|
|
Development costs
|
|
|
648,632
|
|
|
|
67,608
|
|
|
|
716,240
|
|
Exploration costs
|
|
|
75,862
|
|
|
|
11,953
|
|
|
|
87,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
741,525
|
|
|
$
|
111,009
|
|
|
$
|
852,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PRODUCTIVE
OIL AND GAS WELLS
The following table summarizes productive wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
|
Natural Gas
|
|
|
Oil
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States
|
|
|
834.0
|
|
|
|
697.0
|
|
|
|
198.0
|
|
|
|
194.0
|
|
Canada
|
|
|
2,815.0
|
|
|
|
1,297.3
|
|
|
|
4.0
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3,649.0
|
|
|
|
1,994.3
|
|
|
|
202.0
|
|
|
|
194.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL AND
GAS ACREAGE
Our principal natural gas and oil properties consist of
non-producing and producing oil and gas leases and mineral
acreage, including reserves of natural gas and oil in place.
Developed acres are defined as acreage allocated to wells that
are producing or capable of producing. Undeveloped acres are
acres on which wells have not been drilled or completed to a
point that would permit the production of commercial reserves,
15
regardless of whether such acreage contains proved reserves.
Gross acres are the total number of acres in which we have a
working interest. Net acres are the sum of our fractional
interests owned in the gross acres.
The following table indicates our interest in developed and
undeveloped acreage:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
|
Developed Acreage
|
|
|
Undeveloped Acreage
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Texas
|
|
|
75,752
|
|
|
|
66,376
|
|
|
|
553,800
|
|
|
|
468,491
|
|
Other
|
|
|
116,988
|
|
|
|
107,973
|
|
|
|
198,732
|
|
|
|
154,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
192,740
|
|
|
|
174,349
|
|
|
|
752,532
|
|
|
|
622,581
|
|
Canada
|
|
|
458,933
|
|
|
|
272,693
|
|
|
|
249,231
|
|
|
|
222,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
651,673
|
|
|
|
447,042
|
|
|
|
1,001,763
|
|
|
|
845,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes information regarding the total
number of net undeveloped acres as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Expirations
|
|
|
2011 Expirations
|
|
|
2012 Expirations
|
|
|
|
Net
|
|
|
|
|
|
Net Acres with
|
|
|
|
|
|
Net Acres with
|
|
|
|
|
|
Net Acres with
|
|
|
|
Undeveloped
|
|
|
Net Acres
|
|
|
Options
|
|
|
Net Acres
|
|
|
Options
|
|
|
Net Acres
|
|
|
Options
|
|
|
|
Acres
|
|
|
|
|
|
to Extend
|
|
|
|
|
|
to Extend
|
|
|
|
|
|
to Extend
|
|
|
Texas
|
|
|
468,491
|
|
|
|
352,858
|
|
|
|
22,236
|
|
|
|
54,967
|
|
|
|
1,032
|
|
|
|
18,580
|
|
|
|
2,378
|
|
Other U.S.
|
|
|
154,090
|
|
|
|
28,773
|
|
|
|
128
|
|
|
|
28,219
|
|
|
|
5,628
|
|
|
|
16,171
|
|
|
|
-
|
|
Canada
|
|
|
222,524
|
|
|
|
25,379
|
|
|
|
-
|
|
|
|
70,043
|
|
|
|
-
|
|
|
|
83,006
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
845,105
|
|
|
|
407,010
|
|
|
|
22,364
|
|
|
|
153,229
|
|
|
|
6,660
|
|
|
|
117,757
|
|
|
|
2,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the acreage scheduled to expire can be held through
drilling operations. We believe that we have the ability to
retain all of the expiring acreage that we feel will provide
economic production either through drilling activities or
through the exercise of extension options.
COMPETITION
We compete for acquisitions of prospective oil and natural gas
properties and oil and gas reserves. We also compete for
drilling rigs and equipment used to drill for and produce oil
and gas. Our competitive position is dependent upon our ability
to recruit and retain geological, engineering and management
expertise. We believe that the location of our leasehold
acreage, our exploration and production expertise and the
experience and knowledge of our management enable us to compete
effectively in our core operating areas. However, we face
competition from a substantial number of other companies, many
of which have larger technical staffs and greater financial and
operational resources than we do and from companies in other,
but potentially related, industries.
GOVERNMENTAL
REGULATION
Our operations are affected from time to time in varying degrees
by political developments and U.S. and Canadian federal,
state, provincial and local laws and regulations. In
particular, natural gas and oil production and related
operations are, or have been, subject to price controls, taxes
and other laws and regulations relating to the industry.
Failure to comply with such laws and regulations can result in
substantial penalties. The regulatory burden on the industry
increases our cost of doing business and affects our
profitability. We do not anticipate any significant challenges
in complying with laws and regulations applicable to our
operations.
SAFETY
REGULATION
We are subject to a number of federal, provincial and state laws
and regulations, whose purpose is to protect the health and
safety of workers, both generally and within our industry.
Regulations overseen by OSHA, the EPA and other agencies
require, among other matters, that information be maintained
concerning hazardous materials used or produced in our
operations and that this information be provided to employees,
16
state and local government authorities and citizens. We are
also subject to safety regulations which are designed to prevent
or minimize the consequences of catastrophic releases of toxic,
reactive, flammable or explosive chemicals.
ENVIRONMENTAL
MATTERS
We are subject to stringent and complex U.S. and Canadian
federal, state, provincial and local environmental laws,
regulations and permits and international environmental
conventions, including those relating to the generation,
storage, handling, use, disposal, movement and remediation of
natural gas, NGLs, oil and other hazardous materials; the
emission and discharge of such materials to the ground, air and
water; wildlife protection; the storage, use and treatment of
water; and the placement, operation and reclamation of wells.
These requirements are a significant consideration for us as our
operations involve the generation, storage, handling, use,
disposal, movement and remediation of natural gas, NGLs, oil and
other hazardous or regulated materials and the emission and
discharge of such materials to the environment. If we violate
these requirements, or fail to obtain and maintain the necessary
permits, we could be fined or otherwise sanctioned, which
sanctions could include the imposition of fines and penalties
and orders enjoining future operations. Pursuant to such laws,
regulations and permits, we have made and expect to continue to
make capital and other compliance expenditures.
We could be liable for any environmental contamination at our or
our predecessors currently or formerly owned or operated
properties or third party waste disposal sites. Certain
environmental laws, including CERCLA, more commonly known as
Superfund, impose joint and several strict liability for
releases of hazardous substances at such properties or sites,
without regard to fault or the legality of the original
conduct. In addition to potentially significant investigation
and remediation costs, environmental contamination can give rise
to claims from governmental authorities and other third parties
for fines or penalties, natural resource damages, personal
injury and property damage. State regulators in Texas are also
becoming increasingly focused on air emissions from our
industry, including volatile organic compound emissions. This
increased scrutiny could lead to heightened enforcement of
existing regulations as well as the imposition of new measures
to control our emissions or curtail our operations.
Environmental laws, regulations and permits, and the enforcement
and interpretation thereof, change frequently and generally have
become more stringent over time. For example, various
U.S. federal and state initiatives are underway to
regulate, or further investigate the environmental impacts of,
hydraulic fracturing. Such initiatives could require us to
disclose the chemicals we use in the fracturing process, which
disclosure may result in increased scrutiny or third party
claims, or otherwise result in operational delays, liabilities
and increased costs. In addition, from time to time, initiatives
are proposed that could further regulate certain exploration and
production by-products as hazardous wastes and subject them to
more stringent requirements. If enacted, such initiatives could
require us to incur substantial costs for compliance.
GHG emission regulation is also becoming more stringent. We are
currently required to report annual GHG emissions from some of
our operations, and additional GHG emission related requirements
are in various stages of development. For example, the
U.S. Congress is considering legislation that would
establish a nationwide
cap-and-trade
system for GHGs, and the EPA has proposed regulating GHG
emissions from stationary sources pursuant to the Prevention of
Significant Deterioration and Title V provisions of the
federal Clean Air Act which might require us to modify existing
or obtain new air permits or install emission control
technology. Any regulation of GHG emissions, including through
a
cap-and-trade
system, technology mandate, emissions tax, reporting requirement
or other program, could restrict our operations and subject us
to significant costs, including those relating to emission
credits, pollution control equipment, monitoring and reporting.
Although there is still significant uncertainty surrounding the
scope, timing and effect of future GHG regulation, any such
regulation could have a material adverse impact on our business,
financial condition, reputation and operating performance.
In addition, to the extent climate change results in warmer
temperatures or more severe weather, our operations may be
disrupted. For example, storms in the Gulf of Mexico could
damage downstream pipeline infrastructure causing a decrease in
takeaway capacity and potentially requiring us to curtail
production. In
17
addition, warmer temperatures might shorten the time during
winter months when we can access certain remote production areas
resulting in decreased exploration and production activity.
AVAILABILITY
OF REPORTS AND CORPORATE GOVERNANCE DOCUMENTS
We make available free of charge on our internet website,
www.qrinc.com, our Annual Reports on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of
1934 as soon as reasonably practicable after we electronically
file or furnish such material to the SEC. Additionally,
charters for the committees of our Board and our Corporate
Governance Guidelines and Code of Business Conduct and Ethics
can be found on our internet website under the heading
Corporate Governance. Our website and the
information contained therein or connected thereto shall not be
deemed to be incorporated into this Annual Report.
EMPLOYEES
As of February 15, 2010, we had 596 employees, none of
whom have collective bargaining agreements.
EXECUTIVE
OFFICERS OF THE REGISTRANT
The following information is provided with respect to our
executive officers as of February 15, 2010.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
|
Position(s)
|
|
Thomas F. Darden
|
|
|
56
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Director, Chairman of the Board
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Glenn Darden
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Director, President and Chief Executive Officer
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Anne Darden Self
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Director, Vice President - Human Resources
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Jeff Cook
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Executive Vice President - Operations
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Philip W. Cook
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Senior Vice President - Chief Financial Officer
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John C. Cirone
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Senior Vice President, General Counsel and Secretary
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John C. Regan
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Vice President, Controller and Chief Accounting Officer
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Robert N. Wagner
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Vice President - Reservoir Engineering
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Officers are elected by our Board of Directors and hold office
at the pleasure of the Board until their successors are elected
and qualified. Thomas F. Darden, Glenn Darden and Anne Darden
Self are siblings. Messrs. Jeff Cook and Philip W. Cook are
not related. The following biographies describe the business
experience of our executive officers:
THOMAS F. DARDEN has served on our Board of Directors
since December 1997 and became Chairman of the Board in March
1999. He was elected as a director of Quicksilver Gas Services
GP LLC in July 2007. Mr. Darden was previously employed by
Mercury Exploration Company for 22 years in various
executive level positions.
GLENN DARDEN has served on our Board of Directors since
December 1997 and became our Chief Executive Officer in December
1999. He was elected as a director of Quicksilver Gas Services
GP LLC in March 2007. He served as our Vice President until he
was elected President and Chief Operating Officer in March
1999. Prior to that time, he served with Mercury for
18 years, the last five as Executive Vice President.
Mr. Darden previously worked as a geologist for Mitchell
Energy Company LP (subsequently merged with Devon Energy).
ANNE DARDEN SELF has served on our Board of Directors
since September 1999, and became our Vice President
Human Resources in July 2000. She is also currently President
of Mercury, where she has worked since 1992. From 1988 to 1991,
she was employed by Banc PLUS Savings Association in Houston,
Texas, initially as Marketing Director and for three years
thereafter as Vice President of Human Resources. She worked
from 1987 to 1988 as an Account Executive for NW Ayer
Advertising Agency. Prior to 1987, she spent several years in
real estate management.
JEFF COOK became our Executive Vice President
Operations in January 2006, after serving as our Senior Vice
President Operations since July 2000. From 1979 to
1981, he held the position of Operations Supervisor with Western
Company of North America. In 1981, he became a District
Production
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Superintendent for Mercury Production Company and became Vice
President of Operations in 1991 and Executive Vice President in
1998 of Mercury Production Company before joining us.
PHILIP W. COOK became our Senior Vice
President Chief Financial Officer in October 2005.
From October 2004 until October 2005, Mr. Cook served as
President and Chief Financial Officer of a private chemical
company. From August 2001 until September 2004, he served as
Vice President and Chief Financial Officer of a private oilfield
service company. From August 1993 to July 2001, he served in
various capacities, including Vice President and Controller,
Vice President and Chief Information Officer and Vice President
of Audit, of Burlington Resources Inc. (subsequently merged with
ConocoPhillips), a public independent oil and gas company
engaged in exploration, development, production and marketing.
JOHN C. CIRONE was named as our Senior Vice President,
General Counsel and Secretary in January 2006, after serving as
our Vice President, General Counsel and Secretary since July
2002. Mr. Cirone was employed by Union Pacific Resources
(subsequently merged with Anadarko Petroleum Corporation) from
1978 to 2000. During that time, he served in various positions
in the Law Department, and from 1997 to 2000 he was the Manager
of Land and Negotiations. In 2000, he became Assistant General
Counsel of Union Pacific Resources. After leaving Union Pacific
Resources in August 2000, Mr. Cirone was engaged in the
private practice of law prior to joining us in July 2002.
JOHN C. REGAN became our Vice President, Controller and
Chief Accounting Officer in September 2007. He is a Certified
Public Accountant with more than 15 years of combined
public accounting, corporate finance and financial reporting
experience. Mr. Regan joined us from Flowserve Corporation
where he held various management positions of increasing
responsibility from 2002 to 2007, including Vice President of
Finance for the Flow Control Division and Director of Financial
Reporting. He was also a senior manager specializing in the
energy industry in the audit practice of PricewaterhouseCoopers,
where he was employed from 1994 to 2002.
ROBERT N. WAGNER became our Vice President
Reservoir Engineering in December 2002, after serving as our
Vice President Engineering since July 1999. From
January 1999 to July 1999, he was our manager of eastern region
field operations. From November 1995 to January 1999,
Mr. Wagner held the position of District Engineer with
Mercury. Prior to 1995, he was with Mesa, Inc. (subsequently
merged with Parker and Parsley) for more than eight years and
served as both drilling engineer and production engineer.
19
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 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 oil prices. These prices also
affect the amount of cash flow available to service our debt,
fund our capital program and 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 expected
future prices. Lower prices may also reduce the amount of
natural gas, NGLs and oil that we can economically produce.
While prices for natural gas, NGLs and oil may be favorable at
any point in time, they fluctuate widely, particularly as
evidenced by price movements in 2008 and 2009. Among the
factors that can cause these fluctuations are:
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domestic and foreign demand for natural gas, NGLs and oil;
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the level and locations of domestic and foreign natural gas,
NGLs and oil supplies;
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the quality, price and availability of alternative fuels;
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weather conditions;
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domestic and foreign governmental regulations;
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impact of trade organizations, such as OPEC;
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political conditions in oil, NGLs and natural gas producing
regions; and
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worldwide economic conditions.
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Due to the volatility of natural gas and oil prices and the
inability to control the factors that influence them, we cannot
predict future pricing levels.
If
natural gas, NGL or 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 oil and natural gas reserves are
capitalized and accumulated in separate country cost centers for
the U.S. and Canada. These capitalized costs are amortized
based on production for each country cost center. Each
capitalized cost pool cannot exceed the net present value of the
underlying natural gas, NGL and oil reserves. Impairment to the
carrying value of our oil and gas properties was recognized in
the fourth quarter of 2008 and the first, second and fourth
quarters of 2009 and could occur again in the future if natural
gas, NGL or oil prices utilized in determining reserve values
cause the value of our reserves to decrease. Increased
operating and capitalized costs without incremental increases in
reserves value 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
non-cash expense, 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 oil reserves is
complex. In order to prepare these estimates, we and our
independent reserve engineers must project future production
rates and timing of future
20
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. In additions to interpreting available
technical data, we must also analyze other 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.
Actual future production, natural gas, NGL and oil prices and
revenue, taxes, development expenditures, operating expenses and
quantities of recoverable natural gas and 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 our filings with the SEC. 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, 2009, approximately 32% of our estimated
proved reserves were undeveloped. Recovery of undeveloped
reserves requires additional capital expenditures and successful
drilling and completion operations. Our reserve estimates
assume that we will make significant capital expenditures to
develop our reserves. Although we have prepared estimates of
our reserves using SEC requirements, actual prices and costs may
vary from these estimates, development may not occur as
scheduled or actual results may not be as estimated prior to
drilling.
The present value of future net cash flows disclosed in
Item 8 of our Annual Report on
Form 10-K
is not necessarily the fair value of our estimated proved
natural gas and oil reserves. In accordance with SEC
requirements, the estimated discounted future net cash flows
from proved reserves are based on prices determined on an
unweighted average of the preceding
12-month
first-day-of-the-month
prices adjusted for local differentials and operating and
development costs as of period end. Actual future prices and
costs may be materially higher or lower than the prices and
costs used in our estimate. Any changes in consumption by
natural gas, NGL and oil purchasers or in governmental
regulations or taxation will also affect actual future net cash
flows. The timing of both the production and the costs from the
development and production of natural gas and 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 our reserves actual fair
value.
Our
production is concentrated in a small number of geographic
areas.
Approximately 78% of our 2009 production was from Texas and
approximately 20% was from Alberta, Canada. Because of our
concentration in these geographic areas, any regional events
that increase costs, reduce or disrupt availability of equipment
or supplies, reduce demand or limit production, including
weather and natural disasters, may impact us more significantly
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
U.S. 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, aboriginal claims, changes in laws and
policies governing operations of foreign-based companies,
currency restrictions and exchange rate fluctuations. For
example, in addition to federal regulation, each province has
legislation and regulations which govern land tenure, royalties,
production rates and other matters. The royalty regime is a
significant factor in the profitability of oil and natural gas
production. Royalties payable on production from lands other
than Crown lands are determined by negotiations between the
mineral owner and the lessee. Crown royalties are determined by
government regulation and are generally calculated as a
percentage of the value of the gross production, and the rate of
royalties payable generally depends in part on prescribed
reference prices, well productivity, geographical
21
location, field discovery date and the type or quality of the
petroleum product produced. Laws and policies of the United
States affecting foreign trade and taxation may also adversely
affect our Canadian operations.
In addition, the level of activity in the Canadian oil and
natural gas industry is influenced by seasonal weather
patterns. Wet weather and spring thaw may make the ground
unstable. Consequently, municipalities and provincial
transportation departments enforce road bans that restrict the
movement of rigs and other heavy equipment, thereby reducing our
activity levels. Also, certain of our oil and natural gas
producing areas are located in areas that are inaccessible other
than during the winter months because the ground surrounding the
sites in these areas consists of swampy terrain. Therefore,
seasonal factors and unexpected weather patterns may lead to
declines in exploration and production activity.
If we
are unable to obtain needed capital or financing on satisfactory
terms, our ability to replace our reserves or to maintain
current production levels may be limited.
Historically, we have used our cash flow from operations,
borrowings under our Senior Secured Credit Facility and
issuances of equity and debt to fund our capital program,
working capital needs and acquisitions. Our capital program may
require additional financing above the level of cash generated
by our operations to fund our growth. If our cash flow from
operations decreases as a result of lower petroleum prices or
otherwise, our ability to expend the capital necessary to
replace our reserves or to maintain current production may be
limited, resulting in decreased production over time. If our
cash flow from operations is insufficient to satisfy our
financing needs, we cannot be certain that additional financing
will be available to us on acceptable terms or at all. Our
ability to obtain bank financing or to access the capital
markets for future equity or debt offerings may be limited by
our financial condition or general economic conditions at the
time of any such financing or offering. Even if we are
successful in obtaining the necessary funds, the terms of such
financings could have a material adverse effect on our business,
results of operations and financial condition. If 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.
Our
business involves many hazards and operational risks, some of
which may not be insurable. The occurrence of a significant
accident or other event that is not insured or not adequately
insured could curtail our operations and have a material adverse
effect on our business, results of operations and financial
condition.
Our operations are subject to many risks inherent in the oil and
natural gas industry, including operating hazards such as well
blowouts, explosions, uncontrollable flows of 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 production depends on the proximity of reserves to, and
the capacity of, natural gas and oil gathering systems,
treatment plants, pipelines and trucking or terminal facilities.
U.S. and Canadian federal, state, local and provincial
regulation relating to 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 oil.
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. Some of our insurance policies
cover our subsidiaries, including KGS. As a result, if a named
insureds claim is paid under such policy it would reduce
the coverage available to us. We are not insured against all
environmental incidents, claims or damages that might occur.
Any significant accident or event that is not adequately insured
could adversely affect our business, results of operations and
financial condition. In addition, we may be unable to
economically obtain or maintain the insurance that we desire.
As a result of market conditions, premiums and deductibles for
certain of our insurance policies could escalate further. In
some instances, certain insurance could become unavailable or
available only at reduced coverage levels. Any type of
catastrophic event could have a material adverse effect on our
business, results of operation and financial condition.
22
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 purchase proved
reserves. In order to increase reserves and production, we must
continue our development drilling or undertake other replacement
activities. We strive 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 40% limited partner interest in BBEP, but 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 BBEPs business and
operations. Moreover, the management of BBEP has discretion
over the amount, if any, that they distribute to unitholders.
BBEP suspended distributions for all of 2009 and will not resume
distributions until the first quarter and payable the second
quarter of 2010.
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, including BBEP
suspending distributions on its units, could adversely affect
the market price of BBEP limited partner units. Impairment to
the carrying value of BBEP limited partnership units was
recognized in both the fourth quarter of 2008 and the first
quarter of 2009, and could occur again in the future if the
market price for BBEP units declines. In the event of
impairment of our BBEP units, we reduce the carrying value of
our BBEP units and recognize non-cash expense, 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.
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. Although we have diminished control over KGS assets
and operations, we are subject to the risks associated with
KGS business and operations, including, but not limited to:
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changes in general economic conditions;
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fluctuations in natural gas prices;
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failure or delays in us and third parties achieving expected
production from natural gas projects;
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competitive conditions in the midstream industry;
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actions taken on non-performance by third parties, including
suppliers, contractors, operators, processors, transporters and
customers;
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changes in the availability and cost of capital;
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operating hazards, natural disasters, weather-related delays,
casualty losses and other matters beyond our control;
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construction costs or capital expenditures exceeding estimated
or budgeted amounts;
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the effects of existing and future laws and governmental
regulations;
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the effects of future litigation; and
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other factors discussed in KGS Annual Report on
Form 10-K
and as are or may be detailed from time to time in KGS
public announcements and other filings with the SEC.
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We
cannot control the operations of gas processing, liquids
fractionation and transportation facilities we do not own or
operate.
We deliver our production to market through gathering,
fractionation and transportation systems that we do not own.
Since we do not own or operate these assets, their continuing
operation is not within our control.
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If any of these pipelines and other facilities becomes
unavailable or capacity constrained, it could have a material
adverse effect on our business, financial condition and results
of operations.
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 adversely affect our ability
to operate our business.
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 and 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
better able to absorb the burden of any changes in federal,
state, provincial and local laws and regulations than we can,
which would adversely affect our competitive position. These
competitors may be able to pay more for exploratory prospects
and producing 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 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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our production could be materially less than expected; or
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the other parties to the hedging contracts could fail to perform
their contractual obligations.
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If market prices for our production exceed collar ceilings or
swap prices, we would be required to make monthly cash payments,
which could materially adversely affect our liquidity. If we
choose not to engage in hedging arrangements in the future, we
could be more affected by changes in natural gas, NGL and 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 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
difficulty in obtaining, or material increases in the cost of,
drilling equipment, crews and associated supplies, equipment and
services. In addition, drilling operations may be curtailed,
delayed or canceled as a result of unexpected drilling
conditions, including urban drilling, and possible title
issues. Any such delays and price increases could adversely
affect our ability to execute our drilling program and our
results of operations and financial condition.
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Our
activities are regulated by complex laws and regulations that
can adversely affect the cost, manner or feasibility of doing
business.
Our 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:
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discharge permits for drilling operations;
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water obtained for drilling purposes;
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drilling permits and bonds;
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reports concerning operations;
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spacing of wells;
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disposal wells;
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unitization and pooling of properties; and
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taxation.
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From time to time, regulatory agencies have imposed price
controls and limitations on production by restricting the rate
of flow of natural gas and oil wells below actual production
capacity to conserve supplies of natural gas and oil. We also
are subject to changing and extensive tax laws, the effects of
which cannot be predicted.
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.
We are
subject to environmental laws, regulations and permits,
including greenhouse gas requirements that may expose us to
significant costs, liabilities and obligations.
We are subject to stringent and complex U.S. and Canadian
federal, state, provincial and local environmental laws,
regulations and permits and international environmental
conventions, relating to, among other things, the generation,
storage, handling, use, disposal, gathering, movement and
remediation of natural gas, NGLs, oil and other hazardous
materials; the emission and discharge of such materials to the
ground, air and water; wildlife protection; the storage, use and
treatment of water; the placement, operation and reclamation of
wells; and the health and safety of our employees. Failure to
comply with these environmental requirements may result in our
being subject to litigation, fines or other sanctions, including
the revocation of permits and suspension of operations. We
expect to continue to incur significant capital and other
compliance costs related to such requirements.
We could be liable for any environmental contamination at our or
our predecessors currently or formerly owned or operated
properties or third party waste disposal sites. Certain
environmental laws, including CERLA, more commonly know as
Superfund, impose joint and several strict liability for
releases of hazardous substances at such properties or sites,
without regard to fault or the legality of the original
contract. In addition to potentially significant investigation
and remediation costs, such matters can give rise to claims from
governmental authorities and other third parties for fines or
penalties, natural resource damages, personal injury and
property damage. State regulators in Texas are also becoming
increasingly focused on air emissions from our industry,
including volatile organic compound emissions. This increased
scrutiny could lead to heightened enforcement of existing
regulations as well as the imposition of new measures to control
our emissions or curtail our operations.
These laws, regulations and permits, and the enforcement and
interpretation thereof, change frequently and generally have
become more stringent over time. In particular, requirements
pertaining to air emissions, including volatile organic compound
emissions, have been implemented or are under development that
could lead us to incur significant costs or obligations or
curtail our operations. For example, GHG emission regulation is
becoming more stringent. We are currently required to report
annual GHG emissions from some
25
of our operations, and additional GHG emission related
requirements are in various stages of development. The
U.S. Congress is considering legislation that would
establish a nationwide
cap-and-trade
system for GHGs. In addition, the EPA has proposed regulating
GHG emissions from stationary sources pursuant to the Prevention
of Significant Deterioration and Title V provisions of the
federal Clean Air Act. If enacted, such regulations could
require us to modify existing or obtain new permits, implement
additional pollution control technology, curtail operations or
increase significantly our operating costs. Any regulation of
GHG emissions, including through a
cap-and-trade
system, technology mandate, emissions tax, reporting requirement
or other program, could adversely affect our business, financial
condition, reputation, operating performance and product
demand. In addition, to the extent climate change results in
warmer temperatures or more severe weather, our or our
customers operations may be disrupted, which could curtail
our exploration and production activity, increase operating
costs and reduce product demand. In addition, various
U.S. federal and state initiatives are underway to
potentially regulate or further investigate the environmental
impacts of hydraulic fracturing, a practice that involves the
pressurized injection of water, chemicals and other substances
into rock formations to stimulate hydrocarbon production. Such
initiatives could require the public disclosure of chemicals
used in the fracturing process, which disclosure may result in
increased scrutiny or third party claims, or otherwise result in
operational delays, liabilities and increased costs.
Our costs, liabilities and obligations relating to environmental
matters could have a material adverse effect on our business,
reputation, 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
oil prices and their effects on our financial condition, results
of operations and 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:
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make it more difficult for us to satisfy our obligations with
respect to our debt;
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require us to dedicate a substantial portion of our cash flow
from operations to payments on our debt, thereby reducing the
amount of our cash flow available for working capital, capital
expenditures, acquisitions and other general corporate purposes;
|
|
|
require us to make principal payments if the quantity and value
of our proved reserves are insufficient to support our level of
borrowings;
|
|
|
limit our flexibility in planning for, or reacting to, changes
in the oil and natural gas industry;
|
|
|
place us at a competitive disadvantage compared to our
competitors who may have lower debt service obligations and
greater financing flexibility than we do;
|
|
|
limit our financial flexibility, including our ability to borrow
additional funds;
|
|
|
increase our interest expense on our variable rate borrowings if
interest rates increase;
|
|
|
limit our ability to make capital expenditures to develop our
properties;
|
|
|
|
increase our vulnerability to exchange risk associated with
Canadian dollar denominated indebtedness; increase our
vulnerability to general adverse economic and industry
conditions; and
|
|
|
result in a default or event of default under our debt
agreements, which, if not cured or waived, could adversely
affect our financial condition, results of operations and cash
flows.
|
26
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:
|
|
|
|
|
reducing or delaying capital expenditures;
|
|
|
seeking additional debt financing or equity capital;
|
|
|
selling assets;
|
|
|
restructuring or refinancing debt; or
|
|
|
reorganizing our capital structure.
|
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.
The
provisions of our debt agreements and the risks associated with
our debt could adversely affect our business, financial
condition and results of operations.
Our debt agreements restrict our ability to, among other things:
|
|
|
|
|
incur additional debt;
|
|
|
pay dividends on, or redeem or repurchase capital stock;
|
|
|
make certain investments;
|
|
|
incur or permit certain liens to exist;
|
|
|
enter into certain types of transactions with affiliates;
|
|
|
merge, consolidate or amalgamate with another company;
|
|
|
transfer or otherwise dispose of assets, including capital stock
of subsidiaries; and
|
|
|
redeem subordinated debt.
|
Our debt agreements, among other things, require the maintenance
of financial covenants that are more fully described in
Note 13 to our consolidated financial statements found in
Item 8 of this Annual Report. Our ability to comply with
the 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 to declare the outstanding
principal and 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, we may have insufficient assets 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.
27
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, 2009. 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
169 million shares of our common stock outstanding at
December 31, 2009. 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,
2009, the holders election to convert such debentures
could result in an aggregate of 9.8 million shares of our
common stock being issued. We also had options outstanding to
purchase approximately 3.0 million shares of our common
stock at December 31, 2009.
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:
|
|
|
|
|
our board of directors is authorized to issue preferred stock
without stockholder approval;
|
|
|
our board of directors is classified; and
|
|
|
advance notice is required for director nominations by
stockholders and actions to be taken at annual meetings at the
request of stockholders.
|
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.
If we
do not make acquisitions on economically acceptable terms, our
future growth will be limited.
In addition to expanding production from our current reserves,
we may pursue acquisitions. If we are unable to make these
acquisitions because we are: (1) unable to identify
attractive acquisition candidates, to analyze acquisition
opportunities successfully from an operational and financial
point of view or to negotiate acceptable purchase contracts with
them; (2) unable to obtain financing for these acquisitions
on economically acceptable terms; or (3) outbid by
competitors, then our future growth could be limited.
Furthermore, even if we do make acquisitions, these acquisitions
may not result in an increase in the cash generated by
operations.
Any acquisition involves potential risks, including, among other
things:
|
|
|
|
|
mistaken assumptions about volumes, revenue and costs, including
synergies;
|
|
|
an inability to integrate successfully the assets we acquire;
|
|
|
the assumption of unknown liabilities;
|
28
|
|
|
|
|
limitations on rights to indemnity from the seller;
|
|
|
mistaken assumptions about the overall costs of equity or debt;
|
|
|
the diversion of managements and employees attention
from other business matters;
|
|
|
unforeseen difficulties operating in new product areas, with new
customers, or new geographic areas; and
|
|
|
customer or key employee losses at the acquired businesses.
|
|
|
ITEM 1B.
|
Unresolved
Staff Comments
|
None.
A detailed description of our significant properties and
associated 2009 developments can be found in Item 1 of this
Annual Report, which is incorporated herein by reference.
|
|
ITEM 3.
|
Legal
Proceedings
|
Information required with respect to this item is set forth in
Note 16 to the consolidated financial statements included
in Item 8 of this Annual Report, which is incorporated
herein by reference.
PART II.
|
|
ITEM 5.
|
Market
For Registrants Common Equity, Related Stockholder Matters
and Issuer Purchase of Equity Securities
|
Market
Information
Our common stock is traded on the New York Stock Exchange under
the symbol KWK.
The following table sets forth the quarterly high and low sales
prices of our common stock for the periods indicated below.
|
|
|
|
|
|
|
|
|
|
|
HIGH
|
|
|
LOW
|
|
|
2009
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
16.55
|
|
|
$
|
11.78
|
|
Third Quarter
|
|
|
15.10
|
|
|
|
7.93
|
|
Second Quarter
|
|
|
13.35
|
|
|
|
5.29
|
|
First Quarter
|
|
|
8.89
|
|
|
|
3.98
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
20.74
|
|
|
$
|
3.74
|
|
Third Quarter
|
|
|
40.70
|
|
|
|
17.13
|
|
Second Quarter
|
|
|
44.98
|
|
|
|
34.96
|
|
First
Quarter (1)
|
|
|
38.72
|
|
|
|
24.28
|
|
|
|
|
(1) |
|
Per share amounts previously reported have been adjusted to
reflect a two-for-one stock split effected in the form of a
stock dividend in January 2008. |
As of February 15, 2010, there were approximately 799
common stockholders of record.
We have not paid cash dividends on our common stock and intend
to retain our cash flow from operations for the future operation
and development of our business. In addition, we have debt
agreements that restrict payments of dividends.
29
Performance
Graph
The following performance graph compares the cumulative total
stockholder return on Quicksilver common stock with the
Standard & Poors 500 Stock Index (the
S&P 500 Index) and the Standard &
Poors 500 Exploration and Production Index (the
S&P 500 E&P Index) for the period from
December 31, 2004 to December 31, 2009, assuming an
initial investment of $100 and the reinvestment of all
dividends, if any.
Comparison
of Cumulative Five Year Total Return
Issuer
Purchases of Equity Securities
The following table summarizes our repurchases of Quicksilver
common stock during the quarter ended December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of
|
|
|
Maximum Number of
|
|
|
|
Total Number of
|
|
|
|
|
|
Shares Purchased as
|
|
|
Shares that May Yet
|
|
|
|
Shares
|
|
|
Average Price
|
|
|
Part of Publicly
|
|
|
Be Purchased Under
|
|
Period
|
|
Purchased
(1)
|
|
|
Paid per Share
|
|
|
Announced Plan
(2)
|
|
|
the Plan
(2)
|
|
|
October 2009
|
|
|
2,197
|
|
|
$
|
13.38
|
|
|
|
-
|
|
|
|
-
|
|
November 2009
|
|
|
1,323
|
|
|
$
|
13.27
|
|
|
|
-
|
|
|
|
-
|
|
December 2009
|
|
|
573
|
|
|
$
|
12.46
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4,093
|
|
|
$
|
13.22
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
(1)
|
Represents shares of common stock surrendered by employees to
satisfy the income tax withholding obligations arising upon the
vesting of restricted stock issued under our stock plans.
|
|
|
|
(2)
|
We do not have a publicly announced plan for repurchasing our
common stock.
|
|
30
|
|
ITEM 6.
|
Selected
Financial Data
|
The following table sets forth, as of the dates and for the
periods indicated, our selected financial information and is
derived from our audited consolidated financial statements for
such periods. The information should be read in conjunction
with Managements Discussion and Analysis of
Financial Condition and Results of Operations and our
consolidated financial statements and notes thereto contained in
this Annual Report. The following information is not
necessarily indicative of our future results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
(2)
|
|
|
2008
(3)
|
|
|
2007
(4)
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except for per share data and ratios)
|
|
|
Operating Results Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
832,735
|
|
|
$
|
800,641
|
|
|
$
|
561,258
|
|
|
$
|
390,362
|
|
|
$
|
310,448
|
|
Operating income (loss)
|
|
|
(613,873
|
)
|
|
|
(249,697
|
)
|
|
|
803,581
|
|
|
|
174,196
|
|
|
|
149,129
|
|
Income (loss) before income taxes
|
|
|
(836,856
|
)
|
|
|
(585,077
|
)
|
|
|
730,806
|
|
|
|
126,248
|
|
|
|
122,658
|
|
Net income (loss)
|
|
|
(545,239
|
)
|
|
|
(373,622
|
)
|
|
|
476,445
|
|
|
|
90,097
|
|
|
|
83,979
|
|
Net income (loss) attributable to Quicksilver
|
|
|
(557,473
|
)
|
|
|
(378,276
|
)
|
|
|
475,390
|
|
|
|
90,006
|
|
|
|
83,979
|
|
Diluted earnings (loss) per common
share(1)
|
|
$
|
(3.30
|
)
|
|
$
|
(2.33
|
)
|
|
$
|
2.87
|
|
|
$
|
0.58
|
|
|
$
|
0.54
|
|
Dividends paid per share
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cash provided by operating activities
|
|
$
|
612,240
|
|
|
$
|
456,566
|
|
|
$
|
319,104
|
|
|
$
|
242,186
|
|
|
$
|
140,242
|
|
Capital expenditures
|
|
|
693,838
|
|
|
|
1,286,715
|
|
|
|
1,020,684
|
|
|
|
619,061
|
|
|
|
331,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Condition Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment - net
|
|
$
|
3,085,940
|
|
|
$
|
3,797,715
|
|
|
$
|
2,142,346
|
|
|
$
|
1,679,280
|
|
|
$
|
1,112,002
|
|
Total assets
|
|
|
3,612,882
|
|
|
|
4,498,208
|
|
|
|
2,773,751
|
|
|
|
1,881,052
|
|
|
|
1,241,437
|
|
Long-term debt
|
|
|
2,427,523
|
|
|
|
2,586,045
|
|
|
|
788,518
|
|
|
|
887,917
|
|
|
|
469,330
|
|
All other long-term obligations
|
|
|
121,877
|
|
|
|
282,101
|
|
|
|
434,190
|
|
|
|
191,627
|
|
|
|
153,518
|
|
Total equity
|
|
|
696,822
|
|
|
|
1,211,563
|
|
|
|
1,192,468
|
|
|
|
602,119
|
|
|
|
406,399
|
|
|
|
|
|
|
(1)
|
Per share amounts have been adjusted to reflect a three-for-two
stock split effected in the form of a stock dividend in June
2005 and a two-for-one stock split effected in the form of a
stock dividend in January 2008.
|
|
|
|
(2)
|
Operating loss for 2009 includes pre-tax charges of
$786.9 million and $192.7 million for impairments
associated with our U.S. and Canadian oil and gas properties,
respectively. Net loss also includes $75.4 million of
pre-tax income attributable to our proportionate ownership of
BBEP and a pre-tax charge of $102.1 million for impairment
of that investment.
|
|
|
|
(3)
|
Operating loss for 2008 includes a pre-tax charge of
$633.5 million for impairment associated with our U.S. oil
and gas properties. Net loss also includes $93.3 million
for pre-tax income attributable to our proportionate ownership
of BBEP and a pre-tax charge of $320.4 million for
impairment of that investment.
|
|
|
|
(4)
|
Operating income and net income for 2007 include a pre-tax gain
of $628.7 million recognized from the divestiture of our
Northeast Operations and a pre-tax charge of $63.5 million
associated with the Michigan Sales Contract (See Note 2 to
the consolidated financial statements in Item 8 of this
Annual Report).
|
|
31
|
|
ITEM 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following Managements Discussion and Analysis
(MD&A) is intended to help readers of our
financial statements understand our business, results of
operations, financial condition, liquidity and capital
resources. MD&A is provided as a supplement to, and should
be read in conjunction with, the other sections of this Annual
Report. 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 a general description of our
business; the value drivers of our business; measurements; and
opportunities, challenges and risks.
|
|
|
|
Financial Risk Management information about
debt financing and financial risk management.
|
|
|
|
2009 Highlights a summary of significant
activities and events affecting Quicksilver.
|
|
|
|
Results of Operations an analysis of our
consolidated results of operations for the three years presented
in our financial statements.
|
|
|
|
Liquidity, Capital Resources and Financial
Position an analysis of our cash flows, sources
and uses of cash, contractual obligations and commercial
commitments.
|
|
|
|
Critical Accounting Estimates a discussion of
critical accounting estimates that represent choices between
acceptable alternatives
and/or
require management judgments and assumptions.
|
OVERVIEW
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 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 oil. We conduct acquisition, exploration,
exploitation, development and production activities to replace
the reserves that we produce.
At December 31, 2009 approximately 99% of our proved
reserves were natural gas and NGLs. Consistent with one of our
business strategies, we continue to develop and apply our
unconventional resources expertise to our development projects
in Alberta, Canada and in the Barnett Shale in Texas. Our Texas
and Alberta reserves made up 89% and 10%, respectively, of our
proved reserves at December 31, 2009. Our acreage in the
Horn River Basin in British Columbia will provide additional
opportunity for further application of this expertise.
For 2010, we plan to continue our focus on the development and
exploitation of our properties in Texas and Alberta and to fund
exploration in the Horn River Basin and Green River Basin. We
have allocated $390 million of our 2010 consolidated
capital program of $540 million for drilling and completion
activities. Of the remaining 2010 consolidated capital program,
$92 million has been allocated for gathering and processing
activities (including approximately $80 million to be
funded by KGS), $53 million related to acquisition of
additional leasehold interests and $5 million for other
property and equipment. Approximately $465 million is
allocated to projects in Texas and approximately
$52 million is allocated to our Canadian projects
(including $17 million in Alberta). The remaining
$23 million of the 2010 capital program has been allocated
to other areas in the U.S. Our exploratory activities in the
Horn River and Green River Basins are expected to consume
$58 million of our 2010 capital program.
We focus on three key value drivers:
|
|
|
|
|
reserve growth;
|
|
|
production growth; and
|
|
|
maximizing our operating cash flows.
|
32
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 to 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 the properties
we operate to determine if steps can be taken to efficiently
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: organic reserve growth; production
volumes; cash flow from operating activities; and earnings per
share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Organic reserve
growth (1)
|
|
|
23
|
%
|
|
|
29
|
%
|
|
|
59
|
%
|
Production volumes (Bcfe)
|
|
|
118.5
|
|
|
|
96.2
|
|
|
|
77.9
|
|
Cash flow from operating activities (in millions)
|
|
$
|
612.2
|
|
|
$
|
456.6
|
|
|
$
|
319.1
|
|
Diluted earnings (loss) per
share (2)(3)(4)
|
|
$
|
(3.30
|
)
|
|
$
|
(2.33
|
)
|
|
$
|
2.87
|
|
|
|
|
|
|
(1)
|
This ratio is calculated by subtracting adjusted beginning of
the year proved reserves from adjusted end of the year proved
reserves and dividing by adjusted beginning of the year proved
reserves. Adjusted beginning of the year reserves are
calculated by deducting divested reserves and adjusted current
year production from beginning of the year reserves. Adjusted
current year production excludes production from purchased
reserves. Adjusted end of the year reserves are calculated by
deducting purchased reserves from end of the year reserves.
|
|
|
|
(2)
|
Diluted earnings for 2009 include pre-tax charges of
$786.9 million and $192.7 million for impairments
associated with our U.S. and Canadian oil and gas properties,
respectively. Net loss also includes $75.4 million of
pre-tax income attributable to our proportionate ownership of
BBEP and a pre-tax charge of $102.1 million for impairment
of that investment.
|
|
|
|
(3)
|
Diluted earnings for 2008 include a pre-tax charge of
$633.5 million for impairment associated with our U.S. oil
and gas properties. Net loss also includes $93.3 million
of pre-tax income attributable to our proportionate ownership of
BBEP and a pre-tax charge of $320.4 million for impairment
of that investment.
|
|
|
|
(4)
|
Diluted earnings for 2007 include a pre-tax gain of
$628.7 million recognized from the divestiture of our
Northeast Operations and a pre-tax charge of $63.5 million
associated with the Michigan Sales Contract.
|
|
FINANCIAL
RISK MANAGEMENT
We have established internal control policies and procedures for
managing risk within our organization. The possibility of
decreasing prices received for our natural gas, NGL and oil
production is among the several risks that we face. We seek to
manage this risk by entering into derivative contracts which we
strive to treat as 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 or depression. Item 7A of this
Annual Report contains details of our commodity price and
interest rate risk management.
33
2009
HIGHLIGHTS
Eni
Transaction
On June 19, 2009, we completed the Eni Transaction whereby
we entered into a strategic alliance with Eni and sold a 27.5%
interest in our Alliance Leasehold. The total proceeds for the
Eni Transaction were $280 million in cash, inclusive of the
Gas Purchase Commitment, subject to normal post-closing
adjustments. We used the proceeds from the transaction to repay
a portion of the Senior Secured Second Lien Facility. See
Note 3 to our consolidated financial statements in
Item 8 of this Annual Report.
Long-Term
Debt
Upon completion of the Eni Transaction, the borrowing base under
the Senior Secured Credit Facility was adjusted to
$1.125 billion. Subsequently, a redetermination in October
2009 resulted in a revised borrowing base of $1.0 billion.
The Senior Secured Credit Facility provides us an option to
increase the commitments by up to $250 million, with a
maximum of $1.45 billion with lender consent and additional
commitments. We can also extend the facility, which matures on
February 9, 2012, up to two additional years with
lenders approval and commitments.
On June 25, 2009, we issued Senior Notes due 2016 with a
principal amount of $600 million for proceeds of
$580.3 million. The notes bear interest at the rate of
11.75%. The proceeds of these notes, in addition to proceeds
from the Eni Transaction, were used to repay and terminate the
remaining indebtedness under our Senior Secured Second Lien
Facility and to make repayments under the Senior Secured Credit
Facility.
On August 14, 2009, we issued Senior Notes due 2019 with a
principal amount of $300 million for proceeds of
$292.8 million. The notes bear interest at the rate of
9.125%. The proceeds of these notes were used to make
repayments under the Senior Secured Credit Facility.
Additional information about our long-term debt is found in
Note 13 to our consolidated financial statements in
Item 8 of this Annual Report.
KGS
Secondary Offering
KGS issued 4,000,000 common units on December 16, 2009 in
the KGS Secondary Offering and received $80.3 million, net
of underwriters discount and other offering costs. On
January 4, 2010, the underwriters exercised their option to
purchase an additional 549,200 common units for
$11.1 million, which further reduced our ownership of KGS
to 61.2% effective January 6, 2010. The proceeds were used
by KGS to repay borrowings of $11 million outstanding under
the KGS Credit Agreement in January 2010. KGS also re-borrowed
$95 million in January under the KGS Credit Agreement to
fund KGS purchase of the Alliance Midstream Assets.
Upon completion of the Alliance Midstream Asset sale to KGS in
January 2010, we repaid $95 million of borrowings under the
Senior Secured Credit Facility.
Increase
in Production
Daily production increased 23% during 2009 from 2008. The
production increase is discussed further in Results of
Operations below.
Horn
River Basin Discovery
During 2009, we spent $62 million for exploration and
infrastructure development in the Horn River Basin where we have
drilled and cased two wells, one of which was placed into
service in the third quarter with the second well placed into
service in the fourth quarter. Our capital expenditures include
costs related to infrastructure development, such as
construction of roads and production laterals.
We also entered into a nine-year agreement with a third party
that began in May 2009 for the firm processing and
transportation of natural gas out of the Horn River Basin with
initial volumes of 3 MMcfd and increasing to 100 MMcfd
by May 2013.
34
Litigation
Update
In October 2009, a jury awarded $22 million to the
plaintiffs in our litigation originally brought against us by
the plaintiffs Rod and Richard Thornton and Eagle Drilling,
LLC. We are actively seeking an appeal in this matter.
In June 2009, the appellate court in the CMS litigation reversed
the original district court judgment. Pursuant to a settlement
agreement, we paid CMS $5 million during July 2009, which
we accrued during the quarter ended June 30, 2009.
BBEP
Update
In February 2009, we received a quarterly distribution of
$11.1 million for the quarter ended December 31,
2008. In April 2009, BBEP announced that it was suspending its
distributions to remain in compliance with certain provisions of
its credit facility and to redirect cash flow to reduce its
debt. During the year ended December 31, 2009, we
recognized $75.4 million of equity earnings in BBEP and an
impairment of $102.1 million.
On February 3, 2010, we entered into a global settlement
agreement with BBEP and all other parties to the lawsuit whereby
we will receive $18 million in cash along with the
retention of full voting rights for our units held in BBEP
subject to the provisions of a limited standstill agreement, the
ability to name two directors to BBEPs general
partners board of directors, the reinstitution of the BBEP
quarterly distributions and other governance accommodations.
RESULTS
OF OPERATIONS
Revenue
Natural
Gas, NGL and Oil
Production Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Oil
|
|
|
Total
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
$
|
236.6
|
|
|
$
|
371.1
|
|
|
$
|
121.6
|
|
|
$
|
135.5
|
|
|
$
|
198.1
|
|
|
$
|
106.7
|
|
|
$
|
14.0
|
|
|
$
|
30.4
|
|
|
$
|
9.2
|
|
|
$
|
386.1
|
|
|
$
|
599.6
|
|
|
$
|
237.5
|
|
Northeast Operations
|
|
|
-
|
|
|
|
-
|
|
|
|
100.8
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4.5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18.6
|
|
|
|
-
|
|
|
|
-
|
|
|
|
123.9
|
|
Other U.S.
|
|
|
0.5
|
|
|
|
0.8
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
0.8
|
|
|
|
0.6
|
|
|
|
8.0
|
|
|
|
14.8
|
|
|
|
10.2
|
|
|
|
8.8
|
|
|
|
16.4
|
|
|
|
11.1
|
|
Hedging
|
|
|
213.1
|
|
|
|
(2.4
|
)
|
|
|
26.3
|
|
|
|
-
|
|
|
|
(8.6
|
)
|
|
|
(5.2
|
)
|
|
|
-
|
|
|
|
(7.1
|
)
|
|
|
(0.7
|
)
|
|
|
213.1
|
|
|
|
(18.1
|
)
|
|
|
20.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
450.2
|
|
|
|
369.5
|
|
|
|
249.0
|
|
|
|
135.8
|
|
|
|
190.3
|
|
|
|
106.6
|
|
|
|
22.0
|
|
|
|
38.1
|
|
|
|
37.3
|
|
|
|
608.0
|
|
|
|
597.9
|
|
|
|
392.9
|
|
Canada
|
|
|
90.5
|
|
|
|
182.7
|
|
|
|
126.4
|
|
|
|
0.1
|
|
|
|
0.4
|
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
90.7
|
|
|
|
183.1
|
|
|
|
126.6
|
|
Hedging
|
|
|
98.0
|
|
|
|
(0.2
|
)
|
|
|
25.6
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
98.0
|
|
|
|
(0.2
|
)
|
|
|
25.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Canada
|
|
|
188.5
|
|
|
|
182.5
|
|
|
|
152.0
|
|
|
|
0.1
|
|
|
|
0.4
|
|
|
|
0.2
|
|
|
|
0.1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
188.7
|
|
|
|
182.9
|
|
|
|
152.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
638.7
|
|
|
$
|
552.0
|
|
|
$
|
401.0
|
|
|
$
|
135.9
|
|
|
$
|
190.7
|
|
|
$
|
106.8
|
|
|
$
|
22.1
|
|
|
$
|
38.1
|
|
|
$
|
37.3
|
|
|
$
|
796.7
|
|
|
$
|
780.8
|
|
|
$
|
545.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Oil
|
|
|
Equivalent Total
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(MMcfd)
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
|
|
|
|
|
|
|
(MMcfed)
|
|
|
|
|
|
Texas
|
|
|
168.3
|
|
|
|
122.8
|
|
|
|
50.1
|
|
|
|
13,598
|
|
|
|
11,425
|
|
|
|
6,395
|
|
|
|
729
|
|
|
|
873
|
|
|
|
349
|
|
|
|
254.2
|
|
|
|
196.6
|
|
|
|
90.6
|
|
Northeast Operations
|
|
|
-
|
|
|
|
-
|
|
|
|
56.1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
331
|
|
|
|
-
|
|
|
|
-
|
|
|
|
799
|
|
|
|
-
|
|
|
|
-
|
|
|
|
62.9
|
|
Other U.S.
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
34
|
|
|
|
36
|
|
|
|
29
|
|
|
|
434
|
|
|
|
447
|
|
|
|
452
|
|
|
|
3.4
|
|
|
|
3.2
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
168.9
|
|
|
|
123.1
|
|
|
|
106.5
|
|
|
|
13,632
|
|
|
|
11,461
|
|
|
|
6,755
|
|
|
|
1,163
|
|
|
|
1,320
|
|
|
|
1,600
|
|
|
|
257.6
|
|
|
|
199.8
|
|
|
|
156.7
|
|
Canada
|
|
|
66.9
|
|
|
|
63.0
|
|
|
|
56.8
|
|
|
|
5
|
|
|
|
3
|
|
|
|
13
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
66.9
|
|
|
|
63.0
|
|
|
|
56.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
235.8
|
|
|
|
186.1
|
|
|
|
163.3
|
|
|
|
13,637
|
|
|
|
11,464
|
|
|
|
6,768
|
|
|
|
1,165
|
|
|
|
1,320
|
|
|
|
1,600
|
|
|
|
324.5
|
|
|
|
262.8
|
|
|
|
213.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Average Realized Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Oil
|
|
|
Equivalent Total
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(per Mcf)
|
|
|
|
|
|
|
|
|
(per Bbl)
|
|
|
|
|
|
|
|
|
(per Bbl)
|
|
|
|
|
|
|
|
|
(per Mcfe)
|
|
|
|
|
|
Texas
|
|
$
|
3.85
|
|
|
$
|
8.26
|
|
|
$
|
6.65
|
|
|
$
|
27.31
|
|
|
$
|
47.38
|
|
|
$
|
45.70
|
|
|
$
|
52.62
|
|
|
$
|
95.16
|
|
|
$
|
72.37
|
|
|
$
|
4.16
|
|
|
$
|
8.33
|
|
|
$
|
7.18
|
|
Northeast Operations
|
|
|
-
|
|
|
|
-
|
|
|
|
4.92
|
|
|
|
-
|
|
|
|
-
|
|
|
|
37.36
|
|
|
|
-
|
|
|
|
-
|
|
|
|
63.81
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5.40
|
|
Other U.S.
|
|
|
3.62
|
|
|
|
7.43
|
|
|
|
4.68
|
|
|
|
27.02
|
|
|
|
70.52
|
|
|
|
52.35
|
|
|
|
50.53
|
|
|
|
89.41
|
|
|
|
61.49
|
|
|
|
7.41
|
|
|
|
13.92
|
|
|
|
9.63
|
|
Hedging
|
|
|
3.45
|
|
|
|
(0.05
|
)
|
|
|
0.81
|
|
|
|
-
|
|
|
|
(2.06
|
)
|
|
|
(2.10
|
)
|
|
|
-
|
|
|
|
(14.72
|
)
|
|
|
(1.19
|
)
|
|
|
2.26
|
|
|
|
(0.25
|
)
|
|
|
0.45
|
|
Total U.S.
|
|
$
|
7.31
|
|
|
$
|
8.20
|
|
|
$
|
6.40
|
|
|
$
|
27.30
|
|
|
$
|
45.39
|
|
|
$
|
43.22
|
|
|
$
|
51.84
|
|
|
$
|
78.83
|
|
|
$
|
63.87
|
|
|
$
|
6.47
|
|
|
$
|
8.18
|
|
|
$
|
6.87
|
|
Canada
|
|
|
3.71
|
|
|
|
7.92
|
|
|
|
6.10
|
|
|
|
54.66
|
|
|
|
325.52
|
|
|
|
48.02
|
|
|
|
54.80
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3.71
|
|
|
|
7.94
|
|
|
|
6.10
|
|
Hedging
|
|
|
4.01
|
|
|
|
(0.01
|
)
|
|
|
1.23
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4.01
|
|
|
|
(0.01
|
)
|
|
|
1.23
|
|
Total Canada
|
|
$
|
7.72
|
|
|
$
|
7.91
|
|
|
$
|
7.33
|
|
|
$
|
54.66
|
|
|
$
|
325.52
|
|
|
$
|
48.02
|
|
|
$
|
54.80
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
7.72
|
|
|
$
|
7.93
|
|
|
$
|
7.33
|
|
Total
|
|
$
|
7.42
|
|
|
$
|
8.10
|
|
|
$
|
6.73
|
|
|
$
|
27.32
|
|
|
$
|
45.44
|
|
|
$
|
43.23
|
|
|
$
|
51.85
|
|
|
$
|
78.83
|
|
|
$
|
63.87
|
|
|
$
|
6.73
|
|
|
$
|
8.12
|
|
|
$
|
6.99
|
|
The following table summarizes the changes in our natural gas,
NGL and oil revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
NGL
|
|
|
Oil
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Revenue for 2007
|
|
$
|
400,989
|
|
|
$
|
106,787
|
|
|
$
|
37,313
|
|
|
$
|
545,089
|
|
Volume variances
|
|
|
57,227
|
|
|
|
74,591
|
|
|
|
(6,463
|
)
|
|
|
125,355
|
|
Hedge settlement variances
|
|
|
(59,632
|
)
|
|
|
(3,475
|
)
|
|
|
(6,422
|
)
|
|
|
(69,529
|
)
|
Price variances
|
|
|
153,462
|
|
|
|
12,763
|
|
|
|
13,648
|
|
|
|
179,873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue for 2008
|
|
$
|
552,046
|
|
|
$
|
190,666
|
|
|
$
|
38,076
|
|
|
$
|
780,788
|
|
Volume variances
|
|
|
145,141
|
|
|
|
35,484
|
|
|
|
(4,544
|
)
|
|
|
176,081
|
|
Hedge settlement variances
|
|
|
313,493
|
|
|
|
8,648
|
|
|
|
7,117
|
|
|
|
329,258
|
|
Price variances
|
|
|
(371,975
|
)
|
|
|
(98,858
|
)
|
|
|
(18,596
|
)
|
|
|
(489,429
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue for 2009
|
|
$
|
638,705
|
|
|
$
|
135,940
|
|
|
$
|
22,053
|
|
|
$
|
796,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our natural gas revenue for 2009 increased from 2008 as a result
of increases in production partially offset by a decrease in
realized prices. Decreased market prices for natural gas in
2009 reduced revenue $372.0 million, but this reduction was
largely offset by a $313.5 million increase from hedge
settlements. The increase in U.S. natural gas volumes is
due to wells placed into service principally in Texas during
2009. These increases were partially offset by lower volumes
resulting from the sale of a 27.5% revenue interest in our
Alliance properties in June and natural production declines from
existing Texas wells. Canadian natural gas production increased
due in part to the Horn River Basin wells placed into service
during the third and fourth quarters of 2009.
NGL revenue for 2009 decreased primarily due to lower realized
NGL prices for 2009 as compared to 2008. Realized NGL prices
decreased despite the absence of $8.6 million paid for
hedge settlements in 2008. Partially offsetting the price
decrease were increases in production. Texas production
increased 19% due to wells placed into production during 2009,
lower field pressures and improved NGL recoveries from the
Corvette Plant, which was placed into service by KGS during the
first quarter of 2009.
Oil revenue for 2009 was lower than 2008 due to decreases in
market prices and oil production for 2009 as compared to 2008.
An increase in oil and condensate revenue from the absence of
outlays for hedge settlements partially offset these decreases.
Natural gas for 2008 increased as a result of both an increase
in realized prices and an increase in volumes as compared to
2007. Natural gas prices for 2008 increased significantly
compared to 2007 and resulted in additional revenue of
$153.5 million that was partially offset by a
$59.6 million reduction in 2008 revenue because of the
absence of hedge settlements during 2008. Natural gas
production in the U.S. increased as a result of the impact
of wells placed into production partially offset by production
declines for existing Texas wells. The November 2007
divestiture of our Northeast Operations reduced our natural gas
production while the Alliance Acquisition increased production
by 17.0 MMcfd.
36
NGL revenue for 2008 increased as a result of production
increases and higher realized prices. Additional Texas natural
gas production in the
high-BTU
area of the Barnett Shale and processing improvements during
2008 increased NGL volumes when compared to 2007. Realized
prices included higher NGL market prices partially offset by
lower revenue because of additional payments for hedge
settlements. Partially offsetting the Texas production and
pricing increases was the absence of production from the
divested Northeast Operations.
Oil revenue for 2008 was higher than 2007 due to an increase in
realized prices. Realized prices for oil increased in 2008
despite a reduction in revenue from hedge settlements.
Production increases from Texas wells in 2008 partially offset
the absence of production from divested Northeast Operations.
Sales of
Purchased Natural Gas and Costs of Purchased Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(in thousands)
|
|
|
Sales of purchased natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases from Eni
|
|
$
|
11,195
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Purchases from others
|
|
|
12,459
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
23,654
|
|
|
|
-
|
|
|
|
-
|
|
Costs of purchased natural gas sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases from Eni
|
|
|
12,268
|
|
|
|
-
|
|
|
|
-
|
|
Purchases from others
|
|
|
11,265
|
|
|
|
-
|
|
|
|
-
|
|
Unrealized valuation loss on Gas Purchase Commitment
|
|
|
6,625
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
30,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales and purchases of natural gas
|
|
$
|
(6,504
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our activities related to the purchase and sale of natural gas
in Texas are the result of natural gas sales and purchases
transacted under the Gas Purchase Commitment. Due to the nature
of the Gas Purchase Commitment, we have recognized, and will
continue to recognize, unrealized gains and losses associated
with our future commitment. The Gas Purchase Commitment is more
fully described in Notes 3 and 6 to the consolidated
financial statements in Item 8 of this Annual Report.
Other
Revenue
Other revenue, consisting primarily of revenue from the
processing, gathering and marketing of natural gas and income
attributable to hedge derivative ineffectiveness, was
$12.4 million for 2009, which was $7.5 million lower
than for 2008. KGS third-party revenue for the 2009
period was $5.4 million less for 2009 when compared to
2008. Additionally, gains attributable to partial
ineffectiveness of derivatives hedging our Canadian production
were $1.8 million less for 2009 when compared to 2008.
Other revenue was $19.9 million for 2008, an increase of
$3.7 million compared with 2007. Throughput from third
parties utilizing gathering and processing assets primarily
operated by KGS increased other revenue by $6.2 million.
Partially offsetting the increase was the absence of
$4.3 million of Canadian government grants for new drilling
techniques we received in 2007.
37
Operating
Expenses
Oil and
Gas Production Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
|
|
|
|
|
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
|
|
|
Texas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense
|
|
$
|
84,216
|
|
|
$
|
0.91
|
|
|
$
|
90,737
|
|
|
$
|
1.26
|
|
|
$
|
52,998
|
|
|
$
|
1.60
|
|
|
|
|
|
|
|
|
|
Equity compensation
|
|
|
761
|
|
|
|
0.01
|
|
|
|
1,130
|
|
|
|
0.02
|
|
|
|
339
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
84,977
|
|
|
$
|
0.92
|
|
|
$
|
91,867
|
|
|
$
|
1.28
|
|
|
$
|
53,337
|
|
|
$
|
1.61
|
|
|
|
|
|
|
|
|
|
Northeast Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
48,489
|
|
|
$
|
2.11
|
|
|
|
|
|
|
|
|
|
Equity compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
422
|
|
|
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
48,911
|
|
|
$
|
2.13
|
|
|
|
|
|
|
|
|
|
Other U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense
|
|
$
|
6,359
|
|
|
$
|
5.21
|
|
|
$
|
6,318
|
|
|
$
|
5.35
|
|
|
$
|
3,278
|
|
|
$
|
2.97
|
|
|
|
|
|
|
|
|
|
Equity compensation
|
|
|
195
|
|
|
|
0.16
|
|
|
|
190
|
|
|
|
0.16
|
|
|
|
193
|
|
|
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,554
|
|
|
$
|
5.37
|
|
|
$
|
6,508
|
|
|
$
|
5.51
|
|
|
$
|
3,471
|
|
|
$
|
3.13
|
|
|
|
|
|
|
|
|
|
Total U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense
|
|
$
|
90,575
|
|
|
$
|
0.95
|
|
|
$
|
97,055
|
|
|
$
|
1.32
|
|
|
$
|
104,765
|
|
|
$
|
1.83
|
|
|
|
|
|
|
|
|
|
Equity compensation
|
|
|
956
|
|
|
|
0.02
|
|
|
|
1,320
|
|
|
|
0.02
|
|
|
|
954
|
|
|
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
91,531
|
|
|
$
|
0.97
|
|
|
$
|
98,375
|
|
|
$
|
1.34
|
|
|
$
|
105,719
|
|
|
$
|
1.85
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense
|
|
$
|
34,070
|
|
|
$
|
1.39
|
|
|
$
|
33,781
|
|
|
$
|
1.47
|
|
|
$
|
28,415
|
|
|
$
|
1.37
|
|
|
|
|
|
|
|
|
|
Equity compensation
|
|
|
2,114
|
|
|
|
0.09
|
|
|
|
2,146
|
|
|
|
0.09
|
|
|
|
1,969
|
|
|
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,184
|
|
|
$
|
1.48
|
|
|
$
|
35,927
|
|
|
$
|
1.56
|
|
|
$
|
30,384
|
|
|
$
|
1.46
|
|
|
|
|
|
|
|
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash expense
|
|
$
|
124,645
|
|
|
$
|
1.04
|
|
|
$
|
130,836
|
|
|
$
|
1.36
|
|
|
$
|
133,180
|
|
|
$
|
1.70
|
|
|
|
|
|
|
|
|
|
Equity compensation
|
|
|
3,070
|
|
|
|
0.04
|
|
|
|
3,466
|
|
|
|
0.04
|
|
|
|
2,923
|
|
|
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
127,715
|
|
|
$
|
1.08
|
|
|
$
|
134,302
|
|
|
$
|
1.40
|
|
|
$
|
136,103
|
|
|
$
|
1.74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. production expense was lower for 2009 despite a 29%
production increase from 2008, primarily due to cost containment
efforts in Texas during 2009. Texas production expense per Mcfe
for 2009 decreased from 2008 as a result of lower saltwater
disposal costs, price reductions, and our stringent efforts to
contain costs through vendor bidding processes, bulk purchasing
and additional reliance on automation of well operations.
Canadian production expense for 2009 was unchanged from 2008.
Canadian production expense per Mcfe for 2009 decreased because
of production increases. Production expense on a Canadian
dollar basis for 2009 compared to 2008 increased approximately
C$3.3 million or 9% due primarily to the Canadian
production increase.
Oil and gas production expense for 2008 decreased slightly from
2007. The absence of production expense from the divested
Northeast Operations was almost entirely offset by the growth of
our operations in Texas and Canada that increased production
expense in those areas 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 Texas operations
was higher for 2008, production expense per Mcfe decreased 20%
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
38
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,
an increase in personnel costs and higher prevailing exchange
rates during 2008.
Production
and Ad Valorem Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
Production and ad valorem taxes
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
U.S.
|
|
$
|
21,403
|
|
|
$
|
0.23
|
|
|
$
|
15,999
|
|
|
$
|
0.22
|
|
|
$
|
13,912
|
|
|
$
|
0.24
|
|
Canada
|
|
|
2,478
|
|
|
$
|
0.10
|
|
|
|
2,735
|
|
|
$
|
0.12
|
|
|
|
3,136
|
|
|
$
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
23,881
|
|
|
$
|
0.20
|
|
|
$
|
18,734
|
|
|
$
|
0.19
|
|
|
$
|
17,048
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes for 2009 reflect the addition of
wells and midstream facilities in Texas during 2009 although
such costs were almost unchanged on a Mcfe-basis.
Production and ad valorem tax expense for 2008 increased
$1.7 million as compared to 2007. U.S. ad valorem and
production taxes increased $11.8 million due to the
development of our Texas properties, increased production and
higher pricing. This increase was nearly offset by the absence
of $9.5 million for production and ad valorem taxes
associated with the divested Northeast Operations.
Other
Operating Expense
The $3.3 million increase in other operating expense for
2009 as compared to 2008 was primarily the result of
commissioning and other operating expenses associated with the
operation of our Alliance Midstream Assets and other Texas
midstream operations not owned by KGS.
Depletion,
Depreciation and Accretion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
Depletion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
127,888
|
|
|
$
|
1.36
|
|
|
$
|
120,845
|
|
|
$
|
1.65
|
|
|
$
|
65,020
|
|
|
$
|
1.14
|
|
Canada
|
|
|
33,782
|
|
|
|
1.38
|
|
|
|
40,337
|
|
|
|
1.75
|
|
|
|
34,666
|
|
|
|
1.67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
161,670
|
|
|
|
1.36
|
|
|
|
161,182
|
|
|
|
1.68
|
|
|
|
99,686
|
|
|
|
1.28
|
|
Total depletion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
33,329
|
|
|
$
|
0.35
|
|
|
$
|
21,751
|
|
|
$
|
0.30
|
|
|
$
|
15,389
|
|
|
$
|
0.27
|
|
Canada
|
|
|
3,952
|
|
|
|
0.16
|
|
|
|
3,780
|
|
|
|
0.16
|
|
|
|
4,115
|
|
|
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation
|
|
|
37,281
|
|
|
|
0.31
|
|
|
|
25,531
|
|
|
|
0.27
|
|
|
|
19,504
|
|
|
|
0.25
|
|
Accretion
|
|
|
2,436
|
|
|
|
0.02
|
|
|
|
1,483
|
|
|
|
0.01
|
|
|
|
1,507
|
|
|
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
201,387
|
|
|
$
|
1.70
|
|
|
$
|
188,196
|
|
|
$
|
1.96
|
|
|
$
|
120,697
|
|
|
$
|
1.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion for 2009 was relatively unchanged from 2008 as
production increases were almost entirely offset by lower
depletion rates. Our U.S. depletion expense increased due
primarily to the 29% increase in U.S. production volumes.
Both our U.S. and Canadian depletion rates were impacted by
impairment charges. U.S. impairment charges were
recognized in the fourth quarter of 2008 and the first quarter
of 2009. Canadian impairment charges were recognized in the
first, second and fourth quarters of 2009. Changes in the
U.S.-Canadian
dollar exchange rate also contributed to lower Canadian
depletion expense and the Canadian depletion rate on a
Mcfe-basis. We expect that our consolidated depletion rate for
2010 will be in a range of $1.20 to $1.25 per Mcfe.
39
The change in the exchange rate decreased depletion
$2.6 million when comparing 2009 to 2008. The
$11.6 million increase in U.S. depreciation for 2009
as compared to 2008 was primarily associated with additions of
Fort Worth Basin field compression, Alliance gathering and
processing facilities and KGS gathering system in addition
to KGS Corvette Plant that was placed into service in the
first quarter of 2009.
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.
Impairment
of Oil and Gas Properties
As required under GAAP, we perform quarterly ceiling tests to
assess impairment of our oil and gas properties. Net
capitalized costs include the book value of our oil and gas
properties net of accumulated depletion and impairment, reduced
by the related asset retirement obligations and deferred tax
liabilities. Net capitalized costs are compared to the period
end ceiling limitation, which is the sum of:
|
|
|
|
|
estimated future net cash flows, discounted at 10% per annum,
from proved reserves, based on an unweighted average of
preceding
12-month
first-day-of-the-month
prices for the year then ended (year-end prices for 2008 and
2007) adjusted to reflect local differentials, unescalated
period end costs and expenses, adjusted for financial
derivatives that qualify as cash flow hedges of our oil and gas
revenue,
|
|
|
the costs of properties not being amortized,
|
|
|
the lower of cost or market value of unproved properties not
included in the costs being amortized, less
|
|
|
income tax effects related to differences between book and tax
bases of the oil and gas properties.
|
We recognized noncash pre-tax charges totaling
$979.6 million ($656.0 million after tax) for
impairments related to both our U.S. and Canadian oil and
gas properties in 2009. The primary factor that caused the
decrease in the estimated future cash flows from our proved oil
and gas reserves was lower benchmark natural gas prices at
March 31, 2009 for the U.S. and Canada and further
Canadian price decreases at June 30, 2009. Additionally,
reductions in the expected Canadian capital investment for the
following 12- and
18-month
periods at June 30, 2009 further decreased estimated
Canadian future net cash flows from our proved oil and gas
reserves. At September 30, 2009, the unamortized cost of
our Canadian oil and gas properties exceeded the full cost
ceiling limitation by approximately $38.8 million
(pre-tax). As permitted by full cost accounting rules in effect
at that date, improvements in AECO spot natural gas prices
subsequent to September 30, 2009 eliminated the necessity
to record a charge for impairment.
Use of the unweighted average of the preceding
12-month
first-day-of-the-month
prices as required by the SEC effective December 31, 2009,
resulted in a fourth quarter impairment of our Canadian oil and
gas properties. Note 10 to the consolidated financial
statements in Item 8 of this Annual Report contains
additional information about the ceiling test calculation.
We recognized a noncash pre-tax charge of $633.5 million
($411.8 million after tax) for impairment related to our
U.S. oil and gas properties in December 2008. The
impairment charge was primarily a result of the significantly
lower natural gas and NGL prices at year-end 2008 as compared to
year-end 2007.
40
General
and Administrative Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
|
General and administrative expense
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
|
|
|
Mcfe
|
|
|
Cash expense
|
|
$
|
55,200
|
|
|
$
|
0.47
|
|
|
$
|
49,982
|
|
|
$
|
0.52
|
|
|
$
|
38,595
|
|
|
$
|
0.50
|
|
Litigation resolution
|
|
|
5,000
|
|
|
|
0.04
|
|
|
|
9,633
|
|
|
|
0.10
|
|
|
|
-
|
|
|
|
-
|
|
Equity compensation
|
|
|
17,043
|
|
|
|
0.14
|
|
|
|
12,639
|
|
|
|
0.13
|
|
|
|
8,465
|
|
|
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
77,243
|
|
|
$
|
0.65
|
|
|
$
|
72,254
|
|
|
$
|
0.75
|
|
|
$
|
47,060
|
|
|
$
|
0.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Despite a decrease in litigation resolution costs, 2009 legal
fees increased $6.1 million because of our litigation with
BBEP, the Eni Transaction and various other corporate matters.
Non-cash expense for stock-based compensation in 2009 increased
$4.4 million when compared to 2008.
General and administrative expense for 2008 increased
$25.2 million, which included a charge of $9.6 million
in 2008 as a result of the settlement of litigation as discussed
in Note 16 to our consolidated financial statements in
Item 8 of this Annual 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 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 hired 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.
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 Note 5 of our
consolidated financial statements found in Item 8 of this
Annual Report.
Income
from Earnings of BBEP
During 2009, we recognized $75.4 million for equity
earnings from our investment in BBEP. We record our portion of
BBEPs earnings during the quarter in which their financial
statements become publicly available. As a result, our 2009
annual results of operations include BBEPs earnings for
the 12 months ended September 30, 2009. Our 2008
results of operations reflect BBEPs earnings from
November 1, 2007, when we acquired BBEP units, through
September 30, 2008. The increase in equity earnings
recognized during 2009 is primarily due to a significant
reduction in unrealized losses from derivative instruments that
BBEP experienced compared with the prior year
11-month
period. BBEP has continued to experience significant volatility
in its net earnings due to changes in value of its derivative
instruments for which it does not employ hedge accounting.
We recognized $93.3 million of income associated with the
equity earnings from our investment in BBEP in 2008 for the
period 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
BBEPs purchase and retirement of units during 2008.
Impairment
of Investment in BBEP
During the first quarter of 2009, we evaluated our investment in
BBEP for impairment in response to further decreases in
prevailing commodity prices and BBEPs unit price after
December 31, 2008. As a result of these decreases, we made
the determination that the decline in value was
other-than-temporary.
41
Accordingly, our impairment analysis, which utilized the
March 31, 2009 closing price of $6.53 per BBEP unit,
resulted in aggregate fair value of $139.4 million for the
portion of BBEP units that we owned. The $139.4 million
aggregate fair value was compared to the $241.5 million
carrying value of our investment in BBEP. We recorded the
difference of $102.1 million as an impairment charge during
the first quarter of 2009. A similar analysis was performed at
each subsequent quarter-end of 2009, which resulted in no
further impairment. Note 9 to our consolidated financial
statements found in Item 8 of this Annual Report contains
additional information regarding our investment in BBEP.
During the fourth quarter of 2008, our management 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, management determined that the
decrease in fair value of BBEP units was other-than-temporary
and recorded a pre-tax charge of $320.4 million to reduce
the carrying value of our investment in BBEP to its fair value.
Interest
Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(in thousands)
|
|
|
Interest costs on debt outstanding
|
|
$
|
155,696
|
|
|
$
|
105,108
|
|
|
$
|
67,379
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash interest
(1)
|
|
|
18,410
|
|
|
|
13,215
|
|
|
|
10,374
|
|
Non-cash loss on early debt extinguishment
|
|
|
27,122
|
|
|
|
-
|
|
|
|
-
|
|
Less: Interest capitalized
|
|
|
(6,127
|
)
|
|
|
(9,225
|
)
|
|
|
(1,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
195,101
|
|
|
$
|
109,098
|
|
|
$
|
76,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Amortization of deferred financing costs and original issue
discount.
|
|
Interest costs for 2009 were higher than 2008 primarily because
of higher outstanding debt balances, which included the issuance
of our senior notes due 2016 in June 2009 and our senior notes
due 2019 in August 2009. The proceeds from the issuance of the
Senior Notes due 2016 were used to fully repay the Senior
Secured Second Lien Credit Facility in June 2009. At that time,
we recognized additional interest expense of $27.1 million
for the remaining unamortized original issue discount and
deferred financing costs associated with the Senior Secured
Second Lien Facility. Interest rate swaps entered into in June
2009 partially offset increases of interest expense by
$13.7 million for 2009. We expect interest expense to be
in a range of $200 million to $210 million for 2010,
based on current market conditions and expected borrowing levels.
Interest expense for 2008 was higher than 2007 primarily because
of higher average debt outstanding due to the issuance of our
senior notes due 2015 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 the
2008 capital program. The increase in capitalized interest
related 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.
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(in thousands)
|
|
|
Income tax expense (benefit)
|
|
$
|
(291,617
|
)
|
|
$
|
(211,455
|
)
|
|
$
|
254,361
|
|
Effective tax rate
|
|
|
34.8
|
%
|
|
|
36.1
|
%
|
|
|
34.8
|
%
|
Our income tax provision for 2009 changed from 2008 due to a
$251.8 million reduction of pre-tax earnings that resulted
primarily from higher aggregate impairment charges for our oil
and gas properties
42
recognized during 2009 when compared to 2008. The effective tax
rate for 2009 was affected by the resulting taxable net loss in
both the U.S. and Canada that were taxed at approximately
35% and approximately 26%, respectively.
The 2008 provision for income taxes changed dramatically from
2007 due to the loss generated by U.S. operations for
2008. Pre-tax 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
pre-tax 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 exceeded 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.
Quicksilver
Resources Inc. and its Restricted Subsidiaries
Information about Quicksilver and our restricted and
unrestricted subsidiaries is included in Note 20 to our
consolidated financial statements included in Item 8 in
this Annual Report.
The combined results of operations for Quicksilver and our
restricted subsidiaries are substantially similar to our
consolidated results of operations, which are discussed above
under Results of Operations. The combined
financial position of Quicksilver and our restricted
subsidiaries and our consolidated financial position are
materially the same except for the property, plant and equipment
purchased by the unrestricted subsidiaries since the KGS initial
public offering, the borrowings under the KGS Credit Agreement
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 Quicksilver
and our restricted subsidiaries are substantially similar to our
consolidated operating cash flows, financing cash flows and
investing cash flows, which are discussed below in Cash
Flow Activity.
LIQUIDITY,
CAPITAL RESOURCES AND FINANCIAL POSITION
Cash Flow
Activity
Operating
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
612,240
|
|
|
$
|
456,566
|
|
|
$
|
319,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating activities in 2009 increased
because of contributions from working capital including
$54.9 million received from the March 2009 early settlement
of a derivative hedging 40 MMcfd of 2010 natural gas
production and receipt of a $41.1 million U.S. federal
income tax refund. Other components of cash flows provided by
operations for 2009 decreased despite significantly higher
production and lower production expense because of higher
interest payments on our outstanding debt and cash losses from
monthly settlements of the Gas Purchase Commitment.
Additionally, the cash distributions we receive on our BBEP
units decreased $31.4 million from 2008 to
$11.1 million as BBEP eliminated 2009 quarterly
distributions.
Cash flows provided by operating activities in 2008 increased
from 2007 primarily due to 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 earnings from high
production and prices. See additional information regarding
operating activities in Results of Operations.
43
Investing
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Purchases of property, plant and equipment
|
|
$
|
(693,838
|
)
|
|
$
|
(1,286,715
|
)
|
|
$
|
(1,020,684
|
)
|
Alliance Acquisition
|
|
|
-
|
|
|
|
(993,212
|
)
|
|
|
-
|
|
Return of investment from equity affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
9,635
|
|
Proceeds from sales of properties & equipment
|
|
|
220,974
|
|
|
|
1,339
|
|
|
|
741,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
$
|
(472,864
|
)
|
|
$
|
(2,278,588
|
)
|
|
$
|
(269,752
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For each of the three years ended December 31, 2009, we
have spent significant cash resources for the development of our
large acreage positions in our core areas in Texas and Alberta.
In addition, our expenditures for gas processing and gathering
assets have grown significantly as part of our growth in Texas.
We completed several significant transactions over the three
years ended December 31, 2009, including the 2009 Eni
Transaction with net cash proceeds of $219.2 million, our
2008 Alliance Acquisition for cash of $1.0 billion and the
2007 divestiture of our Northeast Operations that resulted in
cash proceeds of $741.1 million.
We reduced our 2009 exploration and development activity from
2008 levels in response to lower natural gas and NGL prices. Of
the $693.8 million of cash paid for property, plant and
equipment during 2009, 79% was invested in our oil and natural
gas properties and 20% was invested in our gas processing and
gathering operations. We drilled 154 (93.2 net) wells in the
Fort Worth Basin and 141 (36.1 net) wells in Alberta. Our
2009 midstream capital investment of $123.0 million was
primarily related to expansion of our Texas gas processing and
gathering facilities.
Our 2008 purchases of property, plant and equipment reflect our
expansion in our core operating areas in Texas and Alberta. In
2008, we purchased approximately 90 producing wells in the
Alliance Acquisition and drilled 296 (259.7 net) wells in Texas
and 373 (156.9 net) wells in Alberta. 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 Alberta.
Additionally, we invested $168.5 million and
$3.4 million for Texas and Canadian gas processing and
gathering facilities, respectively.
We currently estimate that our spending for property, plant and
equipment in 2010 will be approximately $540 million, of which
we have allocated $390 million for drilling and completion
activities, including $340 million in Texas,
$34 million in Canada and $17 million in other areas
in the U.S. We have also budgeted $92 million for
gathering and processing facilities (including $80 million
to be funded directly by KGS), $53 million for acquisition
of additional leasehold interests and $4 million for other
property and equipment.
44
Financing
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Issuance of debt
|
|
$
|
1,420,727
|
|
|
$
|
2,948,672
|
|
|
$
|
817,821
|
|
Repayments of debt
|
|
|
(1,649,630
|
)
|
|
|
(1,096,163
|
)
|
|
|
(968,557
|
)
|
Debt issuance costs
|
|
|
(32,472
|
)
|
|
|
(25,219
|
)
|
|
|
(5,130
|
)
|
Gas Purchase Commitment
|
|
|
58,294
|
|
|
|
-
|
|
|
|
-
|
|
Gas Purchase Commitment repayments
|
|
|
(14,175
|
)
|
|
|
-
|
|
|
|
-
|
|
Issuance of KGS common units
|
|
|
80,729
|
|
|
|
-
|
|
|
|
109,809
|
|
Distributions paid on KGS common units
|
|
|
(9,925
|
)
|
|
|
(8,644
|
)
|
|
|
(8,794
|
)
|
Proceeds from exercise of stock options
|
|
|
4,046
|
|
|
|
1,244
|
|
|
|
21,387
|
|
Excess tax benefit on exercise of stock options
|
|
|
-
|
|
|
|
-
|
|
|
|
2,755
|
|
Purchase of treasury stock
|
|
|
(922
|
)
|
|
|
(23,137
|
)
|
|
|
(1,567
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
$
|
(143,328
|
)
|
|
$
|
1,796,753
|
|
|
$
|
(32,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows from financing activities for 2009 reflect our
efforts to restructure and reduce our debt outstanding at
December 31, 2008. In 2009, we received total proceeds of
$873.1 million from the issuance of our senior notes due
2016 with a principal amount of $600 million and our senior
notes due 2019 with a principal amount of $300 million.
The senior notes due 2016 bear interest at the rate of 11.75%
paid semiannually on January 1 and July 1. The senior
notes due 2019 bear interest at the rate of 9.125% paid
semiannually on February 15 and August 15. Borrowings and
repayments in 2009 under the Senior Secured Credit Facility were
$492 million and $890 million, respectively, which
resulted in a net decrease of $398 million outstanding in
2009. KGS increased borrowings under the KGS Credit Agreement
by $49.5 million in 2009.
Proceeds from the debt issuances and the Eni Transaction were
used to repay and terminate the remaining indebtedness under our
Senior Secured Second Lien Facility and to repay a portion of
the outstanding borrowings under the Senior Secured Credit
Facility. The KGS Secondary Offering, completed in December
2009, resulted in net proceeds of $80.3 million for
4,000,000 common units and reduced our ownership interest in KGS
from approximately 73% to approximately 62% as of
December 31, 2009. In January 2010, the underwriters
exercised their option to purchase an additional 549,200 KGS
common units for $11.1 million, which further reduced our
ownership of KGS to approximately 61%.
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 due
2015 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 was reflected in financing cash flows.
Liquidity
and Borrowing Capacity
Our Senior Secured Credit Facility matures on February 9,
2012. The borrowing base at December 31, 2009 was
$1.0 billion which was the result of a redetermination in
October 2009. The Senior Secured Credit Facility currently
provides us an option to increase the commitment by up to
$250 million, with a maximum of $1.45 billion with
lender consents and additional commitments. We can also extend
the facility up to two additional years with lenders
approval. The borrowing base is subject to at least an annual
redetermination.
45
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 lenders commitments under the
facility are allocated between U.S. and Canadian funds.
U.S. borrowings under the facility are secured by, among
other things, Quicksilvers and our
U.S. subsidiaries oil and gas properties. Canadian
borrowings under the facility are secured by, among other
things, all of our oil and gas properties. We also pledged our
equity interests in BBEP to secure our obligations under the
Senior Secured Credit Facility. At December 31, 2009,
there was approximately $498 million available under the
facility. In January 2010, we repaid $95 million of
borrowings outstanding under the Senior Secured Credit Facility
using the proceeds from the sale of the Alliance Midstream
Assets to KGS. 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.
The KGS Credit Agreement matures August 10, 2012, but may
be extended up to two additional years with lenders
approval. In October 2009, the lenders increased their
commitments to a total of $320 million. At
December 31, 2009, KGS had approximately $172 million
available under the KGS Credit Agreement. The KGS Credit
Agreement permits further expansion to as much as
$350 million, subject to lender consent and additional
commitments. KGS must maintain certain financial ratios that
can limit its borrowing capacity. KGS ability to remain
in compliance with the financial covenants in its credit
agreement may be affected by events beyond our or KGS
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 agreement and by accelerating the maturity of its
indebtedness. KGS received $11.1 million from the
underwriters January exercise of their option to purchase
an additional 549,200 units and repaid $11 million of
borrowings outstanding under the KGS Credit Agreement. KGS also
re-borrowed $95 million under the KGS Credit Agreement to
fund KGS purchase of the Alliance Midstream Assets.
Additional information about our debt and related covenants are
more fully described in Note 13 to the consolidated
financial statements in Item 8 of this Annual Report.
We believe that our capital resources are adequate to meet the
requirements of our existing business. We anticipate that our
2010 capital expenditure program of approximately
$540 million will be funded by cash flow from operations.
We may, from time to time during 2010, make borrowings under the
Senior Secured Credit Facility, but expect that for all of 2010
to require no incremental borrowings above 2009 levels.
Conversely, we anticipate that KGS may experience increases to
its outstanding borrowings to fund further development of its
gathering and treating capacity in the Alliance area.
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,
2009, as compared to our balance sheet as of December 31,
2008:
|
|
|
|
|
Our current and non-current derivative assets and liabilities
decreased $165.8 million on a net basis. Our net open
derivative position decreased $310.9 million because of
monthly settlements during 2009 and $54.9 million received
for early settlement of a derivative hedging a portion of our
2010 production. The valuation of our open derivative positions
at December 31, 2009 partially offset these decreases. Our
current deferred income tax liability related to our derivatives
was almost unchanged
|
46
|
|
|
|
|
because of changes in the allocation of open derivative
positions between the U.S. and Canada and the difference
between U.S. and Canadian statutory tax rates.
|
|
|
|
|
|
Our net property, plant and equipment balance decreased
$711.8 million from December 31, 2008 to
December 31, 2009. During 2009, we recorded charges for
impairment of our oil and gas properties of $979.5 million
and 2009 DD&A expense of $199.1 million. Our
property, plant and equipment balances were also decreased by
proceeds of $219.6 million for the Eni Transaction. These
decreases were partially offset by $601.7 million of costs
incurred for property, plant and equipment, and an additional
$84.7 million for changes to
U.S.-Canadian
exchange rates and assets recognized when retirement obligations
were established for new wells and facilities.
|
|
|
|
Our deferred income tax liability has decreased
$192.5 million and a U.S. deferred tax asset of
$133.1 million was recognized in connection with the
impairments of both our investment in BBEP and our U.S. oil
and gas properties.
|
|
|
|
Equity held by noncontrolling interests increased
$34.1 million, which consisted of $30.1 million from
the KGS Secondary Offering, employee unit compensation of
$1.7 million and income attributable to noncontrolling
interests of $12.2 million partially offset by
$9.9 million of distributions paid to noncontrolling
interests.
|
Contractual
Obligations and Commercial Commitments
Contractual Obligations. Information regarding
our contractual and scheduled interest obligations, at
December 31, 2009, is set forth in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less than
|
|
|
1-3
|
|
|
4-5
|
|
|
More than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Long-term debt
|
|
$
|
2,467,969
|
|
|
$
|
-
|
|
|
$
|
592,969
|
|
|
$
|
475,000
|
|
|
$
|
1,400,000
|
|
Scheduled interest obligations
|
|
|
1,135,247
|
|
|
|
166,782
|
|
|
|
494,438
|
|
|
|
309,705
|
|
|
|
164,322
|
|
Transportation and processing contracts
|
|
|
629,116
|
|
|
|
43,909
|
|
|
|
238,382
|
|
|
|
157,272
|
|
|
|
189,553
|
|
Drilling rig contracts
|
|
|
96,606
|
|
|
|
45,519
|
|
|
|
51,087
|
|
|
|
-
|
|
|
|
-
|
|
Gas Purchase Commitment
|
|
|
50,744
|
|
|
|
50,744
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchase obligations
|
|
|
24,827
|
|
|
|
19,554
|
|
|
|
5,273
|
|
|
|
-
|
|
|
|
-
|
|
Asset retirement obligations
|
|
|
59,378
|
|
|
|
109
|
|
|
|
195
|
|
|
|
130
|
|
|
|
58,944
|
|
Unrecognized tax benefits
|
|
|
9,219
|
|
|
|
-
|
|
|
|
9,219
|
|
|
|
-
|
|
|
|
-
|
|
Operating lease obligations
|
|
|
7,928
|
|
|
|
2,678
|
|
|
|
4,274
|
|
|
|
976
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations
|
|
$
|
4,481,034
|
|
|
$
|
329,295
|
|
|
$
|
1,395,837
|
|
|
$
|
943,083
|
|
|
$
|
1,812,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt. As of December 31, 2009,
our outstanding indebtedness included $468 million
outstanding under our Senior Secured Credit Facility,
$475 million of Senior Notes due 2015, $600 million of
Senior Notes due 2016, $300 million of Senior Notes due
2019, $350 million of Senior Subordinated Notes,
$150 million of contingently convertible debentures and
$125 million outstanding under the KGS Credit Facility (all
before original issue discount). Based upon our debt
outstanding and interest rates in effect at December 31,
2009, we anticipate interest payments, including our scheduled
interest obligations, to be approximately $184.3 million in
2010. Although we do not expect year-over-year increased
borrowings under our Senior Secured Credit Facility during 2010,
should we be required to increase those borrowings and based on
interest rates in effect at December 31, 2009, an
additional $50 million in borrowings would result in
additional annual interest payments of approximately
$1.7 million. If the current borrowing base under our
Senior Secured Credit Facility were to be fully utilized by
year-end 2010 at interest rates in effect at December 31,
2009, we estimate that annual interest payments would increase
by approximately $16.5 million. If interest rates on our
December 31, 2009 variable debt balances of approximately
$1.4 billion, including $825 million subject to fixed
to
|
47
|
|
|
|
|
floating interest rate swaps, increase or decrease by one
percentage point, our annual pre-tax income would decrease or
increase by $14.2 million.
|
|
|
|
|
|
Scheduled Interest Obligations. As of
December 31, 2009, we had scheduled interest payments of
$39.2 million annually on our Senior Notes due 2015,
$70.5 million annually on our Senior Notes due 2016,
$27.4 million annually on our Senior Notes due 2019,
$24.9 million annually on our $350 million of Senior
Subordinated Notes and $2.8 million annually on our
$150 million of contingently convertible debentures.
Additional interest of $1.3 million and $0.7 million
is payable in 2010 on the Senior Secured Credit Facility and KGS
Credit Agreement, respectively.
|
|
|
|
Transportation and Processing Contracts. Under contracts
with various pipeline and processing companies, we are obligated
to provide minimum daily natural gas volumes for transport or
processing, as calculated on a monthly basis, or pay for any
volume deficiencies at a specified reservation fee rate. Our
production committed to the pipelines or processing plants is
expected to meet, or exceed, the daily volumes provided in the
contracts.
|
|
|
|
Drilling Rig Contracts. We utilize drilling
rigs from third parties in our development and exploration
programs. The outstanding drilling rig contracts require
payment of a specified day rate ranging from $20,500 to $26,500
for the entire lease term regardless of our utilization of the
drilling rigs.
|
|
|
|
Gas Purchase Commitment. Pursuant to the Eni
Transaction we agreed to purchase Enis share of Alliance
Leasehold production at $8.60 per MMBtu less costs related to
gathering and processing Enis Alliance Production through
December 2010.
|
|
|
|
Purchase Obligations. At December 31,
2009, we and KGS were under contract to purchase goods and
services for use in field and gas plant operations. KGS
remaining cash obligations for such items were $7.4 million.
|
|
|
|
Asset Retirement Obligations. Our obligations
result from the acquisition, construction or development and the
normal operation of our long-lived assets.
|
|
|
|
Unrecognized Tax Benefits. We have recorded
obligations that have resulted from tax benefit claims in our
tax returns that do not meet the recognition standard of more
likely than not to be sustained upon examination by tax
authorities. The $9.2 million balance of unrecognized tax
benefits includes $8.9 million of amounts that, if
recognized, would reduce our effective tax rate.
|
|
|
|
Operating Lease Obligations. We lease office
buildings and other property under operating leases.
|
Commercial Commitments. We had the following
commercial commitments as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts of Commitments by Expiration Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than
|
|
|
1-3
|
|
|
4-5
|
|
|
More than
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Surety bonds
|
|
$
|
39,069
|
|
|
$
|
39,069
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standby letters of credit
|
|
|
34,522
|
|
|
|
34,522
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
73,591
|
|
|
$
|
73,591
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Surety Bonds. Our surety bonds have been
issued to fulfill contractual, legal or regulatory
requirements. Surety bonds generally have an annual renewal
option.
|
|
|
|
Standby Letters of Credit. Our letters of
credit have been issued to fulfill contractual or regulatory
requirements, including $21.4 million issued to provide
credit support for surety bonds. All of these letters of credit
were issued under our Senior Secured Credit Facility and
generally have an annual renewal option.
|
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
48
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 Note 2
to the consolidated financial statements included in Item 8
of this Annual Report. Management believes that the following
accounting estimates are the most critical in fully
understanding and evaluating our reported financial results, and
they require managements 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.
Oil and
Gas Reserves
Policy
Description
Proved oil and gas reserves are the estimated quantities of 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. In December 2008, the SEC adopted its
final rule for Modernization of Oil and Gas
Reporting. The most significant changes incorporated into
our proved reserve process and related disclosures for 2009
include:
|
|
|
|
|
the use of an unweighted average of the preceding
12-month
first-day-of-the-month
prices for determination of proved reserve values included in
calculating full cost ceiling limitations and for annual proved
reserve disclosures;
|
|
|
consideration of and limitations on the types of technologies
that may be used to reliably establish and estimate proved
reserves;
|
|
|
reporting of investments and progress made during the year to
convert proved undeveloped reserves to proved developed
reserves; and,
|
|
|
reporting on the independence and qualifications of our
personnel and independent petroleum engineers who are
responsible for the preparation of our reserve estimates.
|
Operating costs are the period end operating cost at the time of
the reserve estimate and held constant. 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. Our proved reserve estimates and
related disclosures for 2009 are presented in compliance with
this new guidance. Our 2008 and 2007 proved reserve estimates
and related disclosures were prepared in compliance with the SEC
guidance then in effect. Additional information regarding our
estimated proved oil and gas reserves may be found under
Oil and Natural Gas Reserves found in Item 1 of
this Annual Report.
Judgments
and Assumptions
All of the reserve data in this Annual Report are based on
estimates. Estimates of our oil, natural gas and NGL reserves
are prepared in accordance with guidelines established by the
SEC. Reservoir engineering is a subjective process of
estimating recoverable underground accumulations of oil, natural
gas and NGLs. There are numerous uncertainties inherent in
estimating recoverable quantities of proved 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 oil, natural
gas and NGLs that are ultimately recovered.
The passage of time provides more qualitative information
regarding estimates of reserves, and revisions are made to prior
estimates to reflect updated information. The weighted average
annual revisions to our
49
reserve estimates have been less than 2% of the weighted average
previous years 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.
For example, if estimates of proved reserves decline, the
depletion rate will increase, resulting in a decrease in net
income.
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 calculated and 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 (1) estimated future net revenue, discounted at 10%
per annum, from proved reserves, based on the unweighted average
of the preceding
12-month
first day-of the-month prices (year-end prices for 2008 and
2007) adjusted to reflect local differentials and contract
provisions, unescalated year-end costs and financial derivatives
that hedge the our oil and gas revenue, (2) the cost of
properties not being amortized, (3) the lower of cost or
market value of unproved properties included in the cost being
amortized less (4) 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 cash flows from our
proved oil, natural gas and NGL reserves is the major component
of the ceiling calculation, and is determined in connection with
the estimation of our proved oil, natural gas and NGL reserves.
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.
While the quantities of proved reserves require substantial
judgment, the associated prices of natural gas, NGL and oil
reserves, and the applicable discount rate, that are used to
calculate the discounted present value of the reserves do not
require judgment. Current SEC rules require the use of the
future net cash flows from proved reserves discounted at 10%.
Therefore, the future net cash flows associated with the
estimated proved reserves is not based on our assessment of
future prices or costs. In calculating the ceiling, we adjust
the future net cash flows by the discounted value of derivative
contracts in place that hedge future prices. This valuation is
determined by calculating the difference between reserve pricing
and the contract prices for such hedges also discounted at 10%.
Because the ceiling calculation dictates that our historical
experience, excluding the effects of benefits derived from our
ownership of KGS, be 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, forecasted prices can be either
50
substantially higher or lower than our historical experience.
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.
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.
The fair values of our natural gas and NGL derivatives and the
Gas Purchase Commitment as of December 31, 2009 were
estimated using published market prices of natural gas and NGLs
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.
For derivative instruments that qualify as fair value hedges the
gains or losses on the derivative instruments are recognized
currently in earnings while the gains or losses on the hedged
items adjust the carrying value of the hedged items and are
recognized currently in earnings. Any gains or losses on the
derivative instruments not offset by the gains or losses on the
hedged items are recognized as the value of ineffectiveness in
the hedge relationships. For interest rate swaps that qualify
as fair value hedges of our fixed-rate debt outstanding,
ineffectiveness is recognized currently as a component of
interest expense.
The fair value of our interest rate derivatives was estimated
using published LIBOR interest rates for the periods covered by
the contracts. The estimates were determined by applying the
net differential between the interest rate in each derivative
and interest rates for future periods, to the notional amount
stipulated in each contract to arrive at estimated future cash
flow streams.
Judgments
and Assumptions
The estimates of the fair values of our commodity and interest
rate 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. Future changes to forecasted or realized commodity
prices could result in significantly different values and
realized cash flows for such instruments.
51
Stock-based
Compensation
Policy
Description
An estimate of fair value is determined for all share-based
payment awards. Recognition of compensation expense for all
share-based payment awards is recognized over the vesting period
for each award.
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 or
expected to be 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 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 us. 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.
52
RECENTLY
ISSUED ACCOUNTING STANDARDS
The information regarding recent accounting pronouncements is
included in Note 2 to our consolidated financial statements
in Item 8 of this Annual Report, which is incorporated
herein by reference.
|
|
ITEM 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Commodity
Price Risk
We enter into financial derivative contracts to mitigate our
exposure to commodity price risk associated with anticipated
future production and to increase the predictability of our
revenue. As of December 31, 2009, forecasted natural gas
production of 200 MMcfd has been hedged with natural gas
price collars and 10 MBbld of forecasted NGL production has
been hedged with NGL price swaps for 2010. Additionally,
120 MMcfd of natural gas price collars and 5 MBbld of
NGL price swaps have been executed to hedge anticipated 2011
production and 60 MMcfd of 2012 anticipated natural gas
production has been hedged using natural gas price collars.
Utilization of our financial hedging program will most often
result in realized prices from the sale of our natural gas, NGL
and oil that vary from market prices. As a result of
settlements of derivative contracts, our revenue from natural
gas, NGL and oil production was $310.9 million higher for
2009, $18.4 million lower for 2008 and $51.1 million
higher for 2007, respectively.
53
The following table details our open derivative positions as of
December 31, 2009 and those we have entered into after that
date related to our anticipated natural gas and NGL production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Avg
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Per Mcf or
|
|
|
|
|
Product
|
|
Type
|
|
|
Contract Period
|
|
|
Volume
|
|
|
Bbl
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
$
|
8.00-11.00
|
|
|
$
|
17,163
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
8.00-11.00
|
|
|
|
17,163
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
8.00-12.20
|
|
|
|
17,289
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
8.00-12.20
|
|
|
|
17,289
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
10 MMcfd
|
|
|
|
8.50-12.05
|
|
|
|
10,320
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
8.50-12.05
|
|
|
|
20,640
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
10 MMcfd
|
|
|
|
8.50-12.08
|
|
|
|
10,328
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2011
|
|
|
|
10 MMcfd
|
|
|
|
6.00-7.00
|
|
|
|
1,921
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2011
|
|
|
|
10 MMcfd
|
|
|
|
6.00-7.00
|
|
|
|
1,921
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2011
|
|
|
|
20 MMcfd
|
|
|
|
6.00-7.00
|
|
|
|
3,843
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2012
|
|
|
|
20 MMcfd
|
|
|
|
6.50-7.15
|
|
|
|
10,456
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2010-Dec 2012
|
|
|
|
20 MMcfd
|
|
|
|
6.50-7.18
|
|
|
|
10,993
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
10 MMcfd
|
|
|
|
6.25-7.50
|
|
|
|
1,187
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
10 MMcfd
|
|
|
|
6.25-7.50
|
|
|
|
1,187
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
20 MMcfd
|
|
|
|
6.25-7.50
|
|
|
|
2,374
|
|
Gas
|
|
|
Collar
|
|
|
|
Jan 2012-Dec 2012
|
|
|
|
20 MMcfd
|
|
|
|
6.50-8.01
|
|
|
|
3,277
|
|
Gas
|
|
|
Basis
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
(1)
|
|
|
|
(638
|
)
|
Gas
|
|
|
Basis
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
(1)
|
|
|
|
(638
|
)
|
Gas
|
|
|
Basis
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
10 MMcfd
|
|
|
|
(1)
|
|
|
|
122
|
|
Gas
|
|
|
Basis
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
10 MMcfd
|
|
|
|
(1)
|
|
|
|
122
|
|
Gas
|
|
|
Basis
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
20 MMcfd
|
|
|
|
(1)
|
|
|
|
243
|
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
2 MBld
|
|
|
$
|
32.65
|
|
|
|
(6,930
|
)
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
3 MBld
|
|
|
|
32.98
|
|
|
|
(9,752
|
)
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
1 MBld
|
|
|
|
33.63
|
|
|
|
(3,108
|
)
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
1 MBld
|
|
|
|
34.15
|
|
|
|
(2,980
|
)
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2010-Dec 2010
|
|
|
|
3 MBld
|
|
|
|
34.22
|
|
|
|
(8,397
|
)
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
3 MBld
|
|
|
|
36.06
|
|
|
|
(4,333
|
)
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
2 MBld
|
|
|
|
36.31
|
|
|
|
(3,181
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
$
|
107,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Basis swaps hedge the AECO basis adjustment at a deduction of
$0.45 per Mcf from NYMEX for 2010 and $0.39 per Mcf from NYMEX
for 2011. |
Since December 31, 2009, we have entered into the following
NGL and natural gas basis swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Avg
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Per
|
|
Product
|
|
Type
|
|
|
Contract Period
|
|
|
Volume
|
|
|
Mcf or Bbl
|
|
|
NGL
|
|
|
Swap
|
|
|
|
Jan 2011-Dec 2011
|
|
|
|
3 MBbld
|
|
|
$
|
41.95
|
|
Gas
|
|
|
Basis
|
|
|
|
Feb 2010-Dec 2010
|
|
|
|
20 MMcfd
|
|
|
|
(2)
|
|
Gas
|
|
|
Basis
|
|
|
|
Apr 2010-Dec 2010
|
|
|
|
10 MMcfd
|
|
|
|
(3)
|
|
Gas
|
|
|
Basis
|
|
|
|
Apr 2010-Dec 2010
|
|
|
|
10 MMcfd
|
|
|
|
(3)
|
|
54
|
|
|
(2) |
|
Basis swap hedges the Houston Ship Channel basis adjustment at a
deduction of $0.09 per Mcf from NYMEX for February through
December 2010. |
|
(3) |
|
Basis swaps hedge the Houston Ship Channel basis adjustment at
deductions of $0.45 and $0.425 per Mcf, respectively, from NYMEX
for April through December 2010. |
Based on information available on June 19, 2009, we
recognized a liability pursuant to the Gas Purchase Commitment
for the estimated production volumes attributable to Eni through
December 31, 2010, which then totaled 22.2 Bcf. The
remaining Gas Purchase Commitment is adjusted to fair value
throughout the period of the commitment, which expires on
December 31, 2010. We recognized a $6.6 million
increase in the remaining liability between June 19 and
December 31, 2009 and recorded a valuation loss as a
component of costs of purchased natural gas. At
December 31, 2009, we had a remaining liability of
$50.7 million, including the $6.6 million liability
for the change in value since initial valuation. The following
summarizes activity to the Gas Purchase Commitment:
|
|
|
|
|
(In thousands)
|
|
|
Initial valuation of
liability(1)
|
|
$
|
58,294
|
|
Decrease due to gas volumes purchased
|
|
|
(14,175
|
)
|
Embedded derivative increase (decrease) due to:
|
|
|
|
|
Price changes
|
|
|
7,904
|
|
Volume changes
|
|
|
(1,279
|
)
|
|
|
|
|
|
Total embedded derivative
|
|
|
6,625
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
$
|
50,744
|
|
|
|
|
|
|
|
|
|
(1) |
|
Initial valuation of the Gas Purchase Commitment was estimated
using estimated Eni production volumes from June 19, 2009
through December 2010 and published future market prices and
risk-adjusted interest rates as of June 19, 2009. |
Interest
Rate Risk
The interest income or expense from our interest rate swaps is
accrued as earned and recorded as an adjustment to the interest
expense accrued on two fixed-rate debt issues, our senior notes
due 2015 and our senior subordinated notes. These interest rate
swaps qualified and were accounted for as fair value hedges.
During 2009 settlements under the interest rate swaps decreased
interest expense by $13.7 million, which resulted in
average effective interest rates of approximately 5.1% and 3.7%
on the senior notes due 2015 and the senior subordinated debt,
respectively.
In February 2010, we executed early settlement of our interest
rate swaps on our senior notes due 2015 and our senior
subordinated notes. We received cash of $18.0 million in
the settlement, which has been recorded as an adjustment to the
carrying value of the debt and will be amortized to earnings
over the life of the associated underlying debt instruments.
We subsequently entered into new interest rate swaps on our
senior notes due 2015 and our senior subordinated notes that
convert the interest paid on those issues from a fixed to a
floating rate indexed to six-month LIBOR. The maturity dates and
all other significant terms are the same as those of the
underlying debt. As a result, these interest rate swaps
qualified for hedge accounting treatment as fair value hedges.
Foreign
Currency Risk
Our Canadian subsidiary uses the Canadian dollar as its
functional currency. To the extent that business transactions in
Canada are not denominated in Canadian dollars, we are exposed
to foreign currency exchange rate risk. For 2009, 2008 and 2007,
non-functional currency transactions resulted in losses of
$2.2 million, $3.3 million and $0.8 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 our
available borrowing capacity.
55
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, 2009 and 2008, and
the related consolidated statements of income (loss) and
comprehensive income (loss), equity, and cash flows for each of
the three years in the period ended December 31,
2009. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on the 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 the
Quicksilver Resources Inc. and subsidiaries at December 31,
2009 and 2008, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 2009, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial
statements, on December 31, 2009, the Company adopted
Accounting Standards Update
No. 2010-3,
Oil and Gas Reserve Estimation and Disclosures.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2009, based on the criteria established in
Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 15, 2010 expressed an
unqualified opinion on the Companys internal control over
financial reporting.
/s/
Deloitte &
Touche LLP
Fort Worth, Texas
March 15, 2010
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil
|
|
$
|
796,698
|
|
|
$
|
780,788
|
|
|
$
|
545,089
|
|
Sales of purchased natural gas
|
|
|
23,654
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
12,383
|
|
|
|
19,853
|
|
|
|
16,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
832,735
|
|
|
|
800,641
|
|
|
|
561,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production expense
|
|
|
127,715
|
|
|
|
134,302
|
|
|
|
136,103
|
|
Production and ad valorem taxes
|
|
|
23,881
|
|
|
|
18,734
|
|
|
|
17,048
|
|
Costs of purchased natural gas
|
|
|
30,158
|
|
|
|
-
|
|
|
|
-
|
|
Other operating expense
|
|
|
6,684
|
|
|
|
3,337
|
|
|
|
2,614
|
|
Depletion, depreciation and accretion
|
|
|
201,387
|
|
|
|
188,196
|
|
|
|
120,697
|
|
General and administrative expense
|
|
|
77,243
|
|
|
|
72,254
|
|
|
|
47,060
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expense
|
|
|
467,068
|
|
|
|
416,823
|
|
|
|
323,522
|
|
Impairment related to oil and gas properties
|
|
|
(979,540
|
)
|
|
|
(633,515
|
)
|
|
|
-
|
|
Income from equity affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
661
|
|
Gain on sale of oil and gas properties
|
|
|
-
|
|
|
|
-
|
|
|
|
628,709
|
|
Loss on natural gas sales contract
|
|
|
-
|
|
|
|
-
|
|
|
|
(63,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(613,873
|
)
|
|
|
(249,697
|
)
|
|
|
803,581
|
|
Income from earnings of BBEP
|
|
|
75,444
|
|
|
|
93,298
|
|
|
|
-
|
|
Impairment of investment in BBEP
|
|
|
(102,084
|
)
|
|
|
(320,387
|
)
|
|
|
-
|
|
Other income (expense) net
|
|
|
(1,242
|
)
|
|
|
807
|
|
|
|
3,887
|
|
Interest expense
|
|
|
(195,101
|
)
|
|
|
(109,098
|
)
|
|
|
(76,662
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(836,856
|
)
|
|
|
(585,077
|
)
|
|
|
730,806
|
|
Income tax (expense) benefit
|
|
|
291,617
|
|
|
|
211,455
|
|
|
|
(254,361
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(545,239
|
)
|
|
|
(373,622
|
)
|
|
|
476,445
|
|
Net income attributable to noncontrolling interests
|
|
|
(12,234
|
)
|
|
|
(4,654
|
)
|
|
|
(1,055
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Quicksilver
|
|
$
|
(557,473
|
)
|
|
$
|
(378,276
|
)
|
|
$
|
475,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustments related to settlements of
derivative contracts net of income tax
|
|
|
(211,863
|
)
|
|
|
11,969
|
|
|
|
(34,648
|
)
|
Net change in derivative fair value net of income tax
|
|
|
125,989
|
|
|
|
182,472
|
|
|
|
(14,794
|
)
|
Foreign currency translation adjustment
|
|
|
22,106
|
|
|
|
(49,403
|
)
|
|
|
29,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(621,241
|
)
|
|
$
|
(233,238
|
)
|
|
$
|
455,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share basic
|
|
$
|
(3.30
|
)
|
|
$
|
(2.33
|
)
|
|
$
|
3.04
|
|
Earnings (loss) per common share diluted
|
|
$
|
(3.30
|
)
|
|
$
|
(2.33
|
)
|
|
$
|
2.87
|
|
Basic weighted average shares outstanding
|
|
|
169,004
|
|
|
|
162,004
|
|
|
|
156,517
|
|
Diluted weighted average shares outstanding
|
|
|
169,004
|
|
|
|
162,004
|
|
|
|
168,029
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
58
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,785
|
|
|
$
|
2,848
|
|
Accounts receivable net of allowance for doubtful
accounts
|
|
|
65,253
|
|
|
|
143,315
|
|
Derivative assets at fair value
|
|
|
97,957
|
|
|
|
171,740
|
|
Other current assets
|
|
|
54,943
|
|
|
|
75,433
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
219,938
|
|
|
|
393,336
|
|
Investments in equity affiliates
|
|
|
112,763
|
|
|
|
150,503
|
|
Property, plant and equipment net
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method (including
unevaluated
costs of $458,037 and $543,533, respectively)
|
|
|
2,338,244
|
|
|
|
3,142,608
|
|
Other property and equipment
|
|
|
747,696
|
|
|
|
655,107
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment net
|
|
|
3,085,940
|
|
|
|
3,797,715
|
|
Derivative assets at fair value
|
|
|
14,427
|
|
|
|
116,006
|
|
Deferred income taxes
|
|
|
133,051
|
|
|
|
|
|
Other assets
|
|
|
46,763
|
|
|
|
40,648
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,612,882
|
|
|
$
|
4,498,208
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
|
|
|
$
|
6,579
|
|
Accounts payable
|
|
|
157,986
|
|
|
|
282,636
|
|
Accrued liabilities
|
|
|
156,604
|
|
|
|
66,963
|
|
Derivative liabilities at fair value
|
|
|
395
|
|
|
|
9,928
|
|
Current deferred tax liability
|
|
|
51,675
|
|
|
|
52,393
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
366,660
|
|
|
|
418,499
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
2,427,523
|
|
|
|
2,586,045
|
|
Asset retirement obligations
|
|
|
59,268
|
|
|
|
34,753
|
|
Other liabilities
|
|
|
20,691
|
|
|
|
12,962
|
|
Deferred income taxes
|
|
|
41,918
|
|
|
|
234,386
|
|
Commitments and contingencies (Note 16)
|
|
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
|
|
|
Preferred stock, par value $0.01, 10,000,000 shares
authorized, none outstanding
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, 400,000,000 and
200,000,000 shares authorized,
respectively; 174,469,836 and 171,742,699 shares issued,
respectively
|
|
|
1,745
|
|
|
|
1,717
|
|
Paid in capital in excess of par value
|
|
|
730,265
|
|
|
|
656,958
|
|
Treasury stock of 4,704,448 and 4,572,795 shares,
respectively
|
|
|
(36,363
|
)
|
|
|
(35,441
|
)
|
Accumulated other comprehensive income
|
|
|
121,336
|
|
|
|
185,104
|
|
Retained earnings (deficit)
|
|
|
(180,985
|
)
|
|
|
376,488
|
|
|
|
|
|
|
|
|
|
|
Quicksilver stockholders equity
|
|
|
635,998
|
|
|
|
1,184,826
|
|
Noncontrolling interests
|
|
|
60,824
|
|
|
|
26,737
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
696,822
|
|
|
|
1,211,563
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,612,882
|
|
|
$
|
4,498,208
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quicksilver Resources Inc. Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Paid-in
|
|
|
Treasury
|
|
|
Comprehensive
|
|
|
Retained
|
|
|
Noncontrolling
|
|
|
|
|
|
|
Stock
|
|
|
Capital
|
|
|
Stock
|
|
|
Income
|
|
|
Earnings
|
|
|
Interest
|
|
|
Total
|
|
|
Balances at December 31. 2006
|
|
$
|
1,578
|
|
|
$
|
264,078
|
|
|
$
|
(10,737
|
)
|
|
$
|
60,099
|
|
|
$
|
279,719
|
|
|
$
|
7,382
|
|
|
$
|
602,119
|
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
475,390
|
|
|
|
1,055
|
|
|
|
476,445
|
|
Adoption of new rules for uncertain tax positions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(345
|
)
|
|
|
-
|
|
|
|
(345
|
)
|
Hedge derivative contract settlements reclassified into earnings
from accumulated other comprehensive income, net of income tax
of $16,491
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(34,648
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(34,648
|
)
|
Net change in derivative fair value, net income tax of $8,436
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(14,794
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(14,794
|
)
|
Foreign currency translation adjustment
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
29,409
|
|
|
|
-
|
|
|
|
-
|
|
|
|
29,409
|
|
Issuance & vesting of stock compensation
|
|
|
6
|
|
|
|
13,863
|
|
|
|
(1,567
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
129
|
|
|
|
12,431
|
|
Stock option exercises, including income tax benefits
|
|
|
22
|
|
|
|
21,365
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
21,387
|
|
Issuance of KGS common units
|
|
|
-
|
|
|
|
79,316
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
29,942
|
|
|
|
109,258
|
|
Distributions paid on KGS common units
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8,794
|
)
|
|
|
(8,794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31. 2007
|
|
|
1,606
|
|
|
|
378,622
|
|
|
|
(12,304
|
)
|
|
|
40,066
|
|
|
|
754,764
|
|
|
|
29,714
|
|
|
|
1,192,468
|
|
Net income (loss)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(378,276
|
)
|
|
|
4,654
|
|
|
|
(373,622
|
)
|
Hedge derivative contract settlements reclassified into earnings
from accumulated other comprehensive income, net of income tax
of $6,424
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,969
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,969
|
|
Net change in derivative fair value, net income tax of $93,251
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
182,472
|
|
|
|
-
|
|
|
|
-
|
|
|
|
182,472
|
|
Foreign currency translation adjustment
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(49,403
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(49,403
|
)
|
Issuance & vesting of stock compensation
|
|
|
5
|
|
|
|
15,106
|
|
|
|
(3,237
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
1,013
|
|
|
|
12,887
|
|
Stock option exercises
|
|
|
2
|
|
|
|
1,242
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,244
|
|
Issuance of common stock Alliance Acquisition
|
|
|
104
|
|
|
|
261,988
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
262,092
|
|
Acquisition of treasury stock
|
|
|
-
|
|
|
|
-
|
|
|
|
(19,900
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(19,900
|
)
|
Distributions paid on KGS common units
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8,644
|
)
|
|
|
(8,644
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31. 2008
|
|
|
1,717
|
|
|
|
656,958
|
|
|
|
(35,441
|
)
|
|
|
185,104
|
|
|
|
376,488
|
|
|
|
26,737
|
|
|
|
1,211,563
|
|
Net income (loss)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(557,473
|
)
|
|
|
12,234
|
|
|
|
(545,239
|
)
|
Hedge derivative contract settlements reclassified into earnings
from accumulated other comprehensive income, net of income tax
of $99,004
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(211,863
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(211,863
|
)
|
Net change in derivative fair value, net income tax of $57,007
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
125,989
|
|
|
|
-
|
|
|
|
-
|
|
|
|
125,989
|
|
Foreign currency translation adjustment
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
22,106
|
|
|
|
-
|
|
|
|
-
|
|
|
|
22,106
|
|
Issuance & vesting of stock compensation
|
|
|
22
|
|
|
|
19,085
|
|
|
|
(922
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
1,645
|
|
|
|
19,830
|
|
Stock option exercises
|
|
|
6
|
|
|
|
4,040
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,046
|
|
Issuance of KGS common units
|
|
|
-
|
|
|
|
50,182
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
30,133
|
|
|
|
80,315
|
|
Distributions paid on KGS common units
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(9,925
|
)
|
|
|
(9,925
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31. 2009
|
|
$
|
1,745
|
|
|
$
|
730,265
|
|
|
$
|
(36,363
|
)
|
|
$
|
121,336
|
|
|
$
|
(180,985
|
)
|
|
$
|
60,824
|
|
|
$
|
696,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(545,239
|
)
|
|
$
|
(373,622
|
)
|
|
$
|
476,445
|
|
Adjustments to reconcile net income (loss) to net cash
provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and accretion
|
|
|
201,387
|
|
|
|
188,196
|
|
|
|
120,697
|
|
Impairment related to oil and gas properties
|
|
|
979,540
|
|
|
|
633,515
|
|
|
|
-
|
|
Deferred income tax expense (benefit)
|
|
|
(291,414
|
)
|
|
|
(166,440
|
)
|
|
|
207,796
|
|
(Gain) loss from sale of property, plant and equipment
|
|
|
-
|
|
|
|
605
|
|
|
|
(627,348
|
)
|
Non-cash (gain) loss from hedging and derivative activities
|
|
|
6,756
|
|
|
|
(1,139
|
)
|
|
|
62,515
|
|
Stock-based compensation
|
|
|
20,752
|
|
|
|
16,128
|
|
|
|
11,243
|
|
Non-cash interest expense
|
|
|
45,532
|
|
|
|
13,215
|
|
|
|
10,374
|
|
Income from BBEP in excess of cash distributions
|
|
|
(64,344
|
)
|
|
|
(50,762
|
)
|
|
|
-
|
|
Impairment of investment in BBEP
|
|
|
102,084
|
|
|
|
320,387
|
|
|
|
-
|
|
Other
|
|
|
747
|
|
|
|
-
|
|
|
|
(349
|
)
|
Divestiture expenses
|
|
|
-
|
|
|
|
-
|
|
|
|
2,015
|
|
Changes in assets and liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
77,527
|
|
|
|
(53,071
|
)
|
|
|
(14,423
|
)
|
Derivative assets at fair value
|
|
|
54,896
|
|
|
|
-
|
|
|
|
-
|
|
Prepaid expenses and other assets
|
|
|
3,061
|
|
|
|
(5,448
|
)
|
|
|
(4,805
|
)
|
Accounts payable
|
|
|
(12,320
|
)
|
|
|
7,602
|
|
|
|
18,939
|
|
Income taxes payable
|
|
|
-
|
|
|
|
(46,561
|
)
|
|
|
46,012
|
|
Accrued and other liabilities
|
|
|
33,275
|
|
|
|
(26,039
|
)
|
|
|
9,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
612,240
|
|
|
|
456,566
|
|
|
|
319,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of property, plant and equipment
|
|
|
(693,838
|
)
|
|
|
(1,286,715
|
)
|
|
|
(1,020,684
|
)
|
Alliance Acquisition
|
|
|
-
|
|
|
|
(993,212
|
)
|
|
|
-
|
|
Return of investment from equity affiliates
|
|
|
-
|
|
|
|
-
|
|
|
|
9,635
|
|
Proceeds from sales of properties and equipment
|
|
|
220,974
|
|
|
|
1,339
|
|
|
|
741,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(472,864
|
)
|
|
|
(2,278,588
|
)
|
|
|
(269,752
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt
|
|
|
1,420,727
|
|
|
|
2,948,672
|
|
|
|
817,821
|
|
Repayments of debt
|
|
|
(1,649,630
|
)
|
|
|
(1,096,163
|
)
|
|
|
(968,557
|
)
|
Debt issuance costs paid
|
|
|
(32,472
|
)
|
|
|
(25,219
|
)
|
|
|
(5,130
|
)
|
Gas Purchase Commitment
|
|
|
58,294
|
|
|
|
-
|
|
|
|
-
|
|
Gas Purchase Commitment repayments
|
|
|
(14,175
|
)
|
|
|
-
|
|
|
|
-
|
|
Issuance of KGS common units net offering costs
|
|
|
80,729
|
|
|
|
-
|
|
|
|
109,809
|
|
Distributions paid on KGS common units
|
|
|
(9,925
|
)
|
|
|
(8,644
|
)
|
|
|
(8,794
|
)
|
Proceeds from exercise of stock options
|
|
|
4,046
|
|
|
|
1,244
|
|
|
|
21,387
|
|
Excess tax benefits on exercise of stock options
|
|
|
-
|
|
|
|
-
|
|
|
|
2,755
|
|
Purchase of treasury stock
|
|
|
(922
|
)
|
|
|
(23,137
|
)
|
|
|
(1,567
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(143,328
|
)
|
|
|
1,796,753
|
|
|
|
(32,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes in cash
|
|
|
2,889
|
|
|
|
(109
|
)
|
|
|
5,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
(1,063
|
)
|
|
|
(25,378
|
)
|
|
|
22,945
|
|
Cash and cash equivalents at beginning of period
|
|
|
2,848
|
|
|
|
28,226
|
|
|
|
5,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
1,785
|
|
|
$
|
2,848
|
|
|
$
|
28,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
61
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
Quicksilver Resources Inc. is an independent oil and gas company
incorporated in the state of Delaware and headquartered in
Fort Worth, Texas. We engage in the exploration,
development, exploitation, acquisition, production and sale of
natural gas, NGLs and oil as well as the marketing, processing
and transportation of natural gas. As of December 31,
2009, our significant oil and gas reserves and operations are
located in Texas, the U.S. Rocky Mountains and Alberta and
British Columbia, Canada. We have offices located in
Fort Worth, Texas, Cut Bank, Montana, Glen Rose, Texas and
in Calgary, Alberta. Until we completed the BreitBurn
Transaction in 2007 (see Note 5), we also had significant
oil and gas reserves and operations in Michigan, Indiana and
Kentucky.
Our results of operations are largely dependent on the
difference between the prices received for our natural gas, NGL
and oil products and the cost to find, develop, produce and
market such resources. Natural gas, NGL and oil prices are
subject to fluctuations in response to changes in supply, market
uncertainty and a variety of other factors beyond our control.
These factors include worldwide political instability,
quantities of natural gas in storage, foreign supply of natural
gas and oil, the price of foreign imports, the level of consumer
demand and the price of available alternative fuels. We
actively manage a portion of the financial risk relating to
natural gas, NGL and oil price volatility through derivative
contracts.
|
|
2.
|
SIGNIFICANT
ACCOUNTING POLICIES
|
Basis of
Presentation
Our consolidated financial statements include the accounts of
Quicksilver and all its majority-owned subsidiaries and
companies over which we exercise control through majority voting
rights. We eliminate all inter-company balances and
transactions in preparing consolidated financial statements. We
account for our ownership in unincorporated partnerships and
companies, including BBEP, under the equity method when we have
significant influence over those entities, but because of terms
of the ownership agreements, we do not meet the criteria for
control which would require consolidation of the entities.
Our consolidated financial statements reflect the adoption of
new U.S. accounting standards in 2009, which include the
presentation of noncontrolling interests (previously referred to
as minority interest), accounting for contingently
convertible debt and a revision to the calculation of basic
earnings per share for unvested share-based compensation with
nonforfeitable rights to dividends. Further discussion of the
effects of these accounting standards is found in Note 2 to
our consolidated financial statements in Item 8 of our 2008
Annual Report on
Form 10-K,
as amended and filed June 17, 2009.
Changes
in Presentation
Certain reclassifications have been made to the 2008 and 2007
financial statements for presentations adopted in 2009.
Stock
Split
On January 7, 2008, we announced that our Board of
Directors declared a
two-for-one
stock split of Quicksilvers 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
requires our management to make estimates and assumptions that
affect the reported amounts of certain assets and liabilities
and disclosure of
62
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses
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
managements estimates.
Significant estimates underlying these financial statements
include the estimated quantities of proved natural gas, NGL and
oil reserves (including the associated future net cash flows
from those proved reserves) used to compute depletion expense
and estimates of current revenue based upon expectations for
actual deliveries and prices received. Other estimates that
require the assumptions concerning future events and substantial
judgment include the estimated fair values of financial
derivative instruments, asset retirement obligations and
employee stock-based compensation. Income taxes also involve
the use of considerable judgment in the estimation and
evaluation of deferred income tax assets and our ability to
recover operating loss carryforwards and assessment of uncertain
tax positions.
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
We sell our natural gas, NGL and oil production to various
purchasers. Each of our counterparties is reviewed as to credit
worthiness prior to the extension of credit and on a regular
basis thereafter. Although we do 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, we establish an allowance for doubtful
accounts. During 2009, three purchasers individually accounted
for 15%, 13% and 10% of our consolidated natural gas, NGL and
oil sales. During 2008, two purchasers individually accounted
for 17% and 10% of our consolidated natural gas, NGL and oil
sales.
Hedging
and Derivatives
We enter into financial derivative instruments to mitigate risk
associated with the prices received from our natural gas, NGL
and oil production. We may also utilize financial derivative
instruments to hedge the risk associated with interest rates on
our 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.
For derivative instruments that qualify as fair value hedges the
gains or losses on the derivative instruments are recognized
currently in earnings while the gains or losses on the hedged
items shall adjust the carrying value of the hedged items and be
recognized currently in earnings. Any gains or losses on the
derivative instruments not offset by the gains or losses on the
hedged items are recognized as the value of ineffectiveness in
the hedge relationships. For interest rate swaps that qualify
as fair value hedges of our fixed-rate debt outstanding,
ineffectiveness is recognized currently as a component of
interest expense.
We enter into financial derivatives with counterparties who are
lenders under our Senior Secured Credit Facility. The credit
facility provides for collateralization of amounts outstanding
from our derivative instruments in addition to amounts
outstanding under the facility. Additionally, default on any of
our obligations under derivative instruments with counterparty
lenders could result in acceleration of the amounts outstanding
under the credit facility. The credit facility and our internal
credit policies require that any
63
counterparties, including facility lenders, with whom we enter
into commodity financial derivatives have credit ratings that
meet or exceed BBB- or Baa3 from Standard and Poors or
Moodys, respectively. The fair value for each derivative
takes into consideration credit risk, whether it be our
counterparties or our own. Derivatives are recorded in the
balance sheet as current and non-current derivative assets and
liabilities as determined by the expected timing of settlements.
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 GAAP. In December 2007 and in connection with the
divestiture of the Northeast Operations, we decided to cease
delivering a portion of our natural gas production to supply the
contractual volumes. As the contract no longer qualified under
the normal sales exclusion under GAAP, we recognized a loss of
$63.5 million at that time.
Until May 2007, we 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 GAAP. See Note 5
to these consolidated financial statements for more information
regarding the CMS Contract.
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 gathering of our natural gas
production.
We account for our investment in BBEP using the equity method.
We review our investment for impairment whenever events or
circumstances indicate that the investments carrying
amount may not be recoverable. We record our portion of
BBEPs earnings during the quarter in which their financial
statements become publicly available. As a result, our 2009
annual results of operations include BBEPs earnings for
the 12 months ended September 30, 2009. Our 2008
results of operations reflect BBEPs earnings from
November 1, 2007, when we acquired BBEP units, through
September 30, 2008. We are not aware of any significant
events or transactions subsequent to September 30, 2009
that will affect BBEPs results of operations after that
date. See Note 9 for more information on our BBEP
investment.
Property,
Plant, and Equipment
We follow the full cost method in accounting for our 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 (1) estimated future net revenue, discounted at 10%
per annum, from proved reserves, based on the unweighted average
of the preceding
12-month of
first-day-of-the-month
prices adjusted to reflect local differentials and contract
provisions, year end costs and financial derivatives that hedge
our oil and gas revenue, (2) the cost of properties not
being amortized, (3) the lower of cost or market value of
unproved properties included in the cost being amortized less
(4) income tax effects related to differences between the
book and tax basis of the natural gas and 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 10 to these financial statements contains
further discussion of the ceiling test.
64
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.
Asset
Retirement Obligations
We record 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 assets useful life.
Changes in the liability for the asset retirement obligations
are recognized for (1) the passage of time and
(2) 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.
Revenue
Recognition
Revenue is recognized when title to the products transfer to the
purchaser. We use the sales method to account for
our production revenue, whereby we recognize revenue on all
natural gas, NGL or oil sold to our purchasers, regardless of
whether the sales are proportionate to our ownership in the
property. A receivable or liability is recognized only to the
extent that we have an imbalance on a specific property greater
than the expected remaining proved reserves. As of
December 31, 2009 and 2008, our aggregate production
imbalances were not material.
Environmental
Compliance and Remediation
Environmental compliance costs, including ongoing maintenance
and monitoring, are expensed as incurred. Those environmental
remediation costs which improve a property are capitalized.
Debt
We record all debt instruments at face value. When an issuance
of debt is made at other than par, a discount or premium is
separately recorded. The discount or premium is amortized over
the life of the debt using the effective interest method. As
required by GAAP, we have separately accounted for the liability
and equity components of our contingently convertible debt
instrument. Such recording has resulted in recognition of
interest expense at our effective borrowing rate in effect at
the time of issuance.
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 expected to be 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
We measure and recognize compensation expense for all
share-based payment awards made to employees and directors based
on their estimated fair value at the time the awards are
granted. At the discretion of the board of directors, we may
issue awards payable in cash. For all awards, we recognize 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
Our 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 as the present value of future cash flows discounted
at rates consistent with comparable maturities and includes
consideration
65
of 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.
Foreign
Currency Translation
Our 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 results
of operations.
Noncontrolling
Interests in Consolidated Subsidiaries
Noncontrolling interests reflect the fractional outside
ownership of our majority-owned and consolidated subsidiaries.
Our adoption of new GAAP for noncontrolling interests on
January 1, 2009 resulted in a reclassification of
$29.9 million to equity and captioned as noncontrolling
interests. Measurement of the income statement amounts
attributable to noncontrolling ownership interests of KGS was
unaffected by this adoption. We include the results of
operations and financial position of KGS in our consolidated
financial statements and recognize the portion of KGS
results of operations attributable to unaffiliated unitholders
as a component of income attributable to noncontrolling
interests. Equity balances for noncontrolling interests
do not necessarily reflect the fair value of that outside
ownership.
Earnings
per Share
We report basic earnings per common share, which excludes the
effect of potentially diluted securities, and diluted earnings
per common share, which includes the effect of all potentially
dilutive securities unless their impact is antidilutive. The
calculation of earnings per share is found at Note 18.
Recently
Issued Accounting Standards
Accounting standard-setting organizations frequently issue new
or revised accounting rules. We regularly review all new
pronouncements to determine their impact, if any, on our
financial statements. Below, we present a discussion of only
those pronouncements that have or are expected to have an impact
on our financial statements.
Pronouncements
Impacting Quicksilver That Have Been Implemented During
2009
GAAP guidance discussed below references only those items not
previously included in Note 2 to our consolidated financial
statements in Item 8 of our 2008 Annual Report on
Form 10-K,
as amended and filed June 17, 2009.
In June 2009 and through subsequent updates, the FASB issued
guidance that identified the FASB Accounting Standards
Codification as the single source of authoritative
U.S. GAAP not promulgated by the SEC. The FASC retains
existing GAAP and had no effect on our financial statements upon
its adoption by us at adoption, although any references to GAAP
herein have been converted to the codified reference.
The FASB issued revised guidance for business combinations in
December 2007, which retained 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. The acquirer is the entity that obtains
control in the business combination and the guidance establishes
the criteria to determine the acquisition date. An acquirer is
also required 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 separately from the acquisition. Additional
clarifications were issued on April 1, 2009 that address
application issues regarding initial recognition and
measurement, subsequent measurement and accounting, and
disclosure of assets and liabilities arising from contingencies
in a business combination. Had we made or should we make any
acquisition after January 1, 2009, when we adopted this
revised guidance, we would have applied and will apply the
guidance, but otherwise adoption had no effect on our financial
statements.
66
In February 2008, the FASB issued guidance which allowed for a
one-year deferral of the effective date of the accounting
guidance in FASC Topic 820, Fair Value Measurements and
Disclosures, as it applies to non-financial assets and
liabilities that are recognized or disclosed at fair value on a
nonrecurring basis. Beginning January 1, 2009, we applied
the accounting guidance for all fair value measurements to
non-financial assets and liabilities.
The FASB issued accounting guidance in March 2008 requiring
enhanced disclosures of the fair value and other aspects of all
derivative and hedging instruments 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. We adopted the
guidance on January 1, 2009 and have provided the
prescribed disclosures for all periods presented in Note 6.
On April 9, 2009, the FASB issued guidance, found at FASC
Subtopic
825-10,
Financial Instruments, requiring disclosures about fair
value of financial instruments for interim reporting periods.
We have adopted the disclosure requirements.
The FASB issued guidance in May 2009 for disclosure of events
that occur after the balance sheet date but before financial
statements are issued by public entities. It mirrors the
longstanding existing guidance for subsequent events that was
promulgated by the American Institute of Certified Public
Accountants. We adopted the guidance during the quarter ended
June 30, 2009 when the guidance became effective without
effect.
The FASB issued updated disclosure guidance in August 2009,
which updated FASC Topic 820, Fair Value Measurements and
Disclosures, for the fair value measurement of liabilities.
We have adopted all relevant guidance related to fair value
measurement and disclosure.
The SEC adopted revisions to its required oil and gas reporting
disclosures in December 2008. The revisions affecting us
include: 1) use of the unweighted average of the preceding
12-month
first-day-of-the-month
prices for determination of proved reserve values included in
calculating full cost ceiling limitations and for annual proved
reserve disclosures; 2) consideration of and 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
full cost ceiling test for impairment. We have adopted these
changes for the required supplemental reporting of our proved
reserves and related disclosures as of and for the year ended
December 31, 2009.
As a result of the SECs new rule for oil and gas
disclosures, the FASB issued updates to its guidance for oil and
gas disclosures to incorporate those changes so that FASC
requirements are consistent with the SECs changes.
Additionally the FASB adopted requirements for separate
supplemental disclosures about oil and gas producing activities
for equity method investments. We have adopted these changes
and related disclosures as of and for the year ended
December 31, 2009.
In 2010, the FASB amended guidance that addressed provisions
equity-method investments and for changes in a parents
ownership interest in a consolidated subsidiary. Additionally,
the FASB amended guidance for disclosure of recurrent fair value
measurements. We adopted the changes as of and for
the year ended December 31, 2009.
On June 19, 2009, we completed the Eni Transaction whereby
we entered into a strategic alliance with Eni and sold a 27.5%
interest in our Alliance Leasehold. The assets were
sold to Eni for $279.7 million in cash, inclusive of the
Gas Purchase Commitment assumed and normal post-closing
adjustments. We used the proceeds generated to repay
a portion of the Senior Secured Second Lien Facility.
In connection with the sale, we entered into a gas gathering
agreement with Eni covering Enis production from the
Alliance Leasehold. Under the agreement, we will
gather, treat and deliver Enis Alliance Leasehold
production. Eni also committed to pay approximately
$19.2 million by March 2010 to us (of which
$9.5 million has been paid through December 31,
2009) for construction and installation of the facilities
67
required to gather Enis production from future Alliance
wells. We will be the sole owner of these facilities
and, upon completion of the Gas Purchase Commitment, will
recognize gathering revenue for the volumes of gas that are
gathered.
Also as part of the sale, we entered into a joint development
agreement with Eni. The joint development agreement
includes a schedule of wells that we agreed to drill and
complete with participation by Eni during the development
period. In connection with the scheduled drilling of
these wells, we have committed to drill and complete a minimum
number of lateral feet each year. Eni agreed to pay
us a turnkey drilling and completion cost of $994 per linear
foot attributable to Eni. The net linear footage
requirements to be drilled and completed attributable to Eni are
summarized below:
|
|
|
|
|
|
|
Total Aggregate
|
|
Year
|
|
Linear Feet
|
|
|
2010
|
|
|
58,448
|
|
2011
|
|
|
44,080
|
|
2012
|
|
|
26,974
|
|
2013
|
|
|
34,102
|
|
Under the joint development agreement, we may be subject to pay
Eni for damages at the end of the development period should we
fail to meet the linear footage requirements and certain
production requirements have not been satisfied. We currently
expect to satisfy these requirements and have recognized no
liability related to non-performance.
In August 2008, Quicksilver completed the Alliance Acquisition,
under which we acquired leasehold, royalty and midstream assets
in the Barnett Shale in northern Tarrant and southern Denton
counties of Texas. The purchase price was determined
as follows:
|
|
|
|
|
(In thousands)
|
|
|
Purchase Price:
|
|
|
|
|
Cash paid
|
|
$
|
1,000,000
|
|
Cash received from post-closing settlement
|
|
|
(9,086
|
)
|
Cash paid for acquisition-related expenses
|
|
|
1,368
|
|
|
|
|
|
|
Total cash
|
|
|
992,282
|
|
Issuance of 10,400,468 common shares
|
|
|
262,092
|
|
|
|
|
|
|
|
|
$
|
1,254,374
|
|
|
|
|
|
|
Quicksilvers purchase price allocation is presented below:
|
|
|
|
|
(In thousands)
|
|
|
Allocation of Purchase Price:
|
|
|
|
|
Oil and gas properties proved
|
|
$
|
788,457
|
|
Oil and gas properties unproved
|
|
|
440,372
|
|
Midstream assets
|
|
|
27,652
|
|
Liabilities assumed
|
|
|
(1,035
|
)
|
Asset retirement obligations
|
|
|
(1,072
|
)
|
|
|
|
|
|
|
|
$
|
1,254,374
|
|
|
|
|
|
|
We finalized the purchase price allocation during the quarter
ended September 30, 2009.
68
Pro Forma
Information
The following table reflects our unaudited consolidated pro
forma statements of income as though the Alliance Acquisition,
associated borrowings and issuance of Quicksilver common stock
had occurred on January 1 for each year
presented. The revenue and expenses for the
acquisition are included in our 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.
|
|
|
|
|
|
|
|
|
|
|
For The Years Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues
|
|
|
$ 875,607
|
|
|
|
$ 629,868
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$ (384,645
|
)
|
|
|
$ 428,314
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share - basic
|
|
|
($2.29
|
)
|
|
|
$2.57
|
|
Earnings (loss) per common share - diluted
|
|
|
($2.29
|
)
|
|
|
$2.40
|
|
|
|
5.
|
DIVESTITURE
OF NORTHEAST OPERATIONS
|
In November 2007, we closed the BreitBurn Transaction, which
resulted in the contribution of all of our oil and gas
properties and facilities in our 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 the BBEP unit closing price on the closing date. Under
the terms of the transaction, we were required to retain 50% of
the acquired units until May 1, 2009, but may now freely
trade all of the acquired units.
Concurrent with closing the BreitBurn Transaction, we 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. Our total expense
associated with the termination-related employee benefits was
approximately $10.4 million which was recognized
approximately 60% in 2007 and 20% in 2008 and 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 and $2.0 million recognized in 2008 and
2009, respectively, were attributable to the services rendered
by the affected employees over these periods. Our expenses
associated with the separation benefits ended on
November 1, 2009.
A portion of our hedging program that was designated to the
Northeast Operations for the period subsequent to the closing of
the BreitBurn Transaction no longer qualified for hedge
accounting treatment. Accordingly, concurrent with the
completion of the BreitBurn Transaction, we 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 statement of
income. In the fourth quarter of 2007, we re-designated the
hedges originally attributed to the Northeast Operations as
hedges of other U.S. production and applied hedge
accounting treatment for prospective changes in value.
In completing the BreitBurn Transaction, we 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 GAAP, we held and continue to hold a continuing
interest in the assets and subsidiaries sold in the
BreitBurn Transaction as we owned approximately 32% of
BBEPs outstanding common units following
69
the BreitBurn Transaction. Thus, we deferred $294 million,
or 32%, of the $923 million calculated book gain and
recorded our 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. See Note 9 for more
recent developments regarding our investment in BBEP.
Under the full cost method of accounting, our
U.S. exploration and production assets are considered a
single asset. The divestiture of the Northeast
Operations, therefore, represented 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
|
Commodity
Price Derivatives
As of December 31, 2009, we had price collars hedging
200 MMcfd, 120 MMcfd and 60 MMcfd of our
anticipated natural gas production for 2010, 2011 and 2012,
respectively. We also had fixed price swaps hedging
10 MBbld and 5 MBbld of our anticipated 2010 and 2011
NGL production, respectively. In March 2009, we
executed the early settlement of a price collar that hedged the
sale of 40 MMcfd of our forecasted 2010 natural gas
production, whereby we received
$54.9 million. The settlement was recorded to
AOCI and will be reclassified into natural gas revenue as we
sell the associated hedged production volumes during
2010. Excluded from the amounts presented in the
tables below are additional price collars and swaps entered into
during 2010. In January 2010, we entered into a swap
that fixed the Houston Ship Channel basis for 20 MMcfd of
natural gas at a deduction of $0.09 per Mcf from NYMEX for
February through December 2010. We also entered in a
swap for three MBbld of our 2011 NGL fixing the price at $41.95
per Bbl.
Interest
Rate Derivatives
In June 2009, we entered into interest rate swaps on our
$475 million senior notes due 2010 and our
$350 million senior subordinated notes effectively
converting the interest on those issues from a fixed to a
floating rate indexed to a one-month LIBOR. The
maturity dates and all other significant terms are the same as
those of the underlying debt. Under these swaps, we
pay a variable interest rate and receive the fixed rate
applicable to the underlying debt. The interest
income or expense is accrued as earned and recorded as an
adjustment to the interest expense accrued on the fixed-rate
debt. The interest rate swaps are designated as fair
value hedges of the underlying debt. The value of the
contracts, excluding the net interest accrual, amounted to a net
asset of $4.1 million as of December 31,
2009. The offsetting fair value adjustment to the
debt hedged resulted in an increase of long-term debt by
$4.1 million as of December 31, 2009. No
ineffectiveness was recorded in connection with the fair value
hedges. The average effective interest rates on the
2015 Senior Notes and Senior Subordinated Notes, since we
entered into the hedges in June 2009, were approximately 5.1%
and 3.7%, respectively.
In February 2010, we executed early settlement of our interest
rate swaps. We received cash of $18.0 million in
the settlement, which has been recorded as an adjustment to the
carrying value of the debt and will be amortized to earnings
over the life of the associated underlying debt instruments.
We subsequently entered into new interest rate swaps on our
senior notes due 2015 and our senior subordinated notes that
convert the interest paid on those issues from a fixed to a
floating rate indexed to six-month LIBOR. The
maturity dates and all other significant terms are the same as
those of the underlying debt. As a result, these
interest rate swaps qualified for hedge accounting treatment as
fair value hedges.
Other
Derivatives
Based on information available on June 19, 2009, we
recognized a liability pursuant to the Gas Purchase Commitment
based on the estimated production volumes attributable to Eni
through December 31, 2010, which then totaled
22.2 Bcf. The Gas Purchase Commitment contains
an embedded derivative that is adjusted to fair value throughout
the period of the commitment, which expires on December 31,
2010. We recognized a $6.6 million increase in
the fair value of the embedded derivative liability between June
19 and December 31, 2009 and recorded a valuation loss as a
component of costs of purchased natural gas. At
70
December 31, 2009, we had a remaining liability of
$50.7 million, including the $6.6 million liability
for the embedded derivative. The following summarizes
activity to the Gas Purchase Commitment:
|
|
|
|
|
(In thousands)
|
|
|
Initial valuation of liability
(1)
|
|
$
|
58,294
|
|
Decrease due to gas volumes purchased
|
|
|
(14,175
|
)
|
Embedded derivative increase (decrease) due to:
|
|
|
|
|
Price changes
|
|
|
7,904
|
|
Volume changes
|
|
|
(1,279
|
)
|
|
|
|
|
|
Total embedded derivative
|
|
|
6,625
|
|
Balance at December 31, 2009
|
|
$
|
50,744
|
|
|
|
|
|
|
|
|
|
(1) |
|
Initial valuation of the Gas Purchase Commitment was estimated
using estimated Eni production volumes from June 19, 2009
through December 2010 and published future market prices and
risk-adjusted interest rates as of June 19, 2009. |
The estimated fair value of our derivative instruments at
December 31, 2008 and 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
|
Liability Derivatives
|
|
|
|
As of December 31,
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts reported in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$
|
97,883
|
|
|
$
|
179,079
|
|
|
|
$
|
638
|
|
|
$
|
2,500
|
|
Noncurrent derivative assets
|
|
|
11,031
|
|
|
|
116,006
|
|
|
|
|
-
|
|
|
|
-
|
|
Current derivative liabilities
|
|
|
243
|
|
|
|
-
|
|
|
|
|
638
|
|
|
|
1,865
|
|
Interest rate contracts reported in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
|
712
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Noncurrent derivative assets
|
|
|
3,396
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedges
|
|
$
|
113,265
|
|
|
$
|
295,085
|
|
|
|
$
|
1,276
|
|
|
$
|
4,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchase Commitment reported in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued liabilities
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
$
|
6,625
|
|
|
$
|
-
|
|
Michigan Sales Contract natural gas purchase
derivatives (1) reported
in current derivative assets
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
4,839
|
|
Michigan Sales
Contract (1) reported
in current derivative liabilities
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
8,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedges
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
$
|
6,625
|
|
|
$
|
12,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
113,265
|
|
|
$
|
295,085
|
|
|
|
$
|
7,901
|
|
|
$
|
17,267
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During 2009, our net cash payments were $16.5 million,
including derivative settlements, to complete our obligations
under the Michigan Sales Contract. |
71
The following table shows the level of inputs used in our fair
value calculations of our derivative instruments at
December 31, 2008 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Significant Other Observable
|
|
|
|
Inputs - Level 2
|
|
|
|
at December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
Gas Purchase Commitment
|
|
$
|
(6,625
|
)
|
|
$
|
-
|
|
Michigan Sales Contract
|
|
|
-
|
|
|
|
(8,063
|
)
|
Commodity futures contracts
|
|
|
107,881
|
|
|
|
285,881
|
|
Interest rate contracts
|
|
|
4,108
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Total
derivatives-net
|
|
$
|
105,364
|
|
|
$
|
277,818
|
|
|
|
|
|
|
|
|
|
|
The decrease in carrying value of our commodity price
derivatives since December 31, 2008 principally resulted
from monthly settlements received during 2009 and the
$54.9 million early settlement of a natural gas collar that
hedged 2010 natural gas production. These decreases were
partially offset by the overall decline in market prices for
natural gas relative to the prices in our open derivative
instruments at December 31, 2009.
The changes in the carrying value of our derivatives for 2009
and 2008 are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Two Years Ended December 31, 2009
|
|
|
|
|
|
|
Michigan
|
|
|
Gas Purchase
|
|
|
Fair Value
|
|
|
Cash Flow
|
|
|
|
|
|
|
|
|
|
Contract
|
|
|
Commitment
(1)
|
|
|
Derivatives
|
|
|
Derivatives
|
|
|
Total
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Derivative fair value at December 31, 2007
|
|
$
|
(63,777
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(5,505
|
)
|
|
$
|
(69,282
|
)
|
|
|
|
|
Change in amounts receivable/payable-net
|
|
|
3,518
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(438
|
)
|
|
|
3,080
|
|
|
|
|
|
Net settlements
|
|
|
48,284
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
48,284
|
|
|
|
|
|
Net settlements reported in revenue
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18,392
|
|
|
|
18,392
|
|
|
|
|
|
Ineffectiveness reported in other revenue
|
|
|
(926
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
2,547
|
|
|
|
1,621
|
|
|
|
|
|
Unrealized gains reported in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
275,723
|
|
|
|
275,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value at December 31, 2008
|
|
$
|
(12,901
|
)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
290,719
|
|
|
$
|
277,818
|
|
|
|
|
|
Change in amounts receivable/payable-net
|
|
|
(3,518
|
)
|
|
|
-
|
|
|
|
9,180
|
|
|
|
-
|
|
|
|
5,662
|
|
|
|
|
|
Net settlements
|
|
|
16,479
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16,479
|
|
|
|
|
|
Net settlements reported in revenue
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(310,868
|
)
|
|
|
(310,868
|
)
|
|
|
|
|
Net settlements reported in interest expense
|
|
|
-
|
|
|
|
-
|
|
|
|
13,724
|
|
|
|
-
|
|
|
|
13,724
|
|
|
|
|
|
Unrealized change in fair value of Gas Purchase Commitment
reported in costs of purchased gas
|
|
|
-
|
|
|
|
(6,625
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(6,625
|
)
|
|
|
|
|
Change in fair value of effective interest swaps
|
|
|
-
|
|
|
|
-
|
|
|
|
(18,796
|
)
|
|
|
-
|
|
|
|
(18,796
|
)
|
|
|
|
|
Ineffectiveness reported in other revenue
|
|
|
(60
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(71
|
)
|
|
|
(131
|
)
|
|
|
|
|
Cash settlement reported in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(54,896
|
)
|
|
|
(54,896
|
)
|
|
|
|
|
Unrealized gains reported in OCI
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
182,997
|
|
|
|
182,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative fair value at December 31, 2009
|
|
$
|
-
|
|
|
$
|
(6,625
|
)
|
|
$
|
4,108
|
|
|
$
|
107,881
|
|
|
$
|
105,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Reported in accrued liabilities. |
Gains and losses from the effective portion of derivative assets
and liabilities held in AOCI expected to be reclassified into
earnings over the next twelve months would result in a gain of
$97.0 million net of income taxes. An additional
$35.7 million, net of income taxes, will be reclassified
from AOCI for the gain realized on the 2010 natural gas collar
settled in March 2009. Hedge derivative ineffectiveness
resulted in $0.1 million of net losses and
$1.6 million and $1.0 million of net gains for the
years ended December 31, 2009, 2008 and 2007, respectively.
72
Accounts receivable consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Accrued production receivables
|
|
$
|
33,241
|
|
|
$
|
47,552
|
|
Joint interest receivables
|
|
|
12,889
|
|
|
|
29,420
|
|
Interest rate swap settlement receivable
|
|
|
9,180
|
|
|
|
-
|
|
Income tax receivable
|
|
|
7,018
|
|
|
|
47,928
|
|
Accrued production taxes receivable
|
|
|
2,120
|
|
|
|
12,877
|
|
Other receivables
|
|
|
1,254
|
|
|
|
5,624
|
|
Allowance for doubtful accounts
|
|
|
(449
|
)
|
|
|
(86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
65,253
|
|
|
$
|
143,315
|
|
|
|
|
|
|
|
|
|
|
Other current assets consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Spare parts and supplies
|
|
$
|
44,258
|
|
|
$
|
64,185
|
|
Prepaid production taxes
|
|
|
5,071
|
|
|
|
7,239
|
|
Prepaid drilling rentals
|
|
|
-
|
|
|
|
384
|
|
Deposits
|
|
|
2,758
|
|
|
|
1,680
|
|
Other prepaid expenses
|
|
|
2,856
|
|
|
|
1,945
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
54,943
|
|
|
$
|
75,433
|
|
|
|
|
|
|
|
|
|
|
|
|
9.
|
INVESTMENT
IN BREITBURN ENERGY PARTNERS L.P.
|
In 2007, we received common units of BBEP, a publicly traded
limited partnership, as part of the BreitBurn Transaction, which
is more fully described in Note 5 to these consolidated
financial statements. 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 our ownership from
approximately 32% to approximately 41%. At December 31,
2009, we held an ownership interest in BBEP of approximately 40%
by virtue of employee and director stock-based compensation
programs at BBEP.
During the first quarter of 2009 and fourth quarter of 2008, we
evaluated our investment in BBEP for impairment in response to
decreases in both prevailing commodity prices and BBEPs
unit price. We considered numerous factors in evaluating
whether this decline was
other-than-temporary.
As a result of the period during which BBEP common units traded
below our 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.
Accordingly, the impairment analysis at December 31, 2008
utilized a price of $7.05 per BBEP unit, or an aggregate fair
value of $150.5 million for our investment in BBEP. The
estimated fair value of $150.5 million was then compared to
our carrying value of $470.9 million. The difference of
$320.4 million was recognized as an impairment charge
during 2008.
At March 31, 2009, an additional charge for impairment of
$102.1 million was recognized as the closing unit price of
$6.53 per BBEP unit, or an aggregate fair value of
$139.4 million exceeded our carrying value of
$241.5 million. No subsequent impairment of our investment
occurred as the December 31, 2009 closing
73
price of $10.59 per BBEP exceeded our carrying value of $5.28
per unit. Additional impairment of our investment in BBEP could
occur in the future depending upon the performance of
BBEPs unit price, which itself is dependent upon numerous
factors.
We account for our investment in BBEP units using the equity
method, utilizing a one-quarter lag from BBEPs publicly
available information. Summarized estimated financial
information for BBEP is as follows:
|
|
|
|
|
|
|
|
|
|
|
For the
|
|
|
For the
|
|
|
|
Twelve Months
|
|
|
Eleven Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
September 30,2009
|
|
|
September 30, 2008
|
|
|
|
(In thousands)
|
|
|
Revenue
(1)
|
|
$
|
534,192
|
|
|
$
|
420,321
|
|
Operating expense
(2)
|
|
|
307,391
|
|
|
|
251,618
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
226,801
|
|
|
|
168,703
|
|
Interest and other
(3)
|
|
|
37,458
|
|
|
|
27,795
|
|
Income tax (benefit) expense
|
|
|
336
|
|
|
|
593
|
|
Noncontrolling interests
|
|
|
15
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
Net income available to BBEP
|
|
$
|
188,992
|
|
|
$
|
140,109
|
|
|
|
|
|
|
|
|
|
|
Net income available to common unitholders
|
|
$
|
188,992
|
|
|
$
|
141,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Unrealized gains on commodity derivatives of $193.5 million
and $39.4 million were included for the twelve months ended
September 30, 2009 and eleven months ended
September 30, 2008, respectively. Realized gains on
commodity derivatives of $70.6 million for the early
settlement of derivative positions were included for the twelve
months ended September 30, 2009.
|
|
|
|
(2)
|
An impairment of BBEPs oil and gas properties of
$86.4 million was included for the twelve months ended
September 30, 2009.
|
|
|
|
(3)
|
The twelve months ended September 30, 2009 included
$11.1 million for unrealized losses on interest rate swaps
and the eleven months ended September 30, 2008 included
$2.3 million for unrealized losses on interest rate swaps.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
September 30, 2009
|
|
|
December 31, 2008
|
|
|
|
(In thousands)
|
|
|
Current assets
|
|
$
|
121,207
|
|
|
$
|
140,566
|
|
Property, plant and equipment
|
|
|
1,754,174
|
|
|
|
1,840,341
|
|
Other assets
|
|
|
114,673
|
|
|
|
235,927
|
|
Current liabilities
|
|
|
64,573
|
|
|
|
79,990
|
|
Long-term debt
|
|
|
585,000
|
|
|
|
736,000
|
|
Other non-current liabilities
|
|
|
72,519
|
|
|
|
47,413
|
|
Partners equity
|
|
|
1,267,962
|
|
|
|
1,353,431
|
|
74
Changes in the balance of our investment in BBEP for 2009 and
2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Beginning investment balance
|
|
$
|
150,503
|
|
|
$
|
420,171
|
|
Equity income in BBEP
|
|
|
75,444
|
|
|
|
93,298
|
|
Distributions from BBEP
|
|
|
(11,100
|
)
|
|
|
(42,579
|
)
|
Non-cash impairment of BBEP
|
|
|
(102,084
|
)
|
|
|
(320,387
|
)
|
|
|
|
|
|
|
|
|
|
Ending investment balance
|
|
$
|
112,763
|
|
|
$
|
150,503
|
|
|
|
|
|
|
|
|
|
|
Item 15 in this Annual Report contains BBEPs
financial statements, which have been included pursuant to SEC
Rule 3-09.
|
|
10.
|
PROPERTY,
PLANT AND EQUIPMENT
|
Property, plant and equipment consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Oil and gas properties
|
|
|
|
|
|
|
|
|
Subject to depletion
|
|
$
|
3,947,676
|
|
|
$
|
3,621,831
|
|
Unevaluated costs
|
|
|
458,037
|
|
|
|
543,533
|
|
Accumulated depletion
|
|
|
(2,067,469
|
)
|
|
|
(1,022,756
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
2,338,244
|
|
|
|
3,142,608
|
|
Other plant and equipment
|
|
|
|
|
|
|
|
|
Pipelines and processing facilities
|
|
|
779,493
|
|
|
|
533,234
|
|
General properties
|
|
|
68,698
|
|
|
|
57,941
|
|
Construction in progress
|
|
|
5,630
|
|
|
|
130,878
|
|
Accumulated depreciation
|
|
|
(106,125
|
)
|
|
|
(66,946
|
)
|
|
|
|
|
|
|
|
|
|
Net other property and equipment
|
|
|
747,696
|
|
|
|
655,107
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net of accumulated depletion and
depreciation
|
|
$
|
3,085,940
|
|
|
$
|
3,797,715
|
|
|
|
|
|
|
|
|
|
|
Ceiling
Test Analysis and Impairment
As described in Note 2, we are required to perform a
quarterly ceiling test for impairment of our oil and gas
properties in each of our cost centers. Due to significant
decreases in natural gas and NGL market prices, we have
recognized charges for impairment of both our U.S. and
Canadian cost centers during 2009 and 2008.
The 2009 first quarter U.S. ceiling amount was computed
using benchmark prices of $3.63 per Mcf of natural gas, $24.12
per barrel of NGL and $49.66 per barrel of oil. When we
determined the present value of our U.S. reserves, the
carrying value of our U.S. oil and gas properties exceeded
the ceiling limit by $786.9 million (pre-tax). We computed
the 2009 first quarter Canadian ceiling amount using an AECO
benchmark price of $2.92 per Mcf. Upon calculation of the
present value of our Canadian reserves, the carrying value of
our Canadian oil and gas properties exceeded the ceiling limit
by $109.6 million (pre-tax). We recorded a total
impairment charge of $896.5 million in the first quarter of
2009.
The second quarter 2009 ceiling test for our U.S. oil and
gas properties resulted in no further recognition of impairment
due principally to price recoveries during the second quarter;
however, the second quarter ceiling test for our Canadian oil
and gas properties resulted in an additional charge for
impairment. We
75
computed the 2009 second quarter Canadian ceiling amount using
an AECO benchmark price of $2.87 per Mcf. The carrying value of
our Canadian oil and gas reserves exceeded the present value of
our Canadian proved reserves at June 30, 2009 by
$70.6 million (pre-tax), which we recorded as an impairment
charge in the second quarter of 2009.
At September 30, 2009, the unamortized cost of our Canadian
oil and gas properties exceeded the full cost ceiling limitation
by approximately $38.8 million (pre-tax). The full cost
ceiling limitation included $25.7 million (pre-tax) for
hedge valuations. We computed the 2009 third quarter ceiling
using an AECO price of $3.41 per Mcf. As permitted by GAAP then
in effect, improvements in AECO spot natural gas prices
subsequent to September 30, 2009 eliminated the necessity
to record a charge for impairment. Our U.S. ceiling test
for the third quarter of 2009 required no recognition of
impairment of our U.S. oil and gas properties.
The fourth quarter 2009 Canadian ceiling test was based upon our
December 31, 2009 Canadian proved reserves that were
estimated using an AECO price of $3.76 per Mcf (the unweighted
average of the preceding
12-month
first-day-of-the-month
prices). We used the present value of future net cash flows of
our Canadian proved reserves discounted at 10% at
December 31, 2009 and $48.2 million (pre-tax) for
hedge valuations to determine the Canadian ceiling limit. The
carrying value of our Canadian oil and gas properties exceeded
the ceiling limit by $12.4 million (pre-tax), which we
recorded as an impairment charge in the fourth quarter of 2009.
The fourth quarter 2009 ceiling test for our U.S. oil and
gas properties required no recognition of impairment.
In arriving at the ceiling amount for the fourth quarter of
2008, we used $5.71 per Mcf of natural gas, $44.60 per Bbl of
oil and $21.65 per Bbl of NGL for our U.S. properties
production horizon. When the present value of our
U.S. reserves was calculated, the carrying value exceeded
the ceiling limit and resulted in a pre-tax charge for
impairment of $624.3 million recognized during the fourth
quarter of 2008. Our Canadian ceiling test for the fourth
quarter of 2008 resulted in no impairment of our Canadian oil
and gas properties.
The charges for ceiling test impairment recorded in 2009 and
2008 are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Pre-tax
|
|
|
|
Capitalized
|
|
|
Ceiling
|
|
|
Charge for
|
|
|
|
Costs(1)
|
|
|
Limitation(2)
|
|
|
Impairment
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
First Quarter 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,727,130
|
|
|
$
|
1,940,263
|
|
|
$
|
786,867
|
|
Canada
|
|
|
458,135
|
|
|
|
348,519
|
|
|
|
109,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,185,265
|
|
|
$
|
2,288,782
|
|
|
$
|
896,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
$
|
400,696
|
|
|
$
|
330,053
|
|
|
$
|
70,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
$
|
385,931
|
|
|
$
|
373,517
|
|
|
$
|
12,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Consolidated charge for impairment
|
|
|
|
|
|
|
|
|
|
$
|
979,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Pre-tax
|
|
|
|
Capitalized
|
|
|
Ceiling
|
|
|
Charge for
|
|
|
|
Costs(1)
|
|
|
Limitation(2)
|
|
|
Impairment
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Fourth Quarter 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
3,016,147
|
|
|
$
|
2,391,832
|
|
|
$
|
624,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net capitalized costs before impairment includes all costs
associated with development, exploration and acquisition of oil
and gas properties net of accumulated depletion and impairment,
reduced by the related deferred income tax liability. |
76
|
|
|
(2) |
|
The cost center ceiling is defined as the sum of
(1) estimated future net revenue, discounted at 10% per
annum, from proved reserves, based on the unweighted average of
the preceding
12-month
first day-of the-month prices (end of year prices for 2008 and
2007) adjusted to reflect local differentials and contract
provisions, unescalated year-end costs and financial derivatives
that hedge the our oil and gas revenue, (2) the cost of
properties not being amortized, (3) the lower of cost or
market value of unproved properties included in the cost being
amortized less (4) income tax effects related to
differences between the book and tax bases of the oil and gas
properties. |
In the fourth quarter of 2008, we 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. As a result, we also evaluated our
midstream assets in West Texas for impairment, recording an
impairment charge of $9.2 million (pre-tax) to reduce those
midstream assets to their estimated fair values.
Because of the volatility of oil and natural gas prices, no
assurance can be given that we will not experience a charge for
impairment in future periods.
Unevaluated
Natural Gas and Oil Properties Not Subject to
Depletion
Under full cost accounting, we 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, 2009 and 2008 and the
year in which they were incurred follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 Costs Incurred During
|
|
|
December 31, 2008 Costs Incurred During
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Prior
|
|
|
Total
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Prior
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
|
$
|
12,463
|
|
|
$
|
275,409
|
|
|
$
|
54,855
|
|
|
$
|
63,089
|
|
|
$
|
405,816
|
|
|
$
|
381,203
|
|
|
$
|
54,094
|
|
|
$
|
31,328
|
|
|
$
|
53,998
|
|
|
$
|
520,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs
|
|
|
29,029
|
|
|
|
16,470
|
|
|
|
|
|
|
|
|
|
|
|
45,499
|
|
|
|
19,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest
|
|
|
3,985
|
|
|
|
2,737
|
|
|
|
|
|
|
|
|
|
|
|
6,722
|
|
|
|
3,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
45,477
|
|
|
$
|
294,616
|
|
|
$
|
54,855
|
|
|
$
|
63,089
|
|
|
$
|
458,037
|
|
|
$
|
404,113
|
|
|
$
|
54,094
|
|
|
$
|
31,328
|
|
|
$
|
53,998
|
|
|
$
|
543,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the unevaluated property costs
not subject to depletion.
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Fort Worth Basin
|
|
$
|
312,892
|
|
|
$
|
440,144
|
|
Canadian Horn River Basin
|
|
|
117,330
|
|
|
|
80,590
|
|
Green River Basin
|
|
|
27,131
|
|
|
|
18,580
|
|
Other
|
|
|
684
|
|
|
|
4,219
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
458,037
|
|
|
$
|
543,533
|
|
|
|
|
|
|
|
|
|
|
Costs are transferred into the amortization base on an ongoing
basis, as projects are evaluated and proved reserves established
or impairment determined. Pending determination of proved
reserves attributable to the above costs; we 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 $17.1 million,
$16.8 million and $7.0 million for 2009, 2008 and
2007, respectively. Depletion per Mcfe was $1.36, $1.68 and
$1.28 for 2009, 2008 and 2007, respectively.
77
Other assets consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
Deferred financing costs
|
|
$
|
60,114
|
|
|
$
|
46,375
|
|
Less accumulated amortization
|
|
|
(14,249
|
)
|
|
|
(9,507
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred financing costs
|
|
|
45,865
|
|
|
|
36,868
|
|
Deposits
|
|
|
|
|
|
|
3,008
|
|
Other
|
|
|
898
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
46,763
|
|
|
$
|
40,648
|
|
|
|
|
|
|
|
|
|
|
Costs related to the acquisition of debt are deferred and
amortized over the term of the debt.
Accrued liabilities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Gas Purchase Commitment liability
|
|
$
|
50,744
|
|
|
$
|
|
|
Interest payable
|
|
|
71,768
|
|
|
|
30,713
|
|
Accrued operating expenses
|
|
|
21,136
|
|
|
|
20,296
|
|
Prepayments from partners
|
|
|
5,224
|
|
|
|
974
|
|
Revenue payable
|
|
|
4,141
|
|
|
|
7,181
|
|
Accrued production and property taxes
|
|
|
2,157
|
|
|
|
4,137
|
|
Environmental liabilities
|
|
|
659
|
|
|
|
50
|
|
Accrued product purchases
|
|
|
483
|
|
|
|
1,382
|
|
Accrued capital expenditures
|
|
|
|
|
|
|
1,695
|
|
Other
|
|
|
292
|
|
|
|
535
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
156,604
|
|
|
$
|
66,963
|
|
|
|
|
|
|
|
|
|
|
78
Long-term debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Senior Secured Credit Facility
|
|
$
|
467,569
|
|
|
$
|
827,868
|
|
Senior notes due 2015, net of unamortized discount of $5,036 and
$5,938
|
|
|
469,964
|
|
|
|
469,062
|
|
Senior notes due 2016, net of unamortized discount of $18,641
and $-
|
|
|
581,359
|
|
|
|
|
|
Senior notes due 2019, net of unamortized discount of $6,996 and
$-
|
|
|
293,004
|
|
|
|
|
|
Senior subordinated notes due 2016
|
|
|
350,000
|
|
|
|
350,000
|
|
Convertible debentures, net of unamortized discount of $13,881
and $20,761
|
|
|
136,119
|
|
|
|
129,239
|
|
KGS Credit Agreement
|
|
|
125,400
|
|
|
|
174,900
|
|
Senior secured second lien facility, net of unamortized discount
of $- and $13,050
|
|
|
|
|
|
|
641,555
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
2,423,415
|
|
|
|
2,592,624
|
|
Fair value of interest rate swaps hedges
|
|
|
4,108
|
|
|
|
|
|
Less current maturities
|
|
|
|
|
|
|
(6,579
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
2,427,523
|
|
|
$
|
2,586,045
|
|
|
|
|
|
|
|
|
|
|
Maturities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Senior Secured
|
|
|
Senior Notes
|
|
|
Senior Notes
|
|
|
Senior Notes
|
|
|
Subordinated
|
|
|
Convertible
|
|
|
KGS Credit
|
|
|
|
Indebtedness
|
|
|
Credit Facility
|
|
|
due in 2015
|
|
|
due in 2016
|
|
|
due in 2019
|
|
|
Notes
|
|
|
Debentures
|
|
|
Agreement
|
|
|
|
(In thousands)
|
|
|
2010
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
592,969
|
|
|
|
467,569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125,400
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
|
1,875,000
|
|
|
|
|
|
|
|
475,000
|
|
|
|
600,000
|
|
|
|
300,000
|
|
|
|
350,000
|
|
|
|
150,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,467,969
|
|
|
$
|
467,569
|
|
|
$
|
475,000
|
|
|
$
|
600,000
|
|
|
$
|
300,000
|
|
|
$
|
350,000
|
|
|
$
|
150,000
|
|
|
$
|
125,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
Secured Credit Facility
Our Senior Secured Credit Facility matures on February 9,
2012. The borrowing base at December 31, 2009 was
$1.0 billion, which resulted from a redetermination in
October 2009. The Senior Secured Credit Facility provides us an
option to increase the commitment by up to $250 million,
with a maximum of $1.45 billion with lender consents and
additional commitments. We can also extend the facility up to
two additional years with lenders approval. 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. U.S. borrowings under the facility are secured
by, among other things, Quicksilvers and our
U.S. subsidiaries oil and gas properties. Canadian
borrowings under the facility are secured by, among other
things, all of our oil and gas properties. We also pledged our
equity interests in BBEP to secure our obligations under the
Senior Secured Credit Facility. At December 31, 2009,
there was approximately $498 million available under the
facility. In January 2010, we repaid $95 million of
borrowings outstanding under the Senior Secured Credit Facility
using the proceeds from the sale of the Alliance Midstream
Assets to KGS. 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.
79
Senior
Notes Due 2015
On June 27, 2008, we issued $475 million of senior
notes due 2015, which are unsecured, senior obligations of
Quicksilver. Interest at the rate of 8.25% is payable
semiannually on February 1 and August 1.
Senior
Notes Due 2016
On June 25, 2009, we issued $600 million of senior
notes due 2016, which are unsecured, senior obligations of
Quicksilver. The notes were issued at 96.717% of par, which
resulted in proceeds of $580.3 million that were used to
repay a portion of the Senior Secured Second Lien Facility.
Interest at the rate of 11.75% is payable semiannually on
January 1 and July 1.
Senior
Notes Due 2019
On August 14, 2009, we issued $300 million of senior
notes due 2019, which are unsecured, senior obligations of
Quicksilver. The notes were issued at 97.612% of par, which
resulted in proceeds of $292.8 million that were used to
repay a portion of our Senior Secured Credit Facility. Interest
at the rate of 9.125% is payable semiannually on February 15 and
August 15.
Senior
Secured Second Lien Facility
On August 8, 2008, we entered into a $700 million
five-year Senior Secured Second Lien Facility pursuant to the
Alliance Acquisition. During 2009, proceeds from the Eni
Transaction and Senior Notes Due 2016 were used to fully repay
and terminate the remaining indebtedness under our Senior
Secured Second Lien Facility. Upon termination of the Senior
Secured Second Lien Facility, Quicksilvers and its
domestic subsidiaries guarantee obligations, which were
secured by a second lien on substantially all the assets of
Quicksilver and its domestic subsidiaries, terminated.
Furthermore, the financial covenants which required a minimum
value of the cash flows of our oil and gas reserves under our
Senior Secured Credit Facility were also eliminated.
Senior
Subordinated Notes
Our senior subordinated notes due 2016 were issued in 2006. The
senior subordinated notes are unsecured, senior subordinated
obligations of Quicksilver and bear interest at the rate of
7.125% which is payable semiannually on April 1 and
October 1.
Convertible
Debentures
The convertible debentures due November 1, 2024 are
contingently convertible into shares of Quicksilver common
stock. The debentures bear interest at an annual rate of 1.875%
payable semi-annually on May 1 and November 1.
Additionally, holders of the debentures can require us 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
Quicksilvers 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,
we have 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, 2010,
the debentures were not convertible based on share prices for
the quarter ended December 31, 2009.
KGS
Credit Agreement
Concurrent with its IPO, KGS entered into the KGS Credit
Agreement that matures August 12, 2012. The KGS Credit
Agreement may be extended through an option exercisable by KGS
to extend the agreement for up to two additional years with
lenders approval. In October 2009, the lenders increased
their commitment under agreement to $320 million. With
additional lender consent and commitment increases, KGS
availability
80
could expand to $350 million. KGS must maintain certain
financial ratios that can limit its borrowing capacity.
Borrowings under the agreement are guaranteed by KGS
subsidiaries and are secured by substantially all of the assets
of KGS and each of its subsidiaries. KGS received
$11.1 million in proceeds from the underwriters
January 2010 exercise of their option to purchase an additional
549,200 units. These proceeds were used by KGS to repay
$11 million of borrowings outstanding under the KGS Credit
Agreement. KGS also re-borrowed $95 million from the KGS
Credit Agreement to complete KGS purchase of our Alliance
Midstream Assets.
Summary
of All Outstanding Debt
The following table summarizes significant aspects of our
long-term debt.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Priority on Collateral and Structural
Seniority (1)
|
|
Recourse only to KGS assets
|
|
|
Highest
priority ¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾¾ Lowest
priority
|
|
|
|
|
|
|
Equal priority |
|
|
|
|
|
|
|
|
|
|
Senior Secured
|
|
|
2015
|
|
|
2016
|
|
|
2019
|
|
|
Senior
|
|
|
Convertible
|
|
KGS Credit
|
|
|
Credit Facility
|
|
|
Senior Notes
|
|
|
Senior Notes
|
|
|
Senior Notes
|
|
|
Subordinated Notes
|
|
|
Debentures
|
|
Agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Scheduled maturity date
|
|
February 9, 2012
|
|
|
August 1, 2015
|
|
|
January 1, 2016
|
|
|
September 1, 2019
|
|
|
April 1, 2016
|
|
|
November 1, 2024
|
|
August 10, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate at
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
(2)
|
|
3.30%
|
|
|
8.25%
|
|
|
11.75%
|
|
|
9.125%
|
|
|
7.125%
|
|
|
1.875%
|
|
3.26%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base interest rate options
(3)
|
|
LIBOR, ABR or
specified(4)
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
LIBOR, ABR or specified(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial covenants
(6)
|
|
- Minimum current
ratio of 1.0
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
- Maximum debt to EBITDA ratio of 4.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Minimum EBITDA to interest expense ratio of 2.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Minimum EBITDA
to interest expense
ratio of 2.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant restrictive
|
|
- Incurrence of debt
|
|
|
- Incurrence of debt
|
|
|
- Incurrence of debt
|
|
|
- Incurrence of debt
|
|
|
- Incurrence of debt
|
|
|
N/A
|
|
- Incurrence of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
covenants
(6)
|
|
- Incurrence of liens
|
|
|
- Incurrence of liens
|
|
|
- Incurrence of liens
|
|
|
- Incurrence of liens
|
|
|
- Incurrence of liens
|
|
|
|
|
- Incurrence of liens
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Payment of dividends
|
|
|
- Payment of dividends
|
|
|
- Payment of dividends
|
|
|
- Payment of dividends
|
|
|
- Payment of dividends
|
|
|
|
|
- Equity purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Equity purchases
|
|
|
- Equity purchases
|
|
|
- Equity purchases
|
|
|
- Equity purchases
|
|
|
- Equity purchases
|
|
|
|
|
- Asset sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Asset sales
|
|
|
- Asset sales
|
|
|
- Asset sales
|
|
|
- Asset sales
|
|
|
- Asset sales
|
|
|
|
|
- Limitations on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Affiliate transactions
|
|
|
- Affiliate transactions
|
|
|
- Affiliate transactions
|
|
|
- Affiliate transactions
|
|
|
- Affiliate transactions
|
|
|
|
|
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Limitations on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated fair value
(7)
|
|
$467.6 million
|
|
|
$486.9 million
|
|
|
$681.0 million
|
|
|
$313.8 million
|
|
|
$326.4 million
|
|
|
$180.0 million
|
|
$125.4 million
|
|
|
|
|
|
(1)
|
The Senior Secured Credit Facility is secured by a first
perfected lien on substantially all our assets excluding
KGS assets. The other debt presented is based upon
structural seniority and priority of payment.
|
|
|
|
(2)
|
Represents the weighted average borrowing rate payable to
lenders and excludes effects of interest rate derivatives.
|
|
|
|
(3)
|
Interest rate options include a base rate plus a spread.
|
|
|
|
(4)
|
The Senior Secured Credit Facility was amended in August 2009 to
add a floor to ABR of one-month LIBOR plus a 1%, increase in the
ABR margin to a range of 1.375% to 2.375% and an increase in the
Eurodollar and specified rate margins to a range of 2.25% to
3.25%.
|
|
|
|
(5)
|
The KGS Credit Agreement was amended in October 2009 to add a
floor to ABR of one-month LIBOR plus a 1%, increase in the ABR
margin to a range of 2.00% to 3.00% and an increase in the
Eurodollar and specified rate margins to a range of 3.00% to
4.00%.
|
|
|
|
(6)
|
The covenant information presented in this table is qualified in
all respects by reference to the full text of the covenants and
related definitions contained in the documents governing the
various components of our debt.
|
|
|
|
(7)
|
The estimated fair value is determined based on market
quotations on the balance sheet date for fixed rate
obligations. We consider debt with market-based interest rates
to have a fair value equal to its carrying value.
|
|
81
|
|
14.
|
ASSET
RETIREMENT OBLIGATIONS
|
The following table provides a reconciliation of the changes in
the estimated asset retirement obligation from January 1,
2008 through December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Beginning asset retirement obligations
|
|
$
|
35,193
|
|
|
$
|
24,510
|
|
Additional liability incurred
|
|
|
6,567
|
|
|
|
8,231
|
|
Change in estimates
|
|
|
12,916
|
|
|
|
4,288
|
|
Accretion expense
|
|
|
2,325
|
|
|
|
1,483
|
|
Sale of properties
|
|
|
(380
|
)
|
|
|
-
|
|
Asset retirement costs incurred
|
|
|
(379
|
)
|
|
|
(359
|
)
|
Gain on settlement of liability
|
|
|
131
|
|
|
|
119
|
|
Currency translation adjustment
|
|
|
3,004
|
|
|
|
(3,079
|
)
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligations
|
|
|
59,377
|
|
|
|
35,193
|
|
Less current portion
|
|
|
(109
|
)
|
|
|
(440
|
)
|
|
|
|
|
|
|
|
|
|
Non-current asset retirement obligation
|
|
$
|
59,268
|
|
|
$
|
34,753
|
|
|
|
|
|
|
|
|
|
|
Our current and deferred tax positions were significantly
impacted by the November 2007 divestiture of the Northeast
Operations and the resulting gain and the impairments of our oil
and gas properties and our investment in BBEP in 2009 and 2008.
Significant components of our deferred tax assets and
liabilities as of December 31, 2009 and 2008 are as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carry forwards
|
|
$
|
290,894
|
|
|
$
|
176,957
|
|
Cash flow hedge settlements
|
|
|
19,214
|
|
|
|
-
|
|
Deferred compensation expense
|
|
|
10,654
|
|
|
|
4,236
|
|
Other
|
|
|
8,712
|
|
|
|
969
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets
|
|
|
329,474
|
|
|
|
182,162
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$
|
(186,658
|
)
|
|
$
|
(318,070
|
)
|
Cash flow hedge gains
|
|
|
(55,372
|
)
|
|
|
(92,854
|
)
|
BBEP investment
|
|
|
(29,398
|
)
|
|
|
(40,270
|
)
|
Convertible debenture interest
|
|
|
(18,588
|
)
|
|
|
(17,297
|
)
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
(290,016
|
)
|
|
|
(468,941
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax asset (liability)
|
|
$
|
39,458
|
|
|
$
|
(286,779
|
)
|
|
|
|
|
|
|
|
|
|
Reflected in the consolidated balance sheets as:
|
|
|
|
|
|
|
|
|
Non-current deferred income tax asset
|
|
$
|
133,051
|
|
|
$
|
-
|
|
Current deferred income tax liability
|
|
|
(51,675
|
)
|
|
|
(52,393
|
)
|
Non-current deferred income tax liability
|
|
|
(41,918
|
)
|
|
|
(234,386
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
39,458
|
|
|
$
|
(286,779
|
)
|
|
|
|
|
|
|
|
|
|
82
The 2008 presentation of deferred tax assets and liabilities has
been conformed to the 2009 presentation. In conforming the 2008
amounts, we now present a deferred tax liability for our
investment in BBEP by combining $112 million previously
reported as deferred tax asset captioned as BBEP
impairment and $152 million previously reported as a
deferred tax liability attributable to property, plant and
equipment.
Tax rate reductions were enacted during 2007 by the Canadian
federal government and by Alberta provincial government. Our
Canadian deferred income tax balances were revalued to reflect
the changes in these tax rates. We 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 or 2009.
The components of income tax expense for 2009, 2008 and 2007 are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Current state income tax expense (benefit)
|
|
$
|
(2
|
)
|
|
$
|
(4
|
)
|
|
$
|
1,143
|
|
|
|
|
|
Current U.S. federal income tax expense (benefit)
|
|
|
(202
|
)
|
|
|
(45,210
|
)
|
|
|
45,394
|
|
|
|
|
|
Current Canadian income tax expense
|
|
|
-
|
|
|
|
199
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current income tax expense (benefit)
|
|
|
(204
|
)
|
|
|
(45,015
|
)
|
|
|
46,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred state income tax expense (benefit)
|
|
|
(4,928
|
)
|
|
|
1,939
|
|
|
|
2,538
|
|
|
|
|
|
Deferred U.S. federal income tax expense (benefit)
|
|
|
(262,217
|
)
|
|
|
(190,938
|
)
|
|
|
194,129
|
|
|
|
|
|
Deferred Canadian income tax expense (benefit)
|
|
|
(24,268
|
)
|
|
|
22,559
|
|
|
|
11,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax expense (benefit)
|
|
|
(291,413
|
)
|
|
|
(166,440
|
)
|
|
|
207,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
$
|
(291,617
|
)
|
|
$
|
(211,455
|
)
|
|
$
|
254,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table reconciles the statutory federal income tax
rate to the effective tax rate for 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
U.S. federal statutory tax rate
|
|
|
35.00
|
%
|
|
|
35.00
|
%
|
|
|
35.00
|
%
|
Permanent differences
|
|
|
(0.18
|
)%
|
|
|
(0.33
|
)%
|
|
|
0.01
|
%
|
Noncontrolling interest benefit
|
|
|
0.71
|
%
|
|
|
-
|
|
|
|
-
|
|
State income taxes net of federal deduction
|
|
|
0.38
|
%
|
|
|
(0.22
|
)%
|
|
|
0.33
|
%
|
Recognition of uncertain tax position
|
|
|
-
|
|
|
|
(0.09
|
)%
|
|
|
1.18
|
%
|
Foreign income taxes
|
|
|
(0.98
|
)%
|
|
|
1.38
|
%
|
|
|
(1.71
|
)%
|
Other
|
|
|
(0.08
|
)%
|
|
|
0.40
|
%
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
34.85
|
%
|
|
|
36.14
|
%
|
|
|
34.81
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We incurred net operating tax losses of $331 million and
$656 million in 2009 and 2008, respectively. Approximately
$138 million of this loss was carried back to 2007. The
remaining $849 million is included in deferred tax assets
at December 31, 2009. Our net operating losses will expire
in 2028 and 2029. In December 2009, newly enacted federal
legislation allowed us to carry back 2008 alternative minimum
tax losses of $35 million to 2004 and 2007. The net
operating losses were not reduced by a valuation allowance,
because management believes that future taxable income would
more likely than not be sufficient to utilize substantially all
of our operating loss tax carry forwards prior to their
expiration.
During 2007, we 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 and 2009 because of the
availability of net operating loss tax carry forwards of
Quicksilver.
The following schedule reconciles the total amounts of
unrecognized tax benefits for 2009 and 2008.
83
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Beginning unrecognized tax benefits
|
|
$
|
9,255
|
|
|
$
|
9,997
|
|
Gross amounts of increases in unrecognized tax benefits as a
result of tax positions taken during a prior period
|
|
|
-
|
|
|
|
834
|
|
Amount of decreases in unrecognized tax benefits related to
settlements with taxing authorities
|
|
|
-
|
|
|
|
(1,301
|
)
|
Gross amounts of decreases in unrecognized tax benefits as a
result of tax positions taken during the current year
|
|
|
(36
|
)
|
|
|
-
|
|
Reductions resulting from the lapse of applicable statutes of
limitations
|
|
|
-
|
|
|
|
(275
|
)
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefits
|
|
$
|
9,219
|
|
|
$
|
9,255
|
|
|
|
|
|
|
|
|
|
|
Approximately $8.9 million of these unrecognized tax
benefits at December 31, 2009 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. An audit was completed by the IRS for 2004
and the statute of limitations has now expired for that year.
During October 2009, the Internal Revenue Service commenced an
audit of our 2007 and 2008 consolidated U.S. federal income
tax returns. Although no significant adjustments are expected,
any required adjustments will be made upon completion of the
audit. We remain subject to examination by the Internal Revenue
Service for the years 2001 through 2008 except for 2004. Our
management does not expect that the total amounts of
unrecognized tax benefits will significantly increase or
decrease over the next twelve months.
|
|
16.
|
COMMITMENTS
AND CONTINGENCIES
|
Contractual
Obligations.
Information regarding our contractual obligations, at
December 31, 2009, is set forth in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
|
|
|
|
|
|
|
|
|
|
|
|
|
and Processing
|
|
|
Drilling Rig
|
|
|
Operating
|
|
|
Purchase
|
|
|
|
Contracts
(1)
|
|
|
Contracts
(2)
|
|
|
Leases
(3)
|
|
|
Obligations
(4)
|
|
|
|
(In thousands)
|
|
|
2010
|
|
$
|
43,909
|
|
|
$
|
45,519
|
|
|
$
|
2,678
|
|
|
$
|
19,554
|
|
2011
|
|
|
56,356
|
|
|
|
32,420
|
|
|
|
2,271
|
|
|
|
5,273
|
|
2012
|
|
|
80,905
|
|
|
|
17,876
|
|
|
|
1,363
|
|
|
|
-
|
|
2013
|
|
|
101,121
|
|
|
|
791
|
|
|
|
640
|
|
|
|
-
|
|
2014
|
|
|
79,391
|
|
|
|
-
|
|
|
|
558
|
|
|
|
-
|
|
Thereafter
|
|
|
267,434
|
|
|
|
-
|
|
|
|
418
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
629,116
|
|
|
$
|
96,606
|
|
|
$
|
7,928
|
|
|
$
|
24,827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Under contracts with various pipeline companies, we are
obligated to provide minimum daily natural gas volumes for
transport or processing, as calculated on a monthly basis, or
pay for any deficiencies at a specified reservation fee rate.
Our available production committed to the pipelines and
processing plants is expected to meet, or exceed, the daily
volumes required under the contracts.
|
|
|
|
(2)
|
We lease drilling rigs from third parties for use in our
development and exploration programs. The outstanding drilling
rig contracts require payment of a specified day rate ranging
from $20,500 to $26,500 for the entire lease term regardless of
our utilization of the drilling rigs.
|
|
|
|
(3)
|
We lease office buildings and other property under operating
leases. Rent expense for operating leases with terms exceeding
one month was $4.1 million in 2009, $5.0 million in
2008 and $5.2 million in 2007.
|
|
84
|
|
|
|
|
(4)
|
At December 31, 2009, we and KGS were under contract to
purchase goods and services related to field operations and gas
processing plant operations. KGS obligations totaled
$7.4 million.
|
|
Commitments
We had $39.1 million in surety bonds issued to fulfill
contractual, legal or regulatory requirements and
$34.5 million in letters of credit outstanding against the
credit facility, including $21.4 million issued to provide
credit support for surety bonds. Surety bonds and letters of
credit generally have an annual renewal option.
Contingencies
On November 7, 2001, we 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 Quicksilver against CMS,
declaring our contract with CMS to be void and rescinded as of
that date. CMS appealed this judgment. We also appealed
seeking to have the contract voided from its inception and to
recover jury-awarded punitive damages of $10 million. On
June 25, 2009, the Court of Appeals for the Second District
of Texas, reversed the original district court judgment.
Pursuant to a settlement agreement, we paid CMS $5 million
that was recognized as a component of general and administrative
expense during 2009.
Our lawsuit filed October 13, 2006 against Eagle Drilling
LLC (Eagle) as well as Eagle Domestic Drilling LLC
and its parent Blast Energy Services Inc.
(Eagle/Blast), regarding three contracts for
drilling rigs, is currently pending in U.S. District Court
for the Southern District of Texas in Houston, Texas. We assert
claims against Eagle for, among other things, breach of
contract, breach of express and implied warranties, fraud, and
negligence in connection with Eagles obligation to provide
three drilling rigs. We also seek declaratory relief, actual
damages, and recovery of our attorney fees. Eagle/Blast are no
longer parties in this case. In September 2008, we entered into
a settlement agreement with Eagle/Blast that was approved in the
court in October 2008. Under the settlement agreement, we
agreed to pay Eagle/Blast $10 million over a three-year
period, including $5 million on the settlement date. We
recorded a $9.6 million charge to general and
administrative expense during 2008 for the net present value of
these payments. In the still pending suit, Eagle filed counter
claims against us and our Executive Vice President
Operations, our Chairman, and our Chief Executive Officer for,
among other things, alleged breach of contract, bad faith breach
of contract, tortious interference with business relationships,
false representation, conspiracy and invasion of privacy.
Eagles current complaint seeks an unspecified amount of
actual and exemplary damages, interest, costs, and attorney
fees. We are asserting a vigorous defense to Eagles
claims in addition to actively prosecuting our claims.
On September 17, 2007, Eagle and Rod and Richard Thornton,
sued Quicksilver and our Executive Vice President
Operations, in state district court Cleveland County, Oklahoma
for approximately $29 million in damages and an unspecified
amount of punitive damages resulting from Quicksilvers
repudiation of three rig contracts. In October 2009, a jury
awarded $22 million to the plaintiffs. We are actively
seeking an appeal in this matter.
On October 31, 2008, we filed a lawsuit in the 48th State
District Court in Fort Worth, Texas against BBEP, certain
entities related to BBEP, Provident Energy Trust
(Provident) and certain individuals who serve as, or
have previously served as, directors or officers of these
entities for violations of, among other things, breach of
contract, the Texas Securities Act, the Texas
Business & Commerce Code, common law fraud, fraudulent
inducement, negligent misrepresentation and civil conspiracy.
We sought relief for actual and exemplary damages, and for
injunctive and declaratory relief. On February 3, 2010,
the parties entered into a settlement agreement whereby we will
receive $18 million in cash along with the retention of
full voting rights for our units held in BBEP subject to the
provisions of a limited standstill agreement, the ability to
85
name two directors to the board of BBEPs general partner,
the reinstitution of the BBEP quarterly distributions and other
governance accommodations.
Environmental
Compliance
Our operations are subject to stringent and complex laws and
regulations pertaining to health, safety and the environment.
As an owner or operator of these facilities, we are subject to
laws and regulations at the federal, state, provincial and local
levels that relate to air and water quality, hazardous and solid
waste management and disposal and other environmental matters.
The cost of planning, designing, constructing and operating our
facilities must incorporate compliance with environmental laws
and regulations and safety standards. Failure to comply with
these laws and regulations may trigger a variety of
administrative, civil and potentially criminal enforcement
measures. At December 31, 2009, we had recorded
$0.7 million for liabilities for environmental matters.
|
|
17.
|
NONCONTROLLING
INTERESTS AND KGS
|
KGS issued 4,000,000 newly issued common units on
December 16, 2009 in the KGS Secondary Offering and
received $80.3 million, net of underwriters discount
and other offering costs. The portion of these proceeds related
to our initial ownership interests, $50.2 million, was
recognized as an increase to Additional Paid-in
Capital on our consolidated balance sheet. On
January 4, 2010, the underwriters exercised their option to
purchase an additional 549,200 newly issued common units for
$11.1 million, which further reduced our ownership of KGS
to 61.2% effective January 6, 2010. As a result we
recognized an additional $6.7 million to Additional
Paid-in Capital in January 2010. KGS offered additional
units to the public to provide funding for its acquisition of
the Alliance Midstream Assets from us, which was completed in
January 2010 for $95.2 million.
As of December 31, 2009, KGS ownership is summarized
in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
KGS Ownership
|
|
|
|
Quicksilver
|
|
|
Third Parties
|
|
|
Total
|
|
|
General partner interests
|
|
|
1.7
|
%
|
|
|
-
|
|
|
|
1.7
|
%
|
Limited partner interests:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common interests
|
|
|
20.1
|
%
|
|
|
37.5
|
%
|
|
|
57.6
|
%
|
Subordinated interests
|
|
|
40.7
|
%
|
|
|
-
|
|
|
|
40.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interests
|
|
|
62.5
|
%
|
|
|
37.5
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 continues to earn and pay at least $0.30 per
quarter on each outstanding common unit through that time.
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.
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Net income (loss)
|
|
$
|
(557,473
|
)
|
|
$
|
(378,276
|
)
|
|
$
|
475,390
|
|
Impact of assumed conversions interest on 1.875%
convertible debentures, net of income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
6,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to stockholders assuming conversion of
convertible debentures
|
|
$
|
(557,473
|
)
|
|
$
|
(378,276
|
)
|
|
$
|
481,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares basic
|
|
|
169,004
|
|
|
|
162,004
|
|
|
|
156,517
|
|
Effect of dilutive securities
(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee stock options
|
|
|
-
|
|
|
|
-
|
|
|
|
1,326
|
|
Employee stock awards
|
|
|
-
|
|
|
|
-
|
|
|
|
370
|
|
Contingently convertible debentures
|
|
|
-
|
|
|
|
-
|
|
|
|
9,816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares diluted
|
|
|
169,004
|
|
|
|
162,004
|
|
|
|
168,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share basic
|
|
$
|
(3.30
|
)
|
|
$
|
(2.33
|
)
|
|
$
|
3.04
|
|
Earnings (loss) per common share diluted
|
|
$
|
(3.30
|
)
|
|
$
|
(2.33
|
)
|
|
$
|
2.87
|
|
|
|
|
|
|
(1)
|
For 2009 and 2008, the effects of convertible debt of
9.8 million shares and stock options and unvested
restricted stock units representing 0.8 million shares and
0.9 million, respectively were antidilutive and, therefore,
excluded from the diluted share calculations. No outstanding
options were excluded from the diluted net income per share
calculation for the year ended December 31, 2007.
|
|
|
|
19.
|
QUICKSILVER
STOCKHOLDERS EQUITY
|
Common
Stock, Preferred Stock and Treasury Stock
We are 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, 2009, we had 169.8 million
shares of common stock outstanding.
The following table shows common share and treasury share
activity since January 1, 2007:
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Treasury
|
|
|
|
Shares Issued
|
|
|
Shares Held
|
|
|
Opening balance at January 1, 2007
|
|
|
157,783,515
|
|
|
|
2,579,671
|
|
Stock options exercised
|
|
|
2,257,840
|
|
|
|
-
|
|
Restricted stock activity
|
|
|
591,915
|
|
|
|
37,055
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
160,633,270
|
|
|
|
2,616,726
|
|
Stock issuance
|
|
|
10,400,468
|
|
|
|
-
|
|
Stock repurchase
|
|
|
-
|
|
|
|
1,885,600
|
|
Stock options exercised
|
|
|
249,732
|
|
|
|
-
|
|
Restricted stock activity
|
|
|
459,229
|
|
|
|
70,469
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
171,742,699
|
|
|
|
4,572,795
|
|
Stock options exercised
|
|
|
610,000
|
|
|
|
-
|
|
Restricted stock activity
|
|
|
2,117,137
|
|
|
|
131,653
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
174,469,836
|
|
|
|
4,704,448
|
|
|
|
|
|
|
|
|
|
|
Quicksilver
Stockholder Rights Plan
In 2003, our 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
87
stockholders to buy one one-thousandth of a share of
Quicksilvers 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
Quicksilver. 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
our common stock at December 31, 2009.
If an Acquiring Person acquires 15% or more of our outstanding
common stock, each right will entitle its holder to purchase, at
the rights then-current exercise price, a number of common
shares of Quicksilver 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 our outstanding common stock, each right will
entitle its holder to purchase, at the rights then-current
exercise price, a number of the acquiring companys 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 our common stock, the rights are
redeemable for $0.01 per right at the option of our Board of
Directors.
Stock-Based
Compensation
2006
Equity Plan
In 2006, our Board of Directors and our shareholders approved
the 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. On
May 20, 2009, stockholders approved an amendment to the
2006 Equity Plan, which increased the number of shares available
for issuance to 15 million. Our executive officers, other
employees, consultants and non-employee directors are eligible
to participate in the 2006 Equity Plan. Under the 2006 Equity
Plan, options reflect an exercise price of no less than the fair
market value on the date of grant and have a life of
10 years. At December 31, 2009 and 2008,
15.1 million shares and 12.2 million shares,
respectively, (including 0.2 million shares and
0.1 million shares, respectively, surrendered to us 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 as stock
options, restricted stock and RSUs under the 2006 Equity Plan.
Stock
Options
The following summarizes the values from and assumptions for the
Black-Scholes option pricing model:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Wtd avg grant date fair value
|
|
$
|
6.21
|
|
|
$
|
13.67
|
|
|
|
N/A
|
|
Wtd avg grant date
|
|
|
Jan 2, 2009
|
|
|
|
Jan 2, 2008
|
|
|
|
N/A
|
|
Wtd avg risk-free interest rate
|
|
|
1.90
|
%
|
|
|
3.41
|
%
|
|
|
N/A
|
|
Expected life (in years)
|
|
|
6.0
|
|
|
|
6.0
|
|
|
|
N/A
|
|
Wtd avg volatility
|
|
|
56.76
|
%
|
|
|
40.2
|
%
|
|
|
N/A
|
|
Expected dividends
|
|
|
-
|
|
|
|
-
|
|
|
|
N/A
|
|
88
The following table summarizes our stock option activity for
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wtd Avg
|
|
|
Wtd Avg
|
|
|
|
|
|
|
|
|
|
Exercise
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
Shares
|
|
|
Price
|
|
|
Contractual Life
|
|
|
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Outstanding at January 1, 2009
|
|
|
1,103,336
|
|
|
$
|
14.20
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
2,605,699
|
|
|
|
6.21
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(610,000
|
)
|
|
|
6.63
|
|
|
|
|
|
|
|
|
|
Cancelled
|
|
|
(84,594
|
)
|
|
|
8.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
3,014,441
|
|
|
$
|
8.97
|
|
|
|
8.5
|
|
|
$
|
23,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2009
|
|
|
372,219
|
|
|
$
|
13.98
|
|
|
|
5.4
|
|
|
$
|
2,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that a total of 2,945,350 stock options will become
vested including those options already exercisable. These
unexercised options have a weighted average exercise price of
$9.04 and a weighted average remaining contractual life of
8.5 years.
Compensation expense related to stock options of
$4.5 million, $1.6 million and $0.1 million was
recognized for 2009, 2008 and 2007, respectively. Cash received
from the exercise of stock options totaled $4.0 million,
$1.2 million and $21.4 million for the years 2009,
2008 and 2007, respectively. The total intrinsic value of
options exercised during 2009, 2008 and 2007, was
$4.3 million, $6.7 million and $30.5 million,
respectively.
Restricted
Stock
The following table summarizes our restricted stock and stock
unit activity for 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payable in shares
|
|
|
Payable in cash
|
|
|
|
|
|
|
Wtd Avg
|
|
|
|
|
|
Wtd Avg
|
|
|
|
|
|
|
Grant Date
|
|
|
|
|
|
Grant Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Outstanding at January 1, 2009
|
|
|
1,336,111
|
|
|
$
|
24.01
|
|
|
|
-
|
|
|
$
|
-
|
|
Granted
|
|
|
2,279,679
|
|
|
|
6.28
|
|
|
|
339,835
|
|
|
|
6.22
|
|
Vested
|
|
|
(730,373
|
)
|
|
|
22.20
|
|
|
|
-
|
|
|
|
-
|
|
Cancelled
|
|
|
(162,542
|
)
|
|
|
14.12
|
|
|
|
(11,140
|
)
|
|
|
6.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
2,722,875
|
|
|
$
|
10.33
|
|
|
|
328,695
|
|
|
$
|
6.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008, we had unvested compensation cost of
$17.6 million. As of December 31, 2009, the
unrecognized compensation cost related to outstanding unvested
restricted stock was $15.1 million, which is expected to be
recognized in expense over the next 2 years. Grants of
restricted stock and stock units during 2009 had an estimated
grant date fair value of $14.3 million. The fair value of
RSUs settled in cash was $4.9 million at December 31,
2009. For 2009, 2008 and 2007, compensation expense of
$14.6 million, $13.5 million and $11.0 million,
respectively, was recognized. The total fair value of shares
vested during 2009, 2008 and 2007 was $11.0 million,
$15.1 million and $6.4 million, respectively.
KGS
Restricted Phantom Units
Awards of phantom units have been granted under KGS 2007
Equity Plan. On October 7, 2009, unitholders approved an
amendment to the 2007 Equity Plan, which increased the number of
units available for issuance to 750,000 as of November 4,
2009. All awards granted consist of phantom units that vest
ratably over three years and are to be settled in common units
or cash upon vesting as determined by the Board at the time of
grant. At December 31, 2009 and 2008, 750,000 units
and 603,993 units, respectively, were available for
issuance under the KGS 2007 Equity Plan, as amended.
89
The following table summarizes information regarding the phantom
unit activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payable in units
|
|
|
Payable in cash
|
|
|
|
|
|
|
Wtd Avg
|
|
|
|
|
|
Wtd Avg
|
|
|
|
|
|
|
Grant Date
|
|
|
|
|
|
Grant Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Outstanding at January 1, 2009
|
|
|
139,918
|
|
|
$
|
25.15
|
|
|
|
60,319
|
|
|
$
|
21.63
|
|
Granted
|
|
|
(49,789
|
)
|
|
|
25.25
|
|
|
|
(26,526
|
)
|
|
|
13.79
|
|
Vested
|
|
|
405,428
|
|
|
|
10.06
|
|
|
|
5,420
|
|
|
|
16.65
|
|
Cancelled
|
|
|
(9,885
|
)
|
|
|
15.90
|
|
|
|
(5,973
|
)
|
|
|
21.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
485,672
|
|
|
$
|
12.73
|
|
|
|
33,240
|
|
|
$
|
27.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008, KGS had total unvested compensation
cost of $2.3 million related to unvested phantom units.
KGS recognized compensation expense for 2009 and 2008 of
$2.6 million and $1.4 million, respectively. Grants
of phantom units during the year ended December 31, 2009
had an estimated grant date fair value of $4.2 million.
KGS has unearned compensation of $2.9 million which will be
recognized in expense over the next 1.9 years. Phantom
units that vested during 2009 and 2008 had a fair value of
$1.6 million and $0.7 million, respectively.
|
|
20.
|
CONDENSED
CONSOLIDATING FINANCIAL INFORMATION
|
The following tables provide information about the entities that
guarantee Quicksilvers senior notes and senior
subordinated notes. The guarantees are full and unconditional
and joint and several. Under SEC rules, we are required to
present financial information segregated between its guarantor
and non-guarantor subsidiaries. The indentures under both our
senior notes and our senior subordinated notes distinguish
between restricted subsidiaries and
unrestricted subsidiaries and further specify
supplemental information that is not required under GAAP. The
following table illustrates our subsidiaries and their status
pursuant to the senior notes due 2015, senior notes due 2016,
senior notes due 2019 and the senior subordinated notes:
|
|
|
|
|
Guarantor Subsidiaries -
|
|
Non-Guarantor Subsidiaries
|
Restricted
|
|
Restricted
|
|
Unrestricted
|
|
Cowtown Pipeline Funding, Inc.
|
|
Quicksilver Resources Canada, Inc.
|
|
Quicksilver Gas Services Holdings LLC
|
Cowtown Pipeline Management, Inc.
|
|
Mercury Michigan, Inc.
(1)
|
|
Quicksilver Gas Services GP LLC
|
Cowtown Pipeline L.P.
|
|
Terra Energy Ltd.
(1)
|
|
Quicksilver Gas Services LP
|
Cowtown Gas Processing L.P.
|
|
GTG Pipeline Corporation
(1)
|
|
Quicksilver Gas Services Operating LLC
(4)
|
|
|
Terra Pipeline Company
(1)
|
|
Quicksilver Gas Services Operating GP LLC
(4)
|
|
|
Beaver Creek Pipeline, LLC
(1)
|
|
Cowtown Pipeline Partners
L.P. (4)
|
|
|
Quicksilver Resources Horn River Inc.
(2)
|
|
Cowtown Gas Processing Partners L.P.
(4)
|
|
|
Cowtown Drilling Inc.
(3)
|
|
|
|
|
|
|
|
(1)
|
Prior to the sale of our Northeast Operations in November 2007,
these entities were restricted guarantor subsidiaries. After
the sale, they have been reclassified to restricted
non-guarantor subsidiaries for all periods presented.
|
|
|
|
(2)
|
This entity was amalgamated into Quicksilver Resources Canada
Inc. on January 1, 2009.
|
|
|
|
(3)
|
This entity was dormant for the three-year period ended
December 31, 2009.
|
|
|
|
(4)
|
Each entity is a wholly owned subsidiary of and consolidated
into KGS.
|
|
We own 100% of each of the restricted subsidiaries. Quicksilver
and the restricted subsidiaries conduct all of our exploration
and production activities, and the unrestricted subsidiaries
only conduct midstream operations. Neither the restricted
non-guarantor subsidiaries nor the unrestricted non-guarantor
subsidiaries guarantee the obligations under the Senior Notes
and the Senior Subordinated Notes. However, the restricted
non-guarantor subsidiaries, like the restricted guarantor
subsidiaries, are limited in their activity by the covenants in
the indenture for such matters as:
90
|
|
|
|
|
incurring additional indebtedness;
|
|
|
paying dividends;
|
|
|
selling assets;
|
|
|
making investments; and
|
|
|
making restricted payments.
|
Subject to restrictions set forth in the indentures, we may in
the future designate one or more additional subsidiaries as
unrestricted.
The following tables present financial information about
Quicksilver and our restricted subsidiaries for the annual
periods covered by the consolidated financial statements.
Condensed
Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
Consolidating
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
313,485
|
|
|
$
|
394
|
|
|
$
|
42,622
|
|
|
$
|
(121,580
|
)
|
|
$
|
234,921
|
|
|
$
|
2,268
|
|
|
$
|
(17,251
|
)
|
|
$
|
219,938
|
|
Property and equipment
|
|
|
1,980,053
|
|
|
|
217,407
|
|
|
|
491,528
|
|
|
|
-
|
|
|
|
2,688,988
|
|
|
|
396,952
|
|
|
|
-
|
|
|
|
3,085,940
|
|
Investment in subsidiaries (equity method)
|
|
|
549,200
|
|
|
|
149,945
|
|
|
|
-
|
|
|
|
(436,437
|
)
|
|
|
262,708
|
|
|
|
-
|
|
|
|
(149,945
|
)
|
|
|
112,763
|
|
Other assets
|
|
|
235,304
|
|
|
|
-
|
|
|
|
3,112
|
|
|
|
-
|
|
|
|
238,416
|
|
|
|
9,067
|
|
|
|
(53,242
|
)
|
|
|
194,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,078,042
|
|
|
$
|
367,746
|
|
|
$
|
537,262
|
|
|
$
|
(558,017
|
)
|
|
$
|
3,425,033
|
|
|
$
|
408,287
|
|
|
$
|
(220,438
|
)
|
|
$
|
3,612,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
349,415
|
|
|
$
|
120,302
|
|
|
$
|
25,321
|
|
|
$
|
(121,580
|
)
|
|
$
|
373,458
|
|
|
$
|
10,453
|
|
|
$
|
(17,251
|
)
|
|
$
|
366,660
|
|
Long-term liabilities
|
|
|
2,092,629
|
|
|
|
13,108
|
|
|
|
309,840
|
|
|
|
-
|
|
|
|
2,415,577
|
|
|
|
187,065
|
|
|
|
(53,242
|
)
|
|
|
2,549,400
|
|
Quicksilver stockholders equity
|
|
|
635,998
|
|
|
|
234,336
|
|
|
|
202,101
|
|
|
|
(436,437
|
)
|
|
|
635,998
|
|
|
|
149,945
|
|
|
|
(149,945
|
)
|
|
|
635,998
|
|
Noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
60,824
|
|
|
|
-
|
|
|
|
60,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,078,042
|
|
|
$
|
367,746
|
|
|
$
|
537,262
|
|
|
$
|
(558,017
|
)
|
|
$
|
3,425,033
|
|
|
$
|
408,287
|
|
|
$
|
(220,438
|
)
|
|
$
|
3,612,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
Consolidating
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
424,862
|
|
|
$
|
163
|
|
|
$
|
102,384
|
|
|
$
|
(123,071
|
)
|
|
$
|
404,338
|
|
|
$
|
2,439
|
|
|
$
|
(13,441
|
)
|
|
$
|
393,336
|
|
Property and equipment
|
|
|
2,756,915
|
|
|
|
1,774
|
|
|
|
550,906
|
|
|
|
-
|
|
|
|
3,309,595
|
|
|
|
432,272
|
|
|
|
55,848
|
|
|
|
3,797,715
|
|
Assets of discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
56,022
|
|
|
|
(56,022
|
)
|
|
|
-
|
|
Investment in subsidiaries (equity method)
|
|
|
513,706
|
|
|
|
79,316
|
|
|
|
-
|
|
|
|
(363,203
|
)
|
|
|
229,819
|
|
|
|
-
|
|
|
|
(79,316
|
)
|
|
|
150,503
|
|
Other assets
|
|
|
206,099
|
|
|
|
123,298
|
|
|
|
910
|
|
|
|
-
|
|
|
|
330,307
|
|
|
|
1,916
|
|
|
|
(175,569
|
)
|
|
|
156,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,901,582
|
|
|
$
|
204,551
|
|
|
$
|
654,200
|
|
|
$
|
(486,274
|
)
|
|
$
|
4,274,059
|
|
|
$
|
492,649
|
|
|
$
|
(268,500
|
)
|
|
$
|
4,498,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
357,077
|
|
|
$
|
122,677
|
|
|
$
|
44,907
|
|
|
$
|
(123,071
|
)
|
|
$
|
401,590
|
|
|
$
|
27,183
|
|
|
$
|
(10,274
|
)
|
|
$
|
418,499
|
|
Long-term liabilities
|
|
|
2,359,679
|
|
|
|
-
|
|
|
|
327,964
|
|
|
|
-
|
|
|
|
2,687,643
|
|
|
|
299,111
|
|
|
|
(118,608
|
)
|
|
|
2,868,146
|
|
Liabilities of discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
60,302
|
|
|
|
(60,302
|
)
|
|
|
-
|
|
Quicksilver stockholders equity
|
|
|
1,184,826
|
|
|
|
81,874
|
|
|
|
281,329
|
|
|
|
(363,203
|
)
|
|
|
1,184,826
|
|
|
|
79,316
|
|
|
|
(79,316
|
)
|
|
|
1,184,826
|
|
Noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
26,737
|
|
|
|
-
|
|
|
|
26,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,901,582
|
|
|
$
|
204,551
|
|
|
$
|
654,200
|
|
|
$
|
(486,274
|
)
|
|
$
|
4,274,059
|
|
|
$
|
492,649
|
|
|
$
|
(268,500
|
)
|
|
$
|
4,498,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
Condensed
Consolidating Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2009
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
Consolidated
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Revenue
|
|
$
|
634,321
|
|
|
$
|
4,395
|
|
|
$
|
188,769
|
|
|
$
|
(2,014
|
)
|
|
$
|
825,471
|
|
|
$
|
91,706
|
|
|
$
|
(84,442
|
)
|
|
$
|
832,735
|
|
Operating expense
|
|
|
1,202,124
|
|
|
|
9,413
|
|
|
|
273,969
|
|
|
|
(2,014
|
)
|
|
|
1,483,492
|
|
|
|
47,610
|
|
|
|
(84,494
|
)
|
|
|
1,446,608
|
|
Equity in net earnings of subsidiaries
|
|
|
(52,643
|
)
|
|
|
27,161
|
|
|
|
-
|
|
|
|
52,643
|
|
|
|
27,161
|
|
|
|
-
|
|
|
|
(27,161
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(620,446
|
)
|
|
|
22,143
|
|
|
|
(85,200
|
)
|
|
|
52,643
|
|
|
|
(630,860
|
)
|
|
|
44,096
|
|
|
|
(27,109
|
)
|
|
|
(613,873
|
)
|
Income from earnings of BBEP
|
|
|
75,444
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
75,444
|
|
|
|
-
|
|
|
|
-
|
|
|
|
75,444
|
|
Impairment of investment in BBEP
|
|
|
(102,084
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(102,084
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(102,084
|
)
|
Interest expense and other
|
|
|
(180,980
|
)
|
|
|
3,725
|
|
|
|
(8,526
|
)
|
|
|
-
|
|
|
|
(185,781
|
)
|
|
|
(8,518
|
)
|
|
|
(2,044
|
)
|
|
|
(196,343
|
)
|
Income tax (expense) benefit
|
|
|
270,593
|
|
|
|
(9,054
|
)
|
|
|
24,269
|
|
|
|
-
|
|
|
|
285,808
|
|
|
|
5,809
|
|
|
|
-
|
|
|
|
291,617
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,992
|
)
|
|
|
1,992
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(557,473
|
)
|
|
$
|
16,814
|
|
|
$
|
(69,457
|
)
|
|
$
|
52,643
|
|
|
$
|
(557,473
|
)
|
|
$
|
39,395
|
|
|
$
|
(27,161
|
)
|
|
$
|
(545,239
|
)
|
Net income attributable to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(12,234
|
)
|
|
|
-
|
|
|
|
(12,234
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Quicksilver
|
|
$
|
(557,473
|
)
|
|
$
|
16,814
|
|
|
$
|
(69,457
|
)
|
|
$
|
52,643
|
|
|
$
|
(557,473
|
)
|
|
$
|
27,161
|
|
|
$
|
(27,161
|
)
|
|
$
|
(557,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2008
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Revenue
|
|
$
|
600,906
|
|
|
$
|
514
|
|
|
$
|
187,126
|
|
|
$
|
(426
|
)
|
|
$
|
788,120
|
|
|
$
|
76,084
|
|
|
$
|
(63,563
|
)
|
|
$
|
800,641
|
|
Operating expense
|
|
|
976,984
|
|
|
|
11,157
|
|
|
|
86,937
|
|
|
|
(426
|
)
|
|
|
1,074,652
|
|
|
|
38,659
|
|
|
|
(62,973
|
)
|
|
|
1,050,338
|
|
Equity in net earnings of subsidiaries
|
|
|
74,331
|
|
|
|
21,762
|
|
|
|
-
|
|
|
|
(74,331
|
)
|
|
|
21,762
|
|
|
|
-
|
|
|
|
(21,762
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(301,747
|
)
|
|
|
11,119
|
|
|
|
100,189
|
|
|
|
(74,331
|
)
|
|
|
(264,770
|
)
|
|
|
37,425
|
|
|
|
(22,352
|
)
|
|
|
(249,697
|
)
|
Income from earnings of BBEP
|
|
|
93,298
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
93,298
|
|
|
|
-
|
|
|
|
-
|
|
|
|
93,298
|
|
Impairment of investment in BBEP
|
|
|
(320,387
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(320,387
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(320,387
|
)
|
Interest expense and other
|
|
|
(89,657
|
)
|
|
|
6,023
|
|
|
|
(14,491
|
)
|
|
|
-
|
|
|
|
(98,125
|
)
|
|
|
(8,426
|
)
|
|
|
(1,740
|
)
|
|
|
(108,291
|
)
|
Income tax (expense) benefit
|
|
|
240,217
|
|
|
|
(6,000
|
)
|
|
|
(22,509
|
)
|
|
|
-
|
|
|
|
211,708
|
|
|
|
(253
|
)
|
|
|
-
|
|
|
|
211,455
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,330
|
)
|
|
|
2,330
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(378,276
|
)
|
|
$
|
11,142
|
|
|
$
|
63,189
|
|
|
$
|
(74,331
|
)
|
|
$
|
(378,276
|
)
|
|
$
|
26,416
|
|
|
$
|
(21,762
|
)
|
|
$
|
(373,622
|
)
|
Net income attributable to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,654
|
)
|
|
|
-
|
|
|
|
(4,654
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Quicksilver
|
|
$
|
(378,276
|
)
|
|
$
|
11,142
|
|
|
$
|
63,189
|
|
|
$
|
(74,331
|
)
|
|
$
|
(378,276
|
)
|
|
$
|
21,762
|
|
|
$
|
(21,762
|
)
|
|
$
|
(378,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Revenue
|
|
$
|
367,894
|
|
|
$
|
-
|
|
|
$
|
187,154
|
|
|
$
|
(160
|
)
|
|
$
|
554,888
|
|
|
$
|
35,695
|
|
|
$
|
(29,325
|
)
|
|
$
|
561,258
|
|
Operating expense
|
|
|
241,174
|
|
|
|
601
|
|
|
|
88,517
|
|
|
|
(160
|
)
|
|
|
330,132
|
|
|
|
22,513
|
|
|
|
(29,123
|
)
|
|
|
323,522
|
|
Income from equity affiliates
|
|
|
14
|
|
|
|
-
|
|
|
|
647
|
|
|
|
-
|
|
|
|
661
|
|
|
|
-
|
|
|
|
-
|
|
|
|
661
|
|
Gain on sale of properties
|
|
|
628,709
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
628,709
|
|
|
|
-
|
|
|
|
-
|
|
|
|
628,709
|
|
Loss on natural gas supply contracts
|
|
|
(63,525
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(63,525
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(63,525
|
)
|
Equity in net earnings of subsidiaries
|
|
|
73,468
|
|
|
|
7,407
|
|
|
|
-
|
|
|
|
(73,468
|
)
|
|
|
7,407
|
|
|
|
-
|
|
|
|
(7,407
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
765,386
|
|
|
|
6,806
|
|
|
|
99,284
|
|
|
|
(73,468
|
)
|
|
|
798,008
|
|
|
|
13,182
|
|
|
|
(7,609
|
)
|
|
|
803,581
|
|
Interest expense and other
|
|
|
(56,212
|
)
|
|
|
2,609
|
|
|
|
(14,776
|
)
|
|
|
-
|
|
|
|
(68,379
|
)
|
|
|
(4,021
|
)
|
|
|
(375
|
)
|
|
|
(72,775
|
)
|
Income tax (expense) benefit
|
|
|
(233,784
|
)
|
|
|
(3,228
|
)
|
|
|
(17,036
|
)
|
|
|
-
|
|
|
|
(254,048
|
)
|
|
|
(313
|
)
|
|
|
-
|
|
|
|
(254,361
|
)
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(592
|
)
|
|
|
592
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
475,390
|
|
|
$
|
6,187
|
|
|
$
|
67,472
|
|
|
$
|
(73,468
|
)
|
|
$
|
475,581
|
|
|
$
|
8,256
|
|
|
$
|
(7,392
|
)
|
|
$
|
476,445
|
|
Net income attributable to noncontrolling interests
|
|
|
-
|
|
|
|
(191
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(191
|
)
|
|
|
(864
|
)
|
|
|
-
|
|
|
|
(1,055
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Quicksilver
|
|
$
|
475,390
|
|
|
$
|
5,996
|
|
|
$
|
67,472
|
|
|
$
|
(73,468
|
)
|
|
$
|
475,390
|
|
|
$
|
7,392
|
|
|
$
|
(7,392
|
)
|
|
$
|
475,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92
Condensed
Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2009
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net cash flow provided by operating activities
|
|
$
|
358,342
|
|
|
$
|
73,202
|
|
|
$
|
148,280
|
|
|
$
|
-
|
|
|
$
|
579,824
|
|
|
$
|
68,133
|
|
|
$
|
(35,717
|
)
|
|
$
|
612,240
|
|
Purchases of property, plant and equipment
|
|
|
(474,659
|
)
|
|
|
(73,202
|
)
|
|
|
(94,209
|
)
|
|
|
-
|
|
|
|
(642,070
|
)
|
|
|
(54,818
|
)
|
|
|
3,050
|
|
|
|
(693,838
|
)
|
Proceeds from sales of property, plant and equipment
|
|
|
220,206
|
|
|
|
-
|
|
|
|
768
|
|
|
|
-
|
|
|
|
220,974
|
|
|
|
-
|
|
|
|
-
|
|
|
|
220,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow used for investing activities
|
|
|
(254,453
|
)
|
|
|
(73,202
|
)
|
|
|
(93,441
|
)
|
|
|
-
|
|
|
|
(421,096
|
)
|
|
|
(54,818
|
)
|
|
|
3,050
|
|
|
|
(472,864
|
)
|
Issuance of debt
|
|
|
1,305,137
|
|
|
|
-
|
|
|
|
59,590
|
|
|
|
-
|
|
|
|
1,364,727
|
|
|
|
56,000
|
|
|
|
-
|
|
|
|
1,420,727
|
|
Repayments of debt
|
|
|
(1,428,105
|
)
|
|
|
-
|
|
|
|
(116,025
|
)
|
|
|
-
|
|
|
|
(1,544,130
|
)
|
|
|
(105,500
|
)
|
|
|
-
|
|
|
|
(1,649,630
|
)
|
Debt issuance costs
|
|
|
(29,901
|
)
|
|
|
-
|
|
|
|
(1,125
|
)
|
|
|
-
|
|
|
|
(31,026
|
)
|
|
|
(1,446
|
)
|
|
|
-
|
|
|
|
(32,472
|
)
|
Repayments to parent
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(5,645
|
)
|
|
|
5,645
|
|
|
|
-
|
|
Gas Purchase Commitment net
|
|
|
44,119
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
44,119
|
|
|
|
-
|
|
|
|
-
|
|
|
|
44,119
|
|
Issuance of KGS common units
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
80,729
|
|
|
|
-
|
|
|
|
80,729
|
|
Distributions to parent
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(27,022
|
)
|
|
|
27,022
|
|
|
|
-
|
|
Distributions to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(9,925
|
)
|
|
|
-
|
|
|
|
(9,925
|
)
|
Proceeds from exercise of stock options
|
|
|
4,046
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,046
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,046
|
|
Purchase of treasury stock
|
|
|
(922
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(922
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(922
|
)
|
Other
|
|
|
63
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
63
|
|
|
|
(63
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used for) financing activities
|
|
|
(105,563
|
)
|
|
|
-
|
|
|
|
(57,560
|
)
|
|
|
-
|
|
|
|
(163,123
|
)
|
|
|
(12,872
|
)
|
|
|
32,667
|
|
|
|
(143,328
|
)
|
Effect of exchange rates on cash
|
|
|
-
|
|
|
|
-
|
|
|
|
2,889
|
|
|
|
-
|
|
|
|
2,889
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and equivalents
|
|
|
(1,674
|
)
|
|
|
-
|
|
|
|
168
|
|
|
|
-
|
|
|
|
(1,506
|
)
|
|
|
443
|
|
|
|
-
|
|
|
|
(1,063
|
)
|
Cash and equivalents at beginning of period
|
|
|
1,679
|
|
|
|
-
|
|
|
|
866
|
|
|
|
-
|
|
|
|
2,545
|
|
|
|
303
|
|
|
|
-
|
|
|
|
2,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents at end of period
|
|
$
|
5
|
|
|
$
|
-
|
|
|
$
|
1,034
|
|
|
$
|
-
|
|
|
$
|
1,039
|
|
|
$
|
746
|
|
|
$
|
-
|
|
|
$
|
1,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2008
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net cash flow provided by operations
|
|
$
|
290,160
|
|
|
$
|
-
|
|
|
$
|
137,005
|
|
|
$
|
-
|
|
|
$
|
427,165
|
|
|
$
|
52,683
|
|
|
$
|
(23,282
|
)
|
|
$
|
456,566
|
|
Purchases of property, plant and equipment
|
|
|
(1,995,791
|
)
|
|
|
-
|
|
|
|
(136,057
|
)
|
|
|
-
|
|
|
|
(2,131,848
|
)
|
|
|
(148,079
|
)
|
|
|
-
|
|
|
|
(2,279,927
|
)
|
Proceeds from sale of equipment to subsidiaries
|
|
|
42,914
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
42,914
|
|
|
|
-
|
|
|
|
(42,914
|
)
|
|
|
-
|
|
Proceeds from sales of property, plant and equipment
|
|
|
721
|
|
|
|
-
|
|
|
|
618
|
|
|
|
-
|
|
|
|
1,339
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow used for investing activities
|
|
|
(1,952,156
|
)
|
|
|
-
|
|
|
|
(135,439
|
)
|
|
|
-
|
|
|
|
(2,087,595
|
)
|
|
|
(148,079
|
)
|
|
|
(42,914
|
)
|
|
|
(2,278,588
|
)
|
Issuance of debt
|
|
|
2,570,611
|
|
|
|
-
|
|
|
|
208,161
|
|
|
|
-
|
|
|
|
2,778,772
|
|
|
|
169,900
|
|
|
|
-
|
|
|
|
2,948,672
|
|
Repayments of debt
|
|
|
(886,429
|
)
|
|
|
-
|
|
|
|
(209,734
|
)
|
|
|
-
|
|
|
|
(1,096,163
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,096,163
|
)
|
Debt issuance costs
|
|
|
(24,733
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(24,733
|
)
|
|
|
(486
|
)
|
|
|
-
|
|
|
|
(25,219
|
)
|
Payments to parent
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(42,914
|
)
|
|
|
42,914
|
|
|
|
-
|
|
Distributions to parent
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(23,282
|
)
|
|
|
23,282
|
|
|
|
-
|
|
Distributions to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8,644
|
)
|
|
|
-
|
|
|
|
(8,644
|
)
|
Proceeds from exercise of stock options
|
|
|
1,244
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,244
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,244
|
|
Purchase of treasury stock
|
|
|
(23,137
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(23,137
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(23,137
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used for) financing activities
|
|
|
1,637,556
|
|
|
|
-
|
|
|
|
(1,573
|
)
|
|
|
-
|
|
|
|
1,635,983
|
|
|
|
94,574
|
|
|
|
66,196
|
|
|
|
1,796,753
|
|
Effect of exchange rates on cash
|
|
|
(893
|
)
|
|
|
-
|
|
|
|
784
|
|
|
|
-
|
|
|
|
(109
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and equivalents
|
|
|
(25,333
|
)
|
|
|
-
|
|
|
|
777
|
|
|
|
-
|
|
|
|
(24,556
|
)
|
|
|
(822
|
)
|
|
|
-
|
|
|
|
(25,378
|
)
|
Cash and equivalents at beginning of period
|
|
|
27,012
|
|
|
|
-
|
|
|
|
89
|
|
|
|
-
|
|
|
|
27,101
|
|
|
|
1,125
|
|
|
|
-
|
|
|
|
28,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents at end of period
|
|
$
|
1,679
|
|
|
$
|
-
|
|
|
$
|
866
|
|
|
$
|
-
|
|
|
$
|
2,545
|
|
|
$
|
303
|
|
|
$
|
-
|
|
|
$
|
2,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31, 2007
|
|
|
|
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Restricted
|
|
|
Quicksilver
|
|
|
Unrestricted
|
|
|
|
|
|
Quicksilver
|
|
|
|
Quicksilver
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Subsidiary
|
|
|
and Restricted
|
|
|
Non-Guarantor
|
|
|
|
|
|
Resources Inc.
|
|
|
|
Resources Inc.
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net cash flow provided by operations
|
|
$
|
190,777
|
|
|
$
|
(596
|
)
|
|
$
|
116,935
|
|
|
$
|
-
|
|
|
$
|
307,116
|
|
|
$
|
14,949
|
|
|
$
|
(2,961
|
)
|
|
$
|
319,104
|
|
Purchases of property, plant and equipment
|
|
|
(824,321
|
)
|
|
|
(267
|
)
|
|
|
(151,807
|
)
|
|
|
-
|
|
|
|
(976,395
|
)
|
|
|
(73,797
|
)
|
|
|
29,508
|
|
|
|
(1,020,684
|
)
|
Investment in subsidiaries and affiliates
|
|
|
(38,908
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(38,908
|
)
|
|
|
-
|
|
|
|
38,908
|
|
|
|
-
|
|
Return on investment in subsidiaries and affiliates
|
|
|
121,577
|
|
|
|
-
|
|
|
|
171
|
|
|
|
-
|
|
|
|
121,748
|
|
|
|
-
|
|
|
|
(112,113
|
)
|
|
|
9,635
|
|
Proceeds from sales of property, plant and equipment
|
|
|
741,297
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
741,297
|
|
|
|
-
|
|
|
|
-
|
|
|
|
741,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow used for investing activities
|
|
|
(355
|
)
|
|
|
(267
|
)
|
|
|
(151,636
|
)
|
|
|
-
|
|
|
|
(152,258
|
)
|
|
|
(73,797
|
)
|
|
|
(43,697
|
)
|
|
|
(269,752
|
)
|
Issuance of debt
|
|
|
594,500
|
|
|
|
-
|
|
|
|
218,321
|
|
|
|
-
|
|
|
|
812,821
|
|
|
|
5,000
|
|
|
|
-
|
|
|
|
817,821
|
|
Repayments of debt
|
|
|
(777,866
|
)
|
|
|
-
|
|
|
|
(190,691
|
)
|
|
|
-
|
|
|
|
(968,557
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(968,557
|
)
|
Debt issuance costs
|
|
|
(3,148
|
)
|
|
|
-
|
|
|
|
(664
|
)
|
|
|
-
|
|
|
|
(3,812
|
)
|
|
|
(1,318
|
)
|
|
|
-
|
|
|
|
(5,130
|
)
|
Proceeds from sale of KGS units, net
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
109,642
|
|
|
|
-
|
|
|
|
109,642
|
|
Contributions from noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
167
|
|
|
|
-
|
|
|
|
167
|
|
Contributions from parent
|
|
|
-
|
|
|
|
863
|
|
|
|
-
|
|
|
|
-
|
|
|
|
863
|
|
|
|
67,553
|
|
|
|
(68,416
|
)
|
|
|
-
|
|
Distributions to parent
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(115,074
|
)
|
|
|
115,074
|
|
|
|
-
|
|
Distributions to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8,794
|
)
|
|
|
-
|
|
|
|
(8,794
|
)
|
Proceeds from exercise of stock options
|
|
|
21,387
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
21,387
|
|
|
|
-
|
|
|
|
-
|
|
|
|
21,387
|
|
Excess tax benefits on exercise of stock options
|
|
|
2,755
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,755
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,755
|
|
Purchase of treasury stock
|
|
|
(1,567
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,567
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,567
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used for) financing activities
|
|
|
(163,939
|
)
|
|
|
863
|
|
|
|
26,966
|
|
|
|
-
|
|
|
|
(136,110
|
)
|
|
|
57,176
|
|
|
|
46,658
|
|
|
|
(32,276
|
)
|
Effect of exchange rates on cash
|
|
|
446
|
|
|
|
-
|
|
|
|
5,423
|
|
|
|
-
|
|
|
|
5,869
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and equivalents
|
|
|
26,929
|
|
|
|
-
|
|
|
|
(2,312
|
)
|
|
|
-
|
|
|
|
24,617
|
|
|
|
(1,672
|
)
|
|
|
-
|
|
|
|
22,945
|
|
Cash and equivalents at beginning of period
|
|
|
83
|
|
|
|
-
|
|
|
|
2,401
|
|
|
|
-
|
|
|
|
2,484
|
|
|
|
2,797
|
|
|
|
-
|
|
|
|
5,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents at end of period
|
|
$
|
27,012
|
|
|
$
|
-
|
|
|
$
|
89
|
|
|
$
|
-
|
|
|
$
|
27,101
|
|
|
$
|
1,125
|
|
|
$
|
-
|
|
|
$
|
28,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We operate in two geographic segments, the United States and
Canada, where we are engaged in the exploration and production
segment of the oil and gas industry. Additionally, we operate
in the midstream segment in the U.S., where we provide natural
gas gathering and processing services predominantly through
KGS. Revenue earned by KGS for the gathering and processing of
Quicksilver gas are eliminated on a consolidated basis as are
the costs of these services recognized by Quicksilvers
producing properties. We evaluate performance based on
operating income and property and equipment costs incurred.
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration & Production
|
|
|
Processing &
|
|
|
|
|
|
|
|
|
Quicksilver
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Gathering
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
634,321
|
|
|
$
|
188,770
|
|
|
$
|
99,817
|
|
|
$
|
-
|
|
|
$
|
(90,173
|
)
|
|
$
|
832,735
|
|
|
|
|
|
DD&A
|
|
|
134,066
|
|
|
|
38,965
|
|
|
|
26,682
|
|
|
|
1,674
|
|
|
|
-
|
|
|
|
201,387
|
|
|
|
|
|
Impairment related to oil and gas properties
|
|
|
786,867
|
|
|
|
192,673
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
979,540
|
|
|
|
|
|
Operating income (loss)
|
|
|
(500,164
|
)
|
|
|
(81,529
|
)
|
|
|
46,737
|
|
|
|
(78,917
|
)
|
|
|
-
|
|
|
|
(613,873
|
)
|
|
|
|
|
Investment in equity affiliates
|
|
|
112,763
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
112,763
|
|
|
|
|
|
Property, plant and equipment net
|
|
|
1,968,430
|
|
|
|
491,528
|
|
|
|
614,359
|
|
|
|
11,623
|
|
|
|
-
|
|
|
|
3,085,940
|
|
|
|
|
|
Property and equipment costs incurred
|
|
|
391,916
|
|
|
|
91,949
|
|
|
|
115,655
|
|
|
|
2,161
|
|
|
|
-
|
|
|
|
601,681
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
600,292
|
|
|
$
|
187,740
|
|
|
$
|
78,572
|
|
|
$
|
-
|
|
|
$
|
(65,963
|
)
|
|
$
|
800,641
|
|
|
|
|
|
DD&A
|
|
|
127,010
|
|
|
|
44,948
|
|
|
|
15,134
|
|
|
|
1,104
|
|
|
|
-
|
|
|
|
188,196
|
|
|
|
|
|
Impairment related to oil and gas properties
|
|
|
624,315
|
|
|
|
-
|
|
|
|
9,200
|
|
|
|
-
|
|
|
|
-
|
|
|
|
633,515
|
|
|
|
|
|
Operating income
|
|
|
(321,756
|
)
|
|
|
104,131
|
|
|
|
34,879
|
|
|
|
(66,951
|
)
|
|
|
-
|
|
|
|
(249,697
|
)
|
|
|
|
|
Investment in equity affiliates
|
|
|
150,503
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
150,503
|
|
|
|
|
|
Property, plant and equipment net
|
|
|
2,716,754
|
|
|
|
550,413
|
|
|
|
519,447
|
|
|
|
11,101
|
|
|
|
-
|
|
|
|
3,797,715
|
|
|
|
|
|
Property and equipment costs incurred
|
|
|
2,173,469
|
|
|
|
138,360
|
|
|
|
265,222
|
|
|
|
7,984
|
|
|
|
-
|
|
|
|
2,585,035
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
396,768
|
|
|
$
|
158,121
|
|
|
$
|
35,941
|
|
|
$
|
-
|
|
|
$
|
(29,572
|
)
|
|
$
|
561,258
|
|
|
|
|
|
DD&A
|
|
|
72,132
|
|
|
|
39,445
|
|
|
|
8,146
|
|
|
|
974
|
|
|
|
-
|
|
|
|
120,697
|
|
|
|
|
|
Operating income
|
|
|
750,703
|
|
|
|
85,155
|
|
|
|
12,380
|
|
|
|
(44,657
|
)
|
|
|
-
|
|
|
|
803,581
|
|
|
|
|
|
Investment in equity affiliates
|
|
|
420,171
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
420,171
|
|
|
|
|
|
Property, plant and equipment net
|
|
|
1,290,728
|
|
|
|
571,496
|
|
|
|
275,807
|
|
|
|
4,315
|
|
|
|
-
|
|
|
|
2,142,346
|
|
|
|
|
|
Property and equipment costs incurred
|
|
|
758,601
|
|
|
|
115,073
|
|
|
|
168,523
|
|
|
|
2,017
|
|
|
|
-
|
|
|
|
1,044,214
|
|
|
|
|
|
95
|
|
22.
|
SUPPLEMENTAL
CASH FLOW INFORMATION
|
Cash paid for interest and income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Interest
|
|
$
|
128,217
|
|
|
$
|
83,400
|
|
|
$
|
69,038
|
|
Income taxes
|
|
|
(41,267
|
)
|
|
|
49,433
|
|
|
|
-
|
|
Other significant non-cash transactions are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Working capital related to capital expenditures
|
|
$
|
118,294
|
|
|
$
|
230,624
|
|
|
$
|
159,819
|
|
Issuance of common stock as consideration for the Alliance
Acquisition
|
|
|
-
|
|
|
|
262,092
|
|
|
|
-
|
|
Noncash acquisition of interest in BBEP earnings
|
|
|
-
|
|
|
|
-
|
|
|
|
429,618
|
|
Tax benefit recognized on employee stock option exercises
|
|
|
-
|
|
|
|
-
|
|
|
|
2,755
|
|
Quicksilver has a 401(k) retirement plan available to all
U.S. full time employees who are at least 21 years of
age. We make matching contributions and a fixed annual
contribution and have the ability to make discretionary
contributions to the plan. Expenses associated with company
contributions were $2.3 million, $2.4 million and
$1.6 million for 2009, 2008 and 2007, respectively.
We have a retirement plan available to all Canadian employees.
The plan provides for a match of employees contributions
by us and a fixed annual contribution. Expenses associated with
company contributions were $0.8 million, $0.8 million
and $0.7 million for the 2009, 2008 and 2007, respectively.
We maintain 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 2009, 2008 and 2007 we recognized expenses of
$4.6 million, $4.4 million and $3.2 million,
respectively, for this plan.
|
|
24.
|
RELATED
PARTY TRANSACTIONS
|
As of December 31, 2009, members of the Darden family and
entities controlled by them beneficially owned approximately 30%
of Quicksilvers outstanding common stock. Thomas Darden,
Glenn Darden and Anne Darden Self are officers and directors of
Quicksilver.
We paid $0.7 million, $1.9 million and
$2.1 million in 2009, 2008 and 2007, respectively, for rent
on buildings owned by entities controlled by members of the
Darden family. Rental rates were determined based on comparable
rates charged by third parties. In October 2008, we completed
the purchase of our headquarters building in Fort Worth,
Texas for $6.4 million, the estimated fair value of the
building, from an entity controlled by members of the Darden
family. Subsequently, we entered into a property management
agreement with an affiliate of the seller to which we paid
$14,000 during the remainder of 2008 and $0.1 million in
2009. Annual lease payments on the purchased building prior to
its acquisition had been $1.1 million.
During 2009, 2008 and 2007, we paid $0.2 million,
$0.9 million and $0.2 million for use of an airplane
owned by an entity controlled by members of the Darden family.
Usage rates were determined based upon comparable rates charged
by third parties.
96
We paid $0.2 million in 2009 and 2007 primarily for delay
rentals under leases for over 5,000 acres held by a related
entity. The lease terms were determined based on comparable
prices and terms granted to third parties with respect to
similar leases in the area. No payments were made in 2008.
Payments received in 2009, 2008 and 2007 from Mercury for
sublease rentals, employee insurance coverage and administrative
services were $0.3 million, $0.3 million and
$0.2 million, respectively.
In October 2008, we paid $19.9 million for the purchase of
1,885,600 shares of our common stock from an entity
controlled by members of the Darden family.
In May 2008, we signed a settlement agreement with Mercury in
which Mercury agreed to make a payment of approximately
$0.4 million in connection with issues related to the
ownership and operation of certain oil and gas properties
acquired from Mercury in 2001, including audit claims received
with respect to certain of the acquired properties and the
administration of employee benefits.
97
SUPPLEMENTAL
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table presents selected quarterly financial data
derived from our consolidated financial
statements. This summary should be read in
conjunction with our consolidated financial statements and
related notes also contained in this Item 8 to our Annual
Report on
Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
|
(In thousands, except per share data)
|
|
|
2009
(1)(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
185,932
|
|
|
$
|
206,041
|
|
|
$
|
206,657
|
|
|
$
|
234,105
|
|
Operating income (loss)
|
|
|
(825,692
|
)
|
|
|
10,573
|
|
|
|
103,703
|
|
|
|
97,543
|
|
Net income (loss)
|
|
|
(567,309
|
)
|
|
|
(20,450
|
)
|
|
|
2,159
|
|
|
|
34,154
|
|
Net income (loss) attributable to Quicksilver
|
|
|
(568,979
|
)
|
|
|
(21,762
|
)
|
|
|
730
|
|
|
|
32,538
|
|
Basic net earnings (loss) per share
|
|
$
|
(3.37
|
)
|
|
$
|
(0.13
|
)
|
|
$
|
-
|
|
|
$
|
0.19
|
|
Diluted net earnings (loss) per share
|
|
|
(3.37
|
)
|
|
|
(0.13
|
)
|
|
|
-
|
|
|
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
157,617
|
|
|
$
|
197,901
|
|
|
$
|
236,262
|
|
|
$
|
208,861
|
|
Operating income (loss)
|
|
|
70,723
|
|
|
|
107,103
|
|
|
|
119,990
|
|
|
|
(547,513
|
)
|
Net income (loss)
|
|
|
41,642
|
|
|
|
52,323
|
|
|
|
(2,630
|
)
|
|
|
(464,957
|
)
|
Net income (loss) attributable to Quicksilver
|
|
|
41,134
|
|
|
|
51,335
|
|
|
|
(3,755
|
)
|
|
|
(466,990
|
)
|
Basic net earnings (loss) per share
|
|
$
|
0.26
|
|
|
$
|
0.32
|
|
|
$
|
(0.02
|
)
|
|
$
|
(2.79
|
)
|
Diluted net earnings (loss) per share
|
|
|
0.25
|
|
|
|
0.31
|
|
|
|
(0.02
|
)
|
|
|
(2.79
|
)
|
|
|
|
(1) |
|
Operating loss for the first quarter of 2009 includes a charge
of $896.5 million for the impairment of our U.S. and
Canadian oil and gas properties. Net loss for the
first quarter of 2009 also includes $102.1 million for
pre-tax income attributable to our proportionate ownership of
BBEP and a pre-tax charge of $102.1 million for impairment
of the related investment, respectively. |
|
(2) |
|
Operating income for the second quarter of 2009 includes a
charge of $70.6 million for the impairment of our Canadian
oil and gas properties. Net loss for the second
quarter of 2009 also includes $19.0 million of pre-tax
income attributable to our proportionate ownership of BBEP. |
|
(3) |
|
Operating income for the fourth quarter of 2009 includes a
charge of $12.4 million for the impairment of our Canadian
oil and gas properties. Net income for the fourth
quarter of 2009 also includes $1.9 million pre-tax loss
attributable to our proportionate ownership of BBEP. |
|
(4) |
|
Operating loss for the fourth quarter of 2008 includes a charge
of $633.5 million for the impairment of our U.S. oil and
gas properties. Net loss for the fourth quarter of
2008 also includes $93.3 million for pre-tax income
attributable to our proportionate ownership of BBEP and a
pre-tax charge of $320.4 million for impairment of the
related investment, respectively. |
98
SUPPLEMENTAL
OIL AND GAS INFORMATION (UNAUDITED)
Proved oil and gas reserves estimates for our properties in the
United States and Canada were prepared by independent petroleum
engineers from Schlumberger Data and Consulting Services and
LaRoche Petroleum Consultants, Ltd.,
respectively. The reserve reports were prepared in
accordance with guidelines established by the
SEC. Natural gas, NGL and oil prices used in the 2009
reserve reports are the unweighted average of the preceding
12-month
first-day-of-the-month
prices as of the date of the reserve reports without any
escalation except in those instances where the sale of
production was covered by contract, in which case the applicable
contract prices, including fixed and determinable escalations,
were used for the duration of the contract, and thereafter the
unweighted
12-month
average price was used. The prices used in the 2008
and 2007 reserve reports used end-of-year prices adjusted for
local differentials and applicable contract prices which
conforms to the SEC requirements then in effect. For
all years, operating costs, production and ad valorem taxes and
future development costs were based on year-end costs with no
escalation.
There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting the future rates
of production and timing of development
expenditures. The following reserve data represents
estimates only and should not be construed as being
exact. Moreover, the present values should not be
construed as the current market value of our natural gas and oil
reserves or the costs that would be incurred to obtain
equivalent reserves.
As required by GAAP, we have also included separate disclosure
and presentation of our share of BBEPs proved reserve
because we account for BBEP by the equity method.
Consolidated
Quicksilver (Excluding BBEP Reserves)
The changes in our proved reserves for the three years ended
December 31, 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf)
|
|
|
NGL (MBbl)
|
|
|
Oil (MBbl)
|
|
|
|
United
|
|
|
|
|
|
|
|
|
United
|
|
|
|
|
|
|
|
|
United
|
|
|
|
|
|
|
|
|
|
States
|
|
|
Canada
|
|
|
Total
|
|
|
States
|
|
|
Canada
|
|
|
Total
|
|
|
States
|
|
|
Canada
|
|
|
Total
|
|
|
December 31, 2006
|
|
|
933,342
|
|
|
|
308,335
|
|
|
|
1,241,677
|
|
|
|
47,985
|
|
|
|
16
|
|
|
|
48,001
|
|
|
|
6,315
|
|
|
|
-
|
|
|
|
6,315
|
|
Revisions
(5)
|
|
|
(30,494
|
)
|
|
|
17,761
|
|
|
|
(12,733
|
)
|
|
|
1,112
|
|
|
|
(1
|
)
|
|
|
1,111
|
|
|
|
633
|
|
|
|
-
|
|
|
|
633
|
|
Extensions and discoveries
(4)
|
|
|
302,098
|
|
|
|
24,463
|
|
|
|
326,561
|
|
|
|
46,571
|
|
|
|
-
|
|
|
|
46,571
|
|
|
|
658
|
|
|
|
-
|
|
|
|
658
|
|
Sales in place
(1)
|
|
|
(503,651
|
)
|
|
|
(1,446
|
)
|
|
|
(505,097
|
)
|
|
|
(3,147
|
)
|
|
|
-
|
|
|
|
(3,147
|
)
|
|
|
(3,947
|
)
|
|
|
-
|
|
|
|
(3,947
|
)
|
Production
|
|
|
(38,887
|
)
|
|
|
(20,732
|
)
|
|
|
(59,619
|
)
|
|
|
(2,466
|
)
|
|
|
(5
|
)
|
|
|
(2,471
|
)
|
|
|
(584
|
)
|
|
|
-
|
|
|
|
(584
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
662,408
|
|
|
|
328,381
|
|
|
|
990,789
|
|
|
|
90,055
|
|
|
|
10
|
|
|
|
90,065
|
|
|
|
3,075
|
|
|
|
-
|
|
|
|
3,075
|
|
Revisions
(5)
|
|
|
(171,009
|
)
|
|
|
4,923
|
|
|
|
(166,086
|
)
|
|
|
(25,596
|
)
|
|
|
-
|
|
|
|
(25,596
|
)
|
|
|
(106
|
)
|
|
|
-
|
|
|
|
(106
|
)
|
Extensions and discoveries
(4)
|
|
|
560,205
|
|
|
|
22,363
|
|
|
|
582,568
|
|
|
|
31,662
|
|
|
|
-
|
|
|
|
31,662
|
|
|
|
428
|
|
|
|
-
|
|
|
|
428
|
|
Purchases in place
(2)
|
|
|
299,952
|
|
|
|
-
|
|
|
|
299,952
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Sales in place
|
|
|
-
|
|
|
|
(27
|
)
|
|
|
(27
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(45,059
|
)
|
|
|
(23,069
|
)
|
|
|
(68,128
|
)
|
|
|
(4,194
|
)
|
|
|
(2
|
)
|
|
|
(4,196
|
)
|
|
|
(483
|
)
|
|
|
-
|
|
|
|
(483
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
1,306,497
|
|
|
|
332,571
|
|
|
|
1,639,068
|
|
|
|
91,927
|
|
|
|
8
|
|
|
|
91,935
|
|
|
|
2,914
|
|
|
|
-
|
|
|
|
2,914
|
|
Revisions
(5)
|
|
|
(28,833
|
)
|
|
|
(67,207
|
)
|
|
|
(96,040
|
)
|
|
|
(4,178
|
)
|
|
|
7
|
|
|
|
(4,171
|
)
|
|
|
205
|
|
|
|
1
|
|
|
|
206
|
|
Extensions and discoveries
(4)
|
|
|
460,214
|
|
|
|
12,153
|
|
|
|
472,367
|
|
|
|
15,487
|
|
|
|
-
|
|
|
|
15,487
|
|
|
|
165
|
|
|
|
-
|
|
|
|
165
|
|
Purchases in place
|
|
|
314
|
|
|
|
-
|
|
|
|
314
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Sales in place
(3)
|
|
|
(120,539
|
)
|
|
|
(44
|
)
|
|
|
(120,583
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(61,619
|
)
|
|
|
(24,420
|
)
|
|
|
(86,039
|
)
|
|
|
(4,975
|
)
|
|
|
(2
|
)
|
|
|
(4,977
|
)
|
|
|
(425
|
)
|
|
|
(1
|
)
|
|
|
(426
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
1,556,034
|
|
|
|
253,053
|
|
|
|
1,809,087
|
|
|
|
98,261
|
|
|
|
13
|
|
|
|
98,274
|
|
|
|
2,859
|
|
|
|
-
|
|
|
|
2,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
379,917
|
|
|
|
260,029
|
|
|
|
639,946
|
|
|
|
50,738
|
|
|
|
10
|
|
|
|
50,748
|
|
|
|
2,763
|
|
|
|
-
|
|
|
|
2,763
|
|
December 31, 2008
|
|
|
756,191
|
|
|
|
278,668
|
|
|
|
1,034,859
|
|
|
|
56,181
|
|
|
|
8
|
|
|
|
56,189
|
|
|
|
2,509
|
|
|
|
-
|
|
|
|
2,509
|
|
December 31, 2009
|
|
|
1,044,140
|
|
|
|
223,300
|
|
|
|
1,267,440
|
|
|
|
60,997
|
|
|
|
13
|
|
|
|
61,010
|
|
|
|
2,467
|
|
|
|
-
|
|
|
|
2,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
282,491
|
|
|
|
68,352
|
|
|
|
350,843
|
|
|
|
39,317
|
|
|
|
-
|
|
|
|
39,317
|
|
|
|
312
|
|
|
|
-
|
|
|
|
312
|
|
December 31, 2008
|
|
|
550,306
|
|
|
|
53,903
|
|
|
|
604,209
|
|
|
|
35,746
|
|
|
|
-
|
|
|
|
35,746
|
|
|
|
405
|
|
|
|
-
|
|
|
|
405
|
|
December 31, 2009
|
|
|
511,894
|
|
|
|
29,753
|
|
|
|
541,647
|
|
|
|
37,264
|
|
|
|
-
|
|
|
|
37,264
|
|
|
|
392
|
|
|
|
-
|
|
|
|
392
|
|
99
|
|
|
(1) |
|
Sales of reserves in place during 2007 relate principally to the
BreitBurn Transaction, which is more fully described in
Note 5 to our consolidated financial statements. |
|
(2) |
|
Purchases of reserves in place during 2008 relate principally to
the Alliance Transaction, which is more fully described in
Note 4 to our consolidated financial statements. |
|
(3) |
|
Sales of reserves in place during 2009 relate principally to the
Eni Transaction, which is more fully described in Note 3 to
our consolidated financial statements. |
|
(4) |
|
Extensions and discoveries for each period presented represent
extensions to reserves attributable to additional drilling
activity subsequent to discovery. U.S. extensions and
discoveries for: |
|
|
|
|
|
2009 are 99% attributable to the Barnett Shale (of which 42%
were proved developed);
|
|
|
|
2008 are 100% attributable to the Barnett Shale (of which 49%
were proved developed); and
|
|
|
|
2007 are 96% attributable to the Barnett Shale (of which 49%
were proved developed) and 4% were attributable to the Northeast
Operations (which were all derecognized pursuant to the
BreitBurn Transaction).
|
Canadian extensions and discoveries for 2009 are 47%
attributable to the properties in Alberta and 53% are
attributable the Horn River Basin properties in British
Columbia. All Canadian extensions and discoveries for
2008 and 2007 are attributable to the gas projects in Alberta.
|
|
|
(5)
|
|
Revisions for each period presented reflect upward (downward)
changes in previous estimates attributable to new information
gained primarily from development drilling activity and
production history. Revisions include
132,846 MMcfe, (166,198) MMcfe and (55,584) MMcfd for such
matters in 2009, 2008 and 2007,
respectively. Revisions also include changes in
previous estimates due to changes in sales
price. Revisions include (251,676) MMcfe, (154,100)
MMcfe, and 53,315 MMcfe for such sales price changes in
2009, 2008 and 2007. |
The carrying value of our consolidated oil and gas assets as of
December 31, 2009, 2008 and 2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
3,218,796
|
|
|
$
|
728,880
|
|
|
$
|
3,947,676
|
|
Unevaluated properties
|
|
|
340,707
|
|
|
|
117,330
|
|
|
|
458,037
|
|
Accumulated DD&A
|
|
|
(1,670,923
|
)
|
|
|
(396,546
|
)
|
|
|
(2,067,469
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
1,888,580
|
|
|
$
|
449,664
|
|
|
$
|
2,338,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
3,068,326
|
|
|
$
|
553,505
|
|
|
$
|
3,621,831
|
|
Unevaluated properties
|
|
|
462,943
|
|
|
|
80,590
|
|
|
|
543,533
|
|
Accumulated DD&A
|
|
|
(902,281
|
)
|
|
|
(120,475
|
)
|
|
|
(1,022,756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
2,628,988
|
|
|
$
|
513,620
|
|
|
$
|
3,142,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
1,231,109
|
|
|
$
|
580,186
|
|
|
$
|
1,811,295
|
|
Unevaluated properties
|
|
|
163,274
|
|
|
|
51,954
|
|
|
|
215,228
|
|
Accumulated DD&A
|
|
|
(157,122
|
)
|
|
|
(105,001
|
)
|
|
|
(262,123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
1,237,261
|
|
|
$
|
527,139
|
|
|
$
|
1,764,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
Our consolidated capital costs incurred for acquisition,
exploration and development activities during each of the three
years ended December 31, 2009, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved acreage
|
|
$
|
118
|
|
|
$
|
-
|
|
|
$
|
118
|
|
Unproved acreage
|
|
|
11,300
|
|
|
|
2,658
|
|
|
|
13,958
|
|
Development costs
|
|
|
341,658
|
|
|
|
24,179
|
|
|
|
365,837
|
|
Exploration costs
|
|
|
32,798
|
|
|
|
59,402
|
|
|
|
92,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
385,874
|
|
|
$
|
86,239
|
|
|
$
|
472,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved acreage
|
|
$
|
787,172
|
|
|
$
|
-
|
|
|
$
|
787,172
|
|
Unproved acreage
|
|
|
484,770
|
|
|
|
54,048
|
|
|
|
538,818
|
|
Development costs
|
|
|
836,032
|
|
|
|
68,629
|
|
|
|
904,661
|
|
Exploration costs
|
|
|
30,161
|
|
|
|
10,280
|
|
|
|
40,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,138,135
|
|
|
$
|
132,957
|
|
|
$
|
2,271,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved acreage
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Unproved acreage
|
|
|
17,031
|
|
|
|
31,448
|
|
|
|
48,479
|
|
Development costs
|
|
|
648,632
|
|
|
|
67,608
|
|
|
|
716,240
|
|
Exploration costs
|
|
|
75,862
|
|
|
|
11,953
|
|
|
|
87,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
741,525
|
|
|
$
|
111,009
|
|
|
$
|
852,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101
Consolidated results of operations from our producing activities
for the three years ended December 31, 2009, are set forth
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil revenue
|
|
$
|
608,013
|
|
|
$
|
188,685
|
|
|
$
|
796,698
|
|
Oil & gas production expense
|
|
|
112,935
|
|
|
|
38,661
|
|
|
|
151,596
|
|
Depletion & amortization expense
|
|
|
127,888
|
|
|
|
33,783
|
|
|
|
161,671
|
|
Impairment related to oil and gas properties
|
|
|
786,867
|
|
|
|
192,673
|
|
|
|
979,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(419,677
|
)
|
|
|
(76,432
|
)
|
|
|
(496,109
|
)
|
Income tax expense (benefit)
|
|
|
(146,887
|
)
|
|
|
(22,165
|
)
|
|
|
(169,052
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results from producing activities
|
|
$
|
(272,790
|
)
|
|
$
|
(54,267
|
)
|
|
$
|
(327,057
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil revenue
|
|
$
|
597,889
|
|
|
$
|
182,899
|
|
|
$
|
780,788
|
|
Oil & gas production expense
|
|
|
114,374
|
|
|
|
38,662
|
|
|
|
153,036
|
|
Depletion & amortization expense
|
|
|
120,845
|
|
|
|
40,337
|
|
|
|
161,182
|
|
Impairment related to oil and gas properties
|
|
|
624,315
|
|
|
|
|
|
|
|
624,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(261,645
|
)
|
|
|
103,900
|
|
|
|
3,437
|
|
Income tax expense (benefit)
|
|
|
(91,576
|
)
|
|
|
30,131
|
|
|
|
(61,445
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results from producing activities
|
|
$
|
(170,069
|
)
|
|
$
|
73,769
|
|
|
$
|
64,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil revenue
|
|
$
|
392,841
|
|
|
$
|
152,248
|
|
|
$
|
545,089
|
|
Oil & gas production expense
|
|
|
119,630
|
|
|
|
33,521
|
|
|
|
153,151
|
|
Depletion & amortization expense
|
|
|
65,701
|
|
|
|
35,330
|
|
|
|
101,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
207,510
|
|
|
|
83,397
|
|
|
|
290,907
|
|
Income tax expense
|
|
|
72,629
|
|
|
|
24,185
|
|
|
|
96,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results from producing activities
|
|
$
|
134,881
|
|
|
$
|
59,212
|
|
|
$
|
194,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
(Standardized Measure) do not purport to present the
fair market value of the our natural gas and oil
properties. An estimate of such value should
consider, among other factors, anticipated future prices of
natural gas and oil, the probability of recoveries in excess of
existing proved reserves, the value of probable reserves and
acreage prospects, estimated future capital and operating costs
and perhaps different discount rates. It should be
noted that estimates of reserve quantities, especially from new
discoveries, are inherently imprecise and subject to substantial
revision.
Under the Standardized Measure, future cash inflows for 2009
were estimated by applying the unweighted average of the
preceding
12-month
first-day-of-the-month
prices, adjusted for contracts with price floors but excluding
hedges, and unescalated year-end costs to the estimated future
production of the year-end reserves. These prices
have varied widely and have a significant impact on both the
quantities and value of the proved reserves as reduced prices
cause wells to reach the end of their economic life much sooner
and also make certain proved undeveloped locations uneconomical,
both of which reduce reserves. The following
102
representative prices were used in the Standardized Measure and
were adjusted by field for appropriate regional differentials:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2009
|
|
|
2008
(1)
|
|
|
2007
(1)
|
|
|
Natural gas Henry Hub
|
|
$
|
3.87
|
|
|
$
|
5.71
|
|
|
$
|
6.80
|
|
Natural gas AECO
|
|
|
3.76
|
|
|
|
5.44
|
|
|
|
6.35
|
|
NGL Mont Belvieu, Texas
|
|
|
24.94
|
|
|
|
21.65
|
|
|
|
57.35
|
|
Oil WTI Cushing
|
|
|
61.18
|
|
|
|
44.60
|
|
|
|
95.98
|
|
|
|
|
(1) |
|
The prices used for all 2008 and 2007 proved reserve estimates
were year-end spot prices, which were previously required by
guidance from the SEC and FASB then in
effect. Additional information regarding the change
during 2009 for reserve recognition guidance is included in
Note 2 to our consolidated financial statements. |
Future cash inflows were reduced by estimated future production
and development costs based on year-end costs to determine
pre-tax cash inflows. Future income taxes were
computed by applying the statutory tax rate to the excess of
pre-tax cash inflows over our tax basis in the associated proved
natural gas and oil properties. Tax credits and net
operating loss carry forwards were also considered in the future
income tax calculation. Future net cash inflows after
income taxes were discounted using a 10% annual discount rate to
arrive at the Standardized Measure.
The standardized measure of discounted cash flows related to
proved oil and gas reserves at December 31, 2009, 2008 and
2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Future revenues
|
|
$
|
7,787,422
|
|
|
$
|
916,765
|
|
|
$
|
8,704,187
|
|
Future production costs
|
|
|
(4,169,783
|
)
|
|
|
(403,874
|
)
|
|
|
(4,573,657
|
)
|
Future development costs
|
|
|
(938,675
|
)
|
|
|
(93,588
|
)
|
|
|
(1,032,263
|
)
|
Future income taxes
|
|
|
(222,576
|
)
|
|
|
(47,125
|
)
|
|
|
(269,701
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
2,456,388
|
|
|
|
372,178
|
|
|
|
2,828,566
|
|
10% discount
|
|
|
(1,492,469
|
)
|
|
|
(153,418
|
)
|
|
|
(1,645,887
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows relating to
proved reserves
|
|
$
|
963,919
|
|
|
$
|
218,760
|
|
|
$
|
1,182,679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Future revenues
|
|
$
|
8,783,936
|
|
|
$
|
1,764,268
|
|
|
$
|
10,548,204
|
|
Future production costs
|
|
|
(4,162,737
|
)
|
|
|
(551,395
|
)
|
|
|
(4,714,132
|
)
|
Future development costs
|
|
|
(1,140,466
|
)
|
|
|
(113,800
|
)
|
|
|
(1,254,266
|
)
|
Future income taxes
|
|
|
(504,753
|
)
|
|
|
(215,212
|
)
|
|
|
(719,965
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
2,975,980
|
|
|
|
883,861
|
|
|
|
3,859,841
|
|
10% discount
|
|
|
(1,623,862
|
)
|
|
|
(441,717
|
)
|
|
|
(2,065,579
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows relating to
proved reserves
|
|
$
|
1,352,118
|
|
|
$
|
442,144
|
|
|
$
|
1,794,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
Canada
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Future revenues
|
|
$
|
9,566,791
|
|
|
$
|
2,037,478
|
|
|
$
|
11,604,269
|
|
Future production costs
|
|
|
(3,286,618
|
)
|
|
|
(675,890
|
)
|
|
|
(3,962,508
|
)
|
Future development costs
|
|
|
(651,802
|
)
|
|
|
(156,289
|
)
|
|
|
(808,091
|
)
|
Future income taxes
|
|
|
(1,772,021
|
)
|
|
|
(228,883
|
)
|
|
|
(2,000,904
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
3,856,350
|
|
|
|
976,416
|
|
|
|
4,832,765
|
|
10% discount
|
|
|
(2,168,150
|
)
|
|
|
(495,413
|
)
|
|
|
(2,663,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows relating to
proved reserves
|
|
$
|
1,688,200
|
|
|
$
|
481,003
|
|
|
$
|
2,169,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The primary changes in the standardized measure of discounted
future net cash flows for the three years ended
December 31, 2009, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Sales of oil and gas net of production costs
|
|
$
|
(645,102
|
)
|
|
$
|
(628,333
|
)
|
|
$
|
(392,116
|
)
|
Net changes in price and production cost
|
|
|
(715,484
|
)
|
|
|
(2,368,940
|
)
|
|
|
1,048,432
|
|
Extensions and discoveries
|
|
|
561,544
|
|
|
|
1,630,418
|
|
|
|
1,045,296
|
|
Development costs incurred
|
|
|
205,781
|
|
|
|
373,124
|
|
|
|
170,686
|
|
Changes in estimated future development costs
|
|
|
81,754
|
|
|
|
(413,097
|
)
|
|
|
(234,649
|
)
|
Purchase and sale of reserves, net
|
|
|
(144,279
|
)
|
|
|
722,662
|
|
|
|
(1,010,263
|
)
|
Revision of estimates
|
|
|
(248,681
|
)
|
|
|
(618,527
|
)
|
|
|
(8,090
|
)
|
Accretion of discount
|
|
|
192,325
|
|
|
|
324,064
|
|
|
|
196,275
|
|
Net change in income taxes
|
|
|
196,691
|
|
|
|
509,854
|
|
|
|
(293,374
|
)
|
Timing and other differences
|
|
|
(96,132
|
)
|
|
|
93,834
|
|
|
|
161,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease)
|
|
$
|
(611,583
|
)
|
|
$
|
(374,941
|
)
|
|
$
|
683,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104
Quicksilver
Share of BBEP Reserves
The following disclosures required under GAAP represent
Quicksilvers share of BBEPs reserves and BBEPs
oil and gas operations, which are all located in the U.S.
Notes 5 and 9 in our consolidated financial statements
contain additional information regarding our relationship with
BBEP. In addition, this Annual Report contains
BBEPs financial statements, which are in Item 15 and
have been included pursuant to SEC
Rule 3-09.
The changes in our share of BBEPs oil and gas reserves
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Total
|
|
|
Gas
|
|
|
Oil
|
|
|
Total
|
|
|
Gas
|
|
|
Oil
|
|
|
Total
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(Mboe)
|
|
|
(MMcf)
|
|
|
(MBbl)
|
|
|
(Mboe)
|
|
|
(MMcf)
|
|
|
(MBbl)
|
|
|
(Mboe)
|
|
|
(MMcf)
|
|
|
(MBbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
|
42,038
|
|
|
|
189,176
|
|
|
|
9,471
|
|
|
|
45,314
|
|
|
|
160,864
|
|
|
|
17,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous estimates
|
|
|
6,191
|
|
|
|
(4,203
|
)
|
|
|
6,891
|
|
|
|
(12,903
|
)
|
|
|
(6,591
|
)
|
|
|
(11,805
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
|
|
|
|
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of reserves in place
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,389
|
|
|
|
43,982
|
|
|
|
5,060
|
|
|
|
46,238
|
|
|
|
162,181
|
|
|
|
18,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of reserves in place
(1)
|
|
|
(566
|
)
|
|
|
(543
|
)
|
|
|
(476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(2,636
|
)
|
|
|
(8,561
|
)
|
|
|
(1,209
|
)
|
|
|
(2,762
|
)
|
|
|
(9,079
|
)
|
|
|
(1,249
|
)
|
|
|
(962
|
)
|
|
|
(1,317
|
)
|
|
|
(742
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
45,027
|
|
|
|
175,869
|
|
|
|
14,677
|
|
|
|
42,038
|
|
|
|
189,176
|
|
|
|
9,471
|
|
|
|
45,314
|
|
|
|
160,864
|
|
|
|
17,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
|
38,791
|
|
|
|
175,933
|
|
|
|
9,469
|
|
|
|
40,877
|
|
|
|
145,696
|
|
|
|
16,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
40,846
|
|
|
|
161,491
|
|
|
|
13,931
|
|
|
|
38,791
|
|
|
|
175,933
|
|
|
|
9,469
|
|
|
|
40,877
|
|
|
|
145,696
|
|
|
|
16,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
|
3,247
|
|
|
|
13,244
|
|
|
|
1,040
|
|
|
|
4,437
|
|
|
|
15,169
|
|
|
|
1,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
4,180
|
|
|
|
14,378
|
|
|
|
1,784
|
|
|
|
3,247
|
|
|
|
13,244
|
|
|
|
1,040
|
|
|
|
4,437
|
|
|
|
15,169
|
|
|
|
1,908
|
|
The following representative prices were used in BBEPs
Standardized Measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
(2)
|
|
|
2008
(3)
|
|
|
2007
(3)
|
|
|
Representative prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas Henry Hub
|
|
$
|
3.87
|
|
|
$
|
5.71
|
|
|
$
|
6.80
|
|
Oil WTI Cushing
|
|
|
61.18
|
|
|
|
44.60
|
|
|
|
95.95
|
|
|
|
|
(1) |
|
Amounts are included as needed to reconcile Quicksilvers
portion of beginning reserves to ending reserves that result
from changes in Quicksilvers proportionate ownership of
BBEP. |
|
(2) |
|
Prices used for 2009 proved reserve estimates were the
unweighted average of the preceding
12-month
first-day-of-the-month
prices. |
|
(3) |
|
The prices used for all 2008 and 2007 proved reserve estimates
were year-end spot prices, which were previously required by
guidance from the SEC and FASB then in effect. |
The following table summarizes the carrying value of our portion
of BBEPs consolidated oil and gas assets as of
December 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Proved properties and related producing assets
|
|
$
|
698,541
|
|
|
$
|
703,654
|
|
Pipeline and processing facilities
|
|
|
55,243
|
|
|
|
45,719
|
|
Unproved properties
|
|
|
79,166
|
|
|
|
85,120
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(130,204
|
)
|
|
|
(90,678
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
702,747
|
|
|
$
|
743,815
|
|
|
|
|
|
|
|
|
|
|
105
The following table summarizes our share of the capital costs
incurred by BBEP during the three years ended December 31,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Proved properties
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
457,726
|
|
Unproved properties
|
|
|
-
|
|
|
|
-
|
|
|
|
67,950
|
|
Development costs
|
|
|
11,598
|
|
|
|
52,524
|
|
|
|
8,586
|
|
Asset retirement costs
|
|
|
1,975
|
|
|
|
553
|
|
|
|
1,141
|
|
Pipelines and processing facilities
|
|
|
-
|
|
|
|
-
|
|
|
|
15,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
13,573
|
|
|
$
|
53,077
|
|
|
$
|
550,949
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes our share of BBEPs results
of operations from its producing activities for the three years
ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Oil, natural gas and NGL sales
|
|
$
|
103,126
|
|
|
$
|
189,560
|
|
|
$
|
58,722
|
|
Realized gain (loss) on derivative instruments
|
|
|
67,836
|
|
|
|
(22,691
|
)
|
|
|
(2,088
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
(88,644
|
)
|
|
|
157,385
|
|
|
|
(33,080
|
)
|
Operating costs
|
|
|
(56,029
|
)
|
|
|
(65,706
|
)
|
|
|
(23,565
|
)
|
Depreciation, depletion & amortization
|
|
|
(42,194
|
)
|
|
|
(72,460
|
)
|
|
|
(9,325
|
)
|
Income tax (expense) benefit
|
|
|
618
|
|
|
|
(786
|
)
|
|
|
391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results from producing activities
|
|
$
|
(15,287
|
)
|
|
$
|
185,302
|
|
|
$
|
(8,945
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes our share of BBEPs
standardized measure of discounted cash flows related to its
proved oil and gas reserves at December 31, 2009, 2008 and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Future revenues
|
|
$
|
1,552,493
|
|
|
$
|
1,429,072
|
|
|
$
|
2,597,342
|
|
Future development costs
|
|
|
(79,983
|
)
|
|
|
(86,369
|
)
|
|
|
(118,034
|
)
|
Future production costs
|
|
|
(850,917
|
)
|
|
|
(747,884
|
)
|
|
|
(1,070,304
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
621,593
|
|
|
|
594,819
|
|
|
|
1,409,004
|
|
10% discount
|
|
|
(314,290
|
)
|
|
|
(354,610
|
)
|
|
|
(799,884
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows relating to
proved reserves
|
|
$
|
307,303
|
|
|
$
|
240,209
|
|
|
$
|
609,120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106
The following table summarizes our share of the primary changes
in BBEPs standardized measure of discounted future net
cash flows for the three years ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Beginning balance
|
|
$
|
240,209
|
|
|
$
|
609,120
|
|
|
$
|
-
|
|
Sales, net of production costs
|
|
|
(47,097
|
)
|
|
|
(128,854
|
)
|
|
|
(35,157
|
)
|
Net changes in sales and transfer prices, net of production
expense
|
|
|
88,093
|
|
|
|
(529,993
|
)
|
|
|
77,515
|
|
Previously estimated development costs incurred
|
|
|
11,748
|
|
|
|
23,400
|
|
|
|
4,921
|
|
Changes in estimated future development costs
|
|
|
(14,969
|
)
|
|
|
(39,773
|
)
|
|
|
(7,225
|
)
|
Extensions, discoveries and improved recovery, net of costs
|
|
|
-
|
|
|
|
-
|
|
|
|
829
|
|
Purchase of reserves in
place(1)
|
|
|
-
|
|
|
|
166,538
|
|
|
|
541,014
|
|
Sale of reserves in
place(1)
|
|
|
(2,231
|
)
|
|
|
-
|
|
|
|
-
|
|
Revision of quantity estimates and timing of production
|
|
|
7,590
|
|
|
|
57,205
|
|
|
|
17,270
|
|
Accretion of discount
|
|
|
23,960
|
|
|
|
77,566
|
|
|
|
9,953
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
307,303
|
|
|
$
|
240,209
|
|
|
$
|
609,120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts are included as needed to reconcile Quicksilvers
portion of beginning value to ending value that result from
changes in Quicksilvers proportionate ownership of BBEP. |
107
|
|
ITEM 9.
|
Changes
in and Disagreements with Accountants or Accounting and
Financial Disclosure
|
None.
|
|
ITEM 9A.
|
Controls
and Procedures
|
Disclosure
Controls and Procedures
Disclosure controls and procedures, as defined in SEC
literature, are controls and other procedures that are designed
to ensure that the information that we are required to disclose
in the reports that we file or submit to the SEC is recorded,
processed, summarized and reported within the time periods
specified in the SECs rules and forms, and that such
information is accumulated and communicated to our management,
including our Chief Executive Officer and Chief Financial
Officer, to allow timely decisions regarding required disclosure.
In connection with the preparation of this Annual Report on
Form 10-K,
our management, under the supervision and with the participation
of our Chief Executive Officer and our Chief Financial Officer,
carried out an evaluation of the effectiveness of the design and
operation of our disclosure controls and procedures as of
December 31, 2009.
Based on this evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and
procedures were effective at the reasonable assurance level as
of December 31, 2009.
Managements
Report on Internal Control Over Financial Reporting
Our management, under the supervision and with the participation
of our Chief Executive Officer and Chief Financial Officer, is
responsible for establishing and maintaining adequate internal
control over financial reporting as such term is defined in
Rules 13a-15(f)
under the Exchange Act. Because of its inherent
limitations, internal control over financial reporting may not
prevent or detect all misstatements. Also,
projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of
compliance with existing policies or procedures may deteriorate.
Under the supervision and with the participation of our Chief
Executive Officer and Chief Financial Officer, our management
conducted an assessment of our internal control over financial
reporting as of December 31, 2009, based on the criteria
established in Internal Control Integrated
Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission
(COSO). Based on this assessment, our
management has concluded that, as of December 31, 2009, our
internal control over financial reporting was effective.
The effectiveness of our internal control over financial
reporting as of December 31, 2009, has been audited by
Deloitte & Touche LLP, our independent registered
public accounting firm, and they have issued an attestation
report expressing an unqualified opinion on the effectiveness of
our internal control over financial reports, as stated in their
report included herein.
Changes
in Internal Control Over Financial Reporting
There has been no change in our internal control over financial
reporting during the quarter ended December 31, 2009, that
materially affected, or is reasonably likely to affect, our
internal control over financial reporting.
108
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 internal control over financial reporting of
Quicksilver Resources Inc. and subsidiaries (the
Company) as of December 31, 2009, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The
Companys management is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting, included in the accompanying
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an
opinion on the Companys internal control over financial
reporting based on our audit.
We conducted our audit 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
effective internal control over financial reporting was
maintained in all material respects. Our audit
included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary
in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed by, or under the supervision of, the
companys principal executive and principal financial
officers, or persons performing similar functions, and effected
by the companys board of directors, management, and other
personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A
companys internal control over financial reporting
includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance
with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or
disposition of the companys assets that could have a
material effect on the financial statements.
Because of the inherent limitations of internal control over
financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a
timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial
reporting to future periods are subject to the risk that the
controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures
may deteriorate.
In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2009, based on the criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated financial statements as of and for the year ended
December 31, 2009 of the Company and our report dated March
15, 2010 an unqualified opinion on those financial statements.
/s/
Deloitte & Touche LLP
Fort Worth, Texas
March 15, 2010
109
|
|
ITEM 9B.
|
Other
Information
|
None.
PART III
|
|
ITEM 10.
|
Directors,
Executive Officers and Corporate Governance
|
The information concerning our directors set forth under
Corporate Governance Matters in the proxy statement
for our May 19, 2010 annual meeting of stockholders
(2010 Proxy Statement) is incorporated herein by
reference. The information concerning any changes to
the procedure by which a security holder may recommend nominees
to the board of directors set forth under Corporate
Governance Matters - Committees of the Board in the
2010 Proxy Statement is incorporated herein by
reference. Certain information concerning our
executive officers is set forth under the heading
Business - Executive Officers of the Registrant
in Item 1 of this Annual Report. The information
concerning compliance with Section 16(a) of the Exchange
Act set forth under Section 16(a) Beneficial
Ownership Reporting Compliance in the 2010 Proxy Statement
is incorporated herein by reference.
The information concerning our audit committee set forth under
Corporate Governance Matters - Committees of the
Board in the 2010 Proxy Statement is incorporated herein
by reference.
The information regarding our Code of Ethics set forth under
Corporate Governance Matters - Corporate Governance
Principles, Processes and Code of Business Conduct and
Ethics in the 2010 Proxy Statement is incorporated herein
by reference.
|
|
ITEM 11.
|
Executive
Compensation
|
The information set forth under Executive
Compensation, Corporate Governance Matters -
Director Compensation for 2009 and Certain
Relationships and Related Transactions in our 2010 Proxy
Statement is incorporated herein by reference.
|
|
ITEM 12.
|
Security
Ownership of Management and Certain Beneficial Owners and
Management and Related Stockholder Matters
|
The information set forth under Security Ownership of
Management and Certain Beneficial Holders in the 2010
Proxy Statement for is incorporated herein by
reference. The information regarding our equity plans
under which shares of our common stock are authorized for
issuance as set forth under Equity Compensation Plan
Information in the 2010 Proxy Statement is incorporated
herein by reference.
|
|
ITEM 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The information set forth under Certain Relationships and
Related Transactions in the 2010 Proxy Statement is
incorporated herein by reference.
Information regarding our directors independence set forth
under Corporate Governance Matters - Independent
Directors in the 2010 Proxy Statement is incorporated
herein by reference.
|
|
ITEM 14.
|
Principal
Accountant Fees and Services
|
The information set forth under Independent Registered
Public Accountants in the 2010 Proxy Statement is
incorporated herein by reference.
110
PART IV
ITEM 15.
The following are filed as part of this Annual Report:
Financial
Statements
See the index to the consolidated financial statements and
related footnotes and other supplemental information included in
Item 8 of this Annual Report, which identifies the
financial statements filed herewith.
Financial
Statement Schedules
The audited financial statements and related footnotes of BBEP,
Quicksilvers equity method investment, are being filed in
accordance with SEC
Rule 3-09
of
Regulation S-X.
We acquired our BBEP units in a sale transaction during the
4th quarter of 2007 and there were no earnings recognized
related to BBEP during any part of 2007 because we recognize our
equity earnings in BBEP utilizing a one quarter lag, as
disclosed in Note 2 of our consolidated financial
statements found in Item 8 of this Annual Report. Based
upon the absence of any equity method earnings related to the
BBEP investment during 2007, we determined that presentation of
BBEPs 2007 financial statements was not required in the
Annual Report for the year ended December 31, 2008.
However, we are voluntarily providing BBEPs financials for
2007 in this Annual Report.
The management of BBEP is solely responsible for the form and
content of the BBEP financial statements. Quicksilver has no
responsibility for the form or content of the BBEP financial
statements since it does not control BBEP and is not involved in
the management of BBEP. In addition, the consents of
Schlumberger Data and Consulting Services, Netherland,
Sewell & Associates, Inc. and PricewaterhouseCoopers
LLP are filed as exhibits under Item 15 of this Annual
Report.
All other schedules are omitted from this item because the
information is inapplicable or is presented in the consolidated
financial statements and related notes in Item 8 of this
Annual Report.
111
Report of
Independent Registered Public Accounting Firm
To the Board of Directors of BreitBurn GP, LLC and
Unitholders of BreitBurn Energy Partners L.P.
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of operations,
partners equity and cash flows present fairly, in all
material respects, the financial position of BreitBurn Energy
Partners L.P. and its subsidiaries (the Partnership)
at December 31, 2009 and 2008, and the results of their
operations and their cash flows for the three years in the
period ended December 31, 2009, in conformity with
accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of
the Partnerships management. Our responsibility is to
express an opinion on these financial statements based on our
audits. We conducted our audits of these statements 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, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 16 to the consolidated financial
statements, the Partnership changed the manner in which it
accounts for recurring fair value measurements of financial
instruments in 2008.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
March 11, 2010
112
BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of dollars, except
per unit amounts
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenues and other income items:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquid sales
|
|
$
|
254,917
|
|
|
$
|
467,381
|
|
|
$
|
184,372
|
|
Gains (losses) on commodity derivative instruments, net
(note 16)
|
|
|
(51,437
|
)
|
|
|
332,102
|
|
|
|
(110,418
|
)
|
Other revenue, net (note 11)
|
|
|
1,382
|
|
|
|
2,920
|
|
|
|
1,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and other income items
|
|
|
204,862
|
|
|
|
802,403
|
|
|
|
74,991
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
|
|
138,498
|
|
|
|
162,005
|
|
|
|
73,989
|
|
Depletion, depreciation and amortization (note 6)
|
|
|
106,843
|
|
|
|
179,933
|
|
|
|
29,422
|
|
General and administrative expenses
|
|
|
36,367
|
|
|
|
31,111
|
|
|
|
26,928
|
|
Loss on sale of assets
|
|
|
5,965
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
287,673
|
|
|
|
373,049
|
|
|
|
130,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(82,811
|
)
|
|
|
429,354
|
|
|
|
(55,348
|
)
|
Interest and other financing costs, net
|
|
|
18,827
|
|
|
|
29,147
|
|
|
|
6,258
|
|
Loss on interest rate swaps (note 16)
|
|
|
7,246
|
|
|
|
20,035
|
|
|
|
-
|
|
Other income, net
|
|
|
(99
|
)
|
|
|
(191
|
)
|
|
|
(111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before taxes
|
|
|
(108,785
|
)
|
|
|
380,363
|
|
|
|
(61,495
|
)
|
Income tax expense (benefit) (note 7)
|
|
|
(1,528
|
)
|
|
|
1,939
|
|
|
|
(1,229
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(107,257
|
)
|
|
|
378,424
|
|
|
|
(60,266
|
)
|
Less: Net income attributable to noncontrolling interest
|
|
|
(33
|
)
|
|
|
(188
|
)
|
|
|
(91
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to the partnership
|
|
|
(107,290
|
)
|
|
|
378,236
|
|
|
|
(60,357
|
)
|
General Partners interest in net loss
|
|
|
-
|
|
|
|
(2,019
|
)
|
|
|
(672
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to limited partners
|
|
$
|
(107,290
|
)
|
|
$
|
380,255
|
|
|
$
|
(59,685
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per unit (note 14)
|
|
$
|
(2.03
|
)
|
|
$
|
6.29
|
|
|
$
|
(1.83
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income (loss) per unit (note 14)
|
|
$
|
(2.03
|
)
|
|
$
|
6.28
|
|
|
$
|
(1.83
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
113
BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
5,766
|
|
|
$
|
2,546
|
|
Accounts and other receivables, net (note 2)
|
|
|
65,209
|
|
|
|
47,221
|
|
Derivative instruments (note 16)
|
|
|
57,133
|
|
|
|
76,224
|
|
Related party receivables (note 8)
|
|
|
2,127
|
|
|
|
5,084
|
|
Inventory (note 9)
|
|
|
5,823
|
|
|
|
1,250
|
|
Prepaid expenses
|
|
|
5,888
|
|
|
|
5,300
|
|
Intangibles (note 10)
|
|
|
495
|
|
|
|
2,771
|
|
Other current assets
|
|
|
-
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
142,441
|
|
|
|
140,566
|
|
Equity investments (note 11)
|
|
|
8,150
|
|
|
|
9,452
|
|
Property, plant and equipment
|
|
|
|
|
|
|
|
|
Oil and gas properties (note 4)
|
|
|
2,058,968
|
|
|
|
2,057,531
|
|
Non-oil and gas assets (note 4)
|
|
|
7,717
|
|
|
|
7,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,066,685
|
|
|
|
2,065,337
|
|
Accumulated depletion and depreciation (note 6)
|
|
|
(325,596
|
)
|
|
|
(224,996
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
1,741,089
|
|
|
|
1,840,341
|
|
Other long-term assets
|
|
|
|
|
|
|
|
|
Intangibles (note 10)
|
|
|
-
|
|
|
|
495
|
|
Derivative instruments (note 16)
|
|
|
74,759
|
|
|
|
219,003
|
|
Other long-term assets
|
|
|
4,590
|
|
|
|
6,977
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,971,029
|
|
|
$
|
2,216,834
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
21,314
|
|
|
$
|
28,302
|
|
Book overdraft
|
|
|
-
|
|
|
|
9,871
|
|
Derivative instruments (note 16)
|
|
|
20,057
|
|
|
|
10,192
|
|
Related party payables (note 8)
|
|
|
13,000
|
|
|
|
-
|
|
Revenue and royalties payable
|
|
|
18,224
|
|
|
|
20,084
|
|
Salaries and wages payable
|
|
|
10,244
|
|
|
|
6,249
|
|
Accrued liabilities
|
|
|
9,051
|
|
|
|
5,292
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
91,890
|
|
|
|
79,990
|
|
Long-term debt (note 12)
|
|
|
559,000
|
|
|
|
736,000
|
|
Deferred income taxes (note 7)
|
|
|
2,492
|
|
|
|
4,282
|
|
Asset retirement obligation (note 13)
|
|
|
36,635
|
|
|
|
30,086
|
|
Derivative instruments (note 16)
|
|
|
50,109
|
|
|
|
10,058
|
|
Other long-term liabilities
|
|
|
2,102
|
|
|
|
2,987
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
742,228
|
|
|
|
863,403
|
|
Equity:
|
|
|
|
|
|
|
|
|
Partners equity (note 14)
|
|
|
1,228,373
|
|
|
|
1,352,892
|
|
Noncontrolling interest (note 15)
|
|
|
428
|
|
|
|
539
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
1,228,801
|
|
|
|
1,353,431
|
|
Total liabilities and equity
|
|
$
|
1,971,029
|
|
|
$
|
2,216,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partner units outstanding
|
|
|
52,784
|
|
|
|
52,636
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
114
BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(107,257
|
)
|
|
$
|
378,424
|
|
|
$
|
(60,266
|
)
|
Adjustments to reconcile net income (loss) to cash flow from
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
106,843
|
|
|
|
179,933
|
|
|
|
29,422
|
|
Unit-based compensation expense
|
|
|
12,661
|
|
|
|
6,907
|
|
|
|
12,999
|
|
Unrealized (gain) loss on derivative instruments
|
|
|
213,251
|
|
|
|
(370,734
|
)
|
|
|
103,862
|
|
Distributions greater (less) than income from equity affiliates
|
|
|
1,302
|
|
|
|
1,198
|
|
|
|
(28
|
)
|
Deferred income tax
|
|
|
(1,790
|
)
|
|
|
1,207
|
|
|
|
(1,229
|
)
|
Amortization of intangibles
|
|
|
2,771
|
|
|
|
3,131
|
|
|
|
2,174
|
|
Loss on sale of assets
|
|
|
5,965
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
3,294
|
|
|
|
2,643
|
|
|
|
2,182
|
|
Changes in net assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and other assets
|
|
|
(6,313
|
)
|
|
|
258
|
|
|
|
(24,713
|
)
|
Inventory
|
|
|
(4,573
|
)
|
|
|
4,454
|
|
|
|
4,829
|
|
Net change in related party receivables and payables
|
|
|
2,957
|
|
|
|
32,688
|
|
|
|
(39,202
|
)
|
Accounts payable and other liabilities
|
|
|
(4,753
|
)
|
|
|
(13,413
|
)
|
|
|
30,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
224,358
|
|
|
|
226,696
|
|
|
|
60,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(29,513
|
)
|
|
|
(131,082
|
)
|
|
|
(23,549
|
)
|
Proceeds from sale of assets, net
|
|
|
23,284
|
|
|
|
-
|
|
|
|
-
|
|
Property acquisitions
|
|
|
-
|
|
|
|
(9,957
|
)
|
|
|
(996,561
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(6,229
|
)
|
|
|
(141,039
|
)
|
|
|
(1,020,110
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units, net of discount
|
|
|
-
|
|
|
|
-
|
|
|
|
663,338
|
|
Purchase of common units
|
|
|
-
|
|
|
|
(336,216
|
)
|
|
|
-
|
|
Distributions to predecessor members concurrent with initial
public offering
|
|
|
-
|
|
|
|
-
|
|
|
|
581
|
|
Distributions (b)
|
|
|
(28,038
|
)
|
|
|
(121,349
|
)
|
|
|
(60,497
|
)
|
Proceeds from the issuance of long-term debt
|
|
|
249,975
|
|
|
|
803,002
|
|
|
|
574,700
|
|
Repayments of long-term debt
|
|
|
(426,975
|
)
|
|
|
(437,402
|
)
|
|
|
(205,800
|
)
|
Book overdraft
|
|
|
(9,871
|
)
|
|
|
7,951
|
|
|
|
(116
|
)
|
Long-term debt issuance costs
|
|
|
-
|
|
|
|
(5,026
|
)
|
|
|
(6,362
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
(214,909
|
)
|
|
|
(89,040
|
)
|
|
|
965,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash
|
|
|
3,220
|
|
|
|
(3,383
|
)
|
|
|
5,836
|
|
Cash beginning of period
|
|
|
2,546
|
|
|
|
5,929
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash end of period
|
|
$
|
5,766
|
|
|
$
|
2,546
|
|
|
$
|
5,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Non-cash investing
activity in 2007 was $700 million, reflecting the issuance
of 21.348 million Common Units for the Quicksilver
acquisition.
(b) 2009 and 2008 include
distributions on equivalent units of $0.7 million and
$2.3 million, respectively.
The accompanying notes are an integral part of these
consolidated financial statements.
115
BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated Statements of Partners Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited
|
|
|
General
|
|
|
|
|
Thousands
|
|
Common Units
|
|
|
Partners
|
|
|
Partner
|
|
|
Total
|
|
|
Balance, December 31, 2006
|
|
|
21,976
|
|
|
$
|
174,395
|
|
|
$
|
2,813
|
|
|
$
|
177,208
|
|
Issuance of units (a)
|
|
|
21,348
|
|
|
|
700,000
|
|
|
|
-
|
|
|
|
700,000
|
|
Private offering investment (b)
|
|
|
23,697
|
|
|
|
663,338
|
|
|
|
-
|
|
|
|
663,338
|
|
Distributions
|
|
|
-
|
|
|
|
(59,746
|
)
|
|
|
(751
|
)
|
|
|
(60,497
|
)
|
Unit-based compensation
|
|
|
-
|
|
|
|
5,133
|
|
|
|
-
|
|
|
|
5,133
|
|
Net loss
|
|
|
-
|
|
|
|
(59,685
|
)
|
|
|
(672
|
)
|
|
|
(60,357
|
)
|
Other
|
|
|
-
|
|
|
|
(17
|
)
|
|
|
-
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
67,021
|
|
|
$
|
1,423,418
|
|
|
$
|
1,390
|
|
|
$
|
1,424,808
|
|
Redemption of common units from predecessors (c)
|
|
|
(14,405
|
)
|
|
|
(336,216
|
)
|
|
|
-
|
|
|
|
(336,216
|
)
|
Distributions
|
|
|
-
|
|
|
|
(118,580
|
)
|
|
|
(427
|
)
|
|
|
(119,007
|
)
|
Distributions paid on unissued units under incentive plans
|
|
|
-
|
|
|
|
(2,335
|
)
|
|
|
(7
|
)
|
|
|
(2,342
|
)
|
Unit-based compensation
|
|
|
-
|
|
|
|
7,383
|
|
|
|
-
|
|
|
|
7,383
|
|
Net income (loss)
|
|
|
-
|
|
|
|
380,255
|
|
|
|
(2,019
|
)
|
|
|
378,236
|
|
Contribution of general partner interest to the
Partnership (d)
|
|
|
-
|
|
|
|
(1,063
|
)
|
|
|
1,063
|
|
|
|
-
|
|
BreitBurn Management purchase (e)
|
|
|
20
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
30
|
|
|
|
-
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
52,636
|
|
|
$
|
1,352,892
|
|
|
$
|
-
|
|
|
$
|
1,352,892
|
|
Distributions
|
|
|
-
|
|
|
|
(27,371
|
)
|
|
|
-
|
|
|
|
(27,371
|
)
|
Distributions paid on unissued units under incentive plans
|
|
|
-
|
|
|
|
(667
|
)
|
|
|
-
|
|
|
|
(667
|
)
|
Units issued under incentive plans
|
|
|
148
|
|
|
|
7,488
|
|
|
|
|
|
|
|
7,488
|
|
Unit-based compensation
|
|
|
|
|
|
|
3,322
|
|
|
|
-
|
|
|
|
3,322
|
|
Net loss
|
|
|
-
|
|
|
|
(107,290
|
)
|
|
|
-
|
|
|
|
(107,290
|
)
|
Other
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
52,784
|
|
|
$
|
1,228,373
|
|
|
$
|
-
|
|
|
$
|
1,228,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Reflects the issuance of Common
Units for the Quicksilver acquisition.
|
(b)
|
Reflects the issuance of Common
Units in three private placements.
|
(c)
|
Reflects the purchase of Common
Units from subsidiaries of Provident.
|
(d)
|
General partner interests were
purchased as of June 17, 2008.
|
(e)
|
Reflects issuance of Common Units
to Co-CEOs in exchange for their interest in BreitBurn
Management.
|
The accompanying notes are an integral part of these
consolidated financial statements.
116
Notes to
Consolidated Financial Statements
The Partnership is a Delaware limited partnership formed on
March 23, 2006. In connection with our initial public
offering in October 2006, BreitBurn Energy Company L.P.
(BEC), our Predecessor, contributed to us certain
properties, which included fields in the Los Angeles Basin in
California and the Wind River and Big Horn Basins in central
Wyoming. In 2007, we acquired certain interests in oil leases
and related assets located in Florida for approximately
$110 million, assets located in California for
approximately $93 million and properties located in
Michigan, Indiana and Kentucky from Quicksilver Resources Inc.
(Quicksilver) for approximately $1.46 billion
(the Quicksilver Acquisition).
Our general partner is BreitBurn GP, a Delaware limited
liability company, also formed on March 23, 2006. The
board of directors of our General Partner has sole
responsibility for conducting our business and managing our
operations. We conduct our operations through a wholly owned
subsidiary, BOLP and BOLPs general partner BOGP. We own
all of the ownership interests in BOLP and BOGP.
Our wholly owned subsidiary, BreitBurn Management, manages our
assets and performs other administrative services for us such as
accounting, corporate development, finance, land administration,
legal and engineering. See Note 8 for information
regarding our relationship with BreitBurn Management.
Our wholly owned subsidiary, BreitBurn Finance Corporation was
incorporated on June 1, 2009 under the laws of the State of
Delaware. BreitBurn Finance Corporation is wholly owned by us,
and has no assets or liabilities. Its activities are limited to
co-issuing debt securities and engaging in other activities
incidental thereto.
As of December 31, 2009, the public unitholders, the
institutional investors in our private placements and
Quicksilver owned 98.69 percent of the Common Units.
BreitBurn Corporation owned 690,751 Common Units, representing a
1.31 percent limited partner interest. We own
100 percent of the General Partner, BreitBurn Management,
BOLP and BreitBurn Finance Corporation.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Principles
of consolidation
The consolidated financial statements include our accounts and
the accounts of our wholly owned subsidiaries and our
predecessor. Investments in affiliated companies with a
20 percent or greater ownership interest, and in which we
do not have control, are accounted for on the equity basis.
Investments in affiliated companies with less than a
20 percent ownership interest, and in which we do not have
control, are accounted for on the cost basis. Investments in
which we own greater than 50 percent interest are
consolidated. Investments in which we own less than a
50 percent interest but are deemed to have control or where
we have a variable interest in an entity where we will absorb a
majority of the entitys expected losses or receive a
majority of the entitys expected residual returns or both,
however, are consolidated. The effects of all intercompany
transactions have been eliminated.
Basis of
Presentation
Our financial statements are prepared in conformity with
U.S. generally accepted accounting principles. Certain
items included in the prior year financial statements have been
reclassified to conform to the 2009 presentation.
In the first quarter of 2009, we began classifying regional
operation management expenses as operating costs rather than
general and administrative expenses to better align our
operating and management costs with our organizational structure
and to be more consistent with industry practices. As such, we
have revised classification of these expenses for the years
ended December 31, 2008 and 2007, respectively. The
reclassification did not affect previously reported total
revenues, net income or net cash provided by operating
117
activities. The following table reflects all classification
changes for the years ended December 31, 2008 and 2007,
respectively:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2008
|
|
|
2007
|
|
|
Operating costs
|
|
|
|
|
|
|
|
|
As previously reported
|
|
$
|
149,681
|
|
|
$
|
70,329
|
|
District expense reclass from G&A
|
|
|
12,324
|
|
|
|
3,660
|
|
|
|
|
|
|
|
|
|
|
As revised
|
|
$
|
162,005
|
|
|
$
|
73,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A expenses
|
|
|
|
|
|
|
|
|
As previously reported
|
|
$
|
43,435
|
|
|
$
|
30,588
|
|
District expense reclass to operating costs
|
|
|
(12,324
|
)
|
|
|
(3,660
|
)
|
|
|
|
|
|
|
|
|
|
As revised
|
|
$
|
31,111
|
|
|
$
|
26,928
|
|
|
|
|
|
|
|
|
|
|
Use of
estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates. The financial statements are based
on a number of significant estimates including oil and gas
reserve quantities, which are the basis for the calculation of
depletion, depreciation, amortization, asset retirement
obligations and impairment of oil and gas properties.
We account for business combinations using the purchase method,
in accordance with Financial Accounting Standards Board
(FASB) Accounting Standards Codification
(ASC) 805 Business Combinations.
We use estimates to record the assets and liabilities
acquired. All purchase price allocations are finalized within
one year from the acquisition date.
Business
segment information
ASC 280 Segment Reporting establishes
standards for reporting information about operating segments.
Segment reporting is not applicable because our oil and gas
operating areas have similar economic characteristics. We
acquire, exploit, develop and produce oil and natural gas in the
United States. Corporate management administers all properties
as a whole rather than as discrete operating segments.
Operational data is tracked by area; however, financial
performance is measured as a single enterprise and not on an
area-by-area
basis. Allocation of capital resources is employed on a
project-by-project
basis across our entire asset base to maximize profitability
without regard to individual areas.
Revenue
recognition
Revenues associated with sales of our crude oil and natural gas
are recognized when title passes from us to our customer.
Revenues from properties in which we have an interest with other
partners are recognized on the basis of our working interest
(entitlement method of accounting). We generally
market most of our natural gas production from our operated
properties and pay our partners for their working interest
shares of natural gas production sold. As a result, we have no
material natural gas producer imbalance positions.
Cash and
cash equivalents
We consider all investments with original maturities of three
months or less to be cash equivalents. At December 31,
2009 and 2008 we had no such investments.
118
Accounts
Receivable
Our accounts receivable are primarily from purchasers of crude
oil and natural gas and counterparties to our financial
instruments. Crude oil receivables are generally collected
within 30 days after the end of the month. Natural gas
receivables are generally collected within 60 days after
the end of the month. We review all outstanding accounts
receivable balances and record a reserve for amounts that we
expect will not be fully recovered. Actual balances are not
applied against the reserve until substantially all collection
efforts have been exhausted.
At December 31, 2009, accounts receivable also included a
$4.3 million receivable from our insurance company related
to legal costs incurred during the lawsuit with Quicksilver and
a $13.0 million receivable from our insurance company
related to the settlement of the lawsuit.
As of December 31, 2009, we did not carry an allowance for
doubtful accounts receivable.
During 2008 we terminated our crude oil derivative instruments
with Lehman Brothers due to their bankruptcy. On
October 21, 2009, we completed the transfer and sale of our
claims in the bankruptcy cases filed by Lehman Brothers
Commodity Services Inc. and Lehman Brothers Holdings Inc.
(together referred to as Lehman Brothers), to a third party. We
recognized a $1.9 million gain reflected in gains and
losses on commodity derivative instruments on the consolidated
statements of operations. At December 31, 2008, we had an
allowance of $4.6 million related to the Lehman Brothers
crude oil derivative contracts.
Inventory
Oil inventories are carried at the lower of cost to produce or
market price. We match production expenses with crude oil
sales. Production expenses associated with unsold crude oil
inventory are recorded as inventory.
Investments
in Equity Affiliates
Income from equity affiliates is included as a component of
operating income, as the operations of these affiliates are
associated with the processing and transportation of our natural
gas production.
Property,
plant and equipment
Oil
and gas properties
We follow the successful efforts method of accounting. Lease
acquisition and development costs (tangible and intangible)
incurred relating to proved oil and gas properties are
capitalized. Delay and surface rentals are charged to expense
as incurred. Dry hole costs incurred on exploratory wells are
expensed. Dry hole costs associated with developing proved
fields are capitalized. Geological and geophysical costs
related to exploratory operations are expensed as incurred.
Upon sale or retirement of proved properties, the cost thereof
and the accumulated depletion, depreciation and amortization
(DD&A) are removed from the accounts and any
gain or loss is recognized in the statement of operations.
Maintenance and repairs are charged to operating expenses.
DD&A of proved oil and gas properties, including the
estimated cost of future abandonment and restoration of well
sites and associated facilities, are generally computed on a
field-by-field
basis where applicable and recognized using the
units-of-production method net of any anticipated proceeds from
equipment salvage and sale of surface rights. Other gathering
and processing facilities are recorded at cost and are
depreciated using straight line, generally over 20 years.
Non-oil
and gas assets
Buildings and non-oil and gas assets are recorded at cost and
depreciated using the straight-line method over their estimated
useful lives, which range from three to 20 years.
119
Oil and
natural gas reserve quantities
Reserves and their relation to estimated future net cash flows
impact our depletion and impairment calculations. As a result,
adjustments to depletion are made concurrently with changes to
reserve estimates. We disclose reserve estimates, and the
projected cash flows derived from these reserve estimates, in
accordance with SEC guidelines. In 2009, our reserves
disclosures were in accordance with Release
No. 33-8995,
Modernization of Oil and Gas Reporting
(Release
33-8995),
issued by the SEC in December, 2008 as well as ASC 932 which
incorporates the SEC release. The independent engineering firms
adhere to the SEC definitions when preparing their reserve
reports.
Asset
retirement obligations
We have significant obligations to plug and abandon oil and
natural gas wells and related equipment at the end of oil and
natural gas production operations. The computation of our asset
retirement obligations (ARO) is prepared in
accordance with ASC 410 Asset Retirement and
Environmental Obligations. This topic applies to the
fair value of a liability for an asset retirement obligation
that is recorded when there is a legal obligation associated
with the retirement of a tangible long-lived asset and the
liability can be reasonably estimated. Over time, changes in
the present value of the liability are accreted and expensed.
The capitalized asset costs are depreciated over the useful
lives of the corresponding asset. Recognized liability amounts
are based upon future retirement cost estimates and incorporate
many assumptions such as: (1) expected economic recoveries
of crude oil and natural gas, (2) time to abandonment,
(3) future inflation rates and (4) the risk free rate
of interest adjusted for our credit costs. Future revisions to
ARO estimates will impact the present value of existing ARO
liabilities and corresponding adjustments will be made to the
capitalized asset retirement costs balance.
Impairment
of assets
Long-lived assets with recorded values that are not expected to
be recovered through future cash flows are written-down to
estimated fair value in accordance with ASC 360
Property, Plant and Equipment. Under
ASC 360, a long- lived asset is tested for impairment when
events or circumstances indicate that its carrying value may not
be recoverable. The carrying value of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows
expected to result from the use and eventual disposition of the
asset. If the carrying value exceeds the sum of the
undiscounted cash flows, an impairment loss equal to the amount
by which the carrying value exceeds the fair value of the asset
is recognized. Fair value is generally determined from
estimated discounted future net cash flows. For purposes of
performing an impairment test, the undiscounted future cash
flows are based on total proved and risk-adjusted probable and
possible reserves and are forecast using five-year NYMEX forward
strip prices at the end of the period and escalated along with
expenses and capital starting year six thereafter at
2.5 percent per year. For impairment charges, the
associated propertys expected future net cash flows are
discounted using a rate of approximately ten percent. Reserves
are calculated based upon reports from third-party engineers
adjusted for acquisitions or other changes occurring during the
year as determined to be appropriate in the good faith judgment
of management.
We assess our long-lived assets for impairment generally on a
field-by-field
basis where applicable. We did not record an impairment charge
in 2009 or 2007. Because of the low commodity prices that
existed at year end 2008, we recorded $51.9 million in
impairments and $34.5 million in price related depletion
and depreciation adjustments. Price related adjustments to
depletion and depreciation in 2009 were immaterial. See
Note 6 for a discussion of our impairments and price
related depletion and depreciation adjustments.
Debt
issuance costs
The costs incurred to obtain financing have been capitalized.
Debt issuance costs are amortized using the straight-line method
over the term of the related debt. Use of the straight-line
method does not differ materially from the effective
interest method of amortization.
120
Equity-based
compensation
ASC 718 Compensation Stock
Compensation establishes standards for charging
compensation expenses based on fair value provisions. BreitBurn
Management has various forms of equity-based compensation
outstanding under employee compensation plans that are described
more fully in Note 17. Awards classified as equity are
valued on the grant date and are recognized as compensation
expense over the vesting period. We recognize equity-based
compensation costs on a straight line basis over the annual
vesting periods. Awards classified as liabilities were revalued
at each reporting period and changes in the fair value of the
options were recognized as compensation expense over the vesting
schedules of the awards.
Fair
market value of financial instruments
The carrying amount of our cash, accounts receivable, accounts
payable, related party receivables and payables, and accrued
expenses, approximate their respective fair value due to the
relatively short term of the related instruments. The carrying
amount of long-term debt approximates fair value; however,
changes in the credit markets at year-end may impact our ability
to enter into future credit facilities at similar terms.
Accounting
for business combinations
We have accounted for all business combinations using the
purchase method, in accordance with ASC 805 Business
Combinations. Under the purchase method of
accounting, a business combination is accounted for at a
purchase price based upon the fair value of the consideration
given, whether in the form of cash, assets, equity or the
assumption of liabilities. The assets and liabilities acquired
are measured at their fair values, and the purchase price is
allocated to the assets and liabilities based upon these fair
values. The excess of the fair value of assets acquired and
liabilities assumed over the cost of an acquired entity, if any,
is allocated as a pro rata reduction of the amounts that
otherwise would have been assigned to certain acquired assets.
We have not recognized any goodwill from any business
combinations.
Concentration
of credit risk
We maintain our cash accounts primarily with a single bank and
invest cash in money market accounts, which we believe to have
minimal risk. At times, such balances may be in excess of the
Federal Insurance Corporation insurance limit. As operator of
jointly owned oil and gas properties, we sell oil and gas
production to U.S. oil and gas purchasers and pay vendors
on behalf of joint owners for oil and gas services. We
periodically monitor our major purchasers credit ratings.
We enter into commodity and interest rate derivative
instruments. Our derivative counterparties are all lenders
under our credit facility and we periodically monitor their
credit ratings.
Derivatives
ASC 815 Derivatives and Hedging establishes
accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other
contracts, and hedging activities. It requires the recognition
of all derivative instruments as assets or liabilities on our
balance sheet and measurement of those instruments at fair
value. The accounting treatment of changes in fair value is
dependent upon whether or not a derivative instrument is
designated as a hedge and if so, the type of hedge. For
derivatives designated as cash flow hedges, changes in fair
value are recognized in other comprehensive income, to the
extent the hedge is effective, until the hedged item is
recognized in earnings. Hedge effectiveness is measured based
on the relative changes in fair value between the derivative
contract and the hedged item over time. Any change in fair
value resulting from ineffectiveness, as defined by
ASC 815, is recognized immediately in earnings. Gains and
losses on derivative instruments not designated as hedges are
currently included in earnings. The resulting cash flows are
reported as cash from operating activities. We currently do not
designate any of our derivatives as hedges for accounting
purposes.
Effective January 1, 2008, we adopted
SFAS No. 157, Fair Value Measurements,
now codified within ASC 820, Fair Value
Measurements and Disclosures. ASC 820 defines
fair value, establishes a framework for measuring fair value and
expands disclosures about fair value measurements. Fair value
measurement
121
under ASC 820 is based upon a hypothetical transaction to
sell an asset or transfer a liability at the measurement date,
considered from the perspective of a market participant that
holds the asset or owes the liability. The objective of fair
value measurement as defined in ASC 820 is to determine the
price that would be received in selling the asset or
transferring the liability in an orderly transaction between
market participants at the measurement date. If there is an
active market for the asset or liability, the fair value
measurement shall represent the price in that market whether the
price is directly observable or otherwise obtained using a
valuation technique.
Income
taxes
Our subsidiaries are mostly partnerships or limited liability
companies treated as partnerships for federal tax purposes with
essentially all taxable income or loss being passed through to
the members. As such, no federal income tax for these entities
has been provided.
We have three wholly owned subsidiaries, which are subject to
corporate income taxes. We account for the taxes associated
with one entity in accordance with ASC 740, Income
Taxes. Deferred income taxes are recorded under the
asset and liability method. Where material, deferred income tax
assets and liabilities are computed for differences between the
financial statement and income tax bases of assets and
liabilities that will result in taxable or deductible amounts in
the future. Such deferred income tax asset and liability
computations are based on enacted tax laws and rates applicable
to periods in which the differences are expected to affect
taxable income. Income tax expense is the tax payable or
refundable for the period plus or minus the change during the
period in deferred income tax assets and liabilities.
ASC 740 clarifies the accounting for uncertainty in income
taxes recognized in a companys financial statements. A
company can only recognize the tax position in the financial
statements if the position is more-likely-than-not to be upheld
on audit based only on the technical merits of the tax
position. This accounting standard also provides guidance on
thresholds, measurement, derecognition, classification, interest
and penalties, accounting in interim periods, disclosure, and
transition that is intended to provide better
financial-statement comparability among different companies.
We performed evaluations as of December 31, 2009, 2008 and
2007 and concluded that there were no uncertain tax positions
requiring recognition in our financial statements.
Net
Income or loss per unit
ASC 260 Earnings per Share requires use
of the two-class method of computing earnings per
unit for all periods presented. The two-class
method is an earnings allocation formula that determines
earnings per unit for each class of Common Unit and
participating security as if all earnings for the period had
been distributed. Unvested restricted unit awards that earn
non-forfeitable dividend rights qualify as participating
securities and, accordingly, are included in the basic
computation. Our unvested restricted phantom units
(RPUs) and convertible phantom units
(CPUs) participate in dividends on an equal basis
with Common Units; therefore, there is no difference in
undistributed earnings allocated to each participating
security. Accordingly, our calculation is prepared on a
combined basis and is presented as earnings per Common Unit. See
Note 14 for our earnings per Common Unit calculation.
Environmental
expenditures
We review, on an annual basis, our estimates of the cleanup
costs of various sites. When it is probable that obligations
have been incurred and where a reasonable estimate of the cost
of compliance or remediation can be determined, the applicable
amount is accrued. For other potential liabilities, the timing
of accruals coincides with the related ongoing site assessments.
We do not discount any of these liabilities. At
December 31, 2009 and 2008, we had a $2.0 million
environmental liability related to a closure of a drilling pit
in Michigan, which we assumed in the Quicksilver Acquisition.
122
|
|
3.
|
Accounting
Pronouncements
|
We adopted new accounting pronouncements during 2009 related to
fair value measurements as discussed in Notes 13 and 16,
the earnings per share impact of instruments granted in
share-based payment transactions as discussed in Note 14,
noncontrolling interests as discussed in Note 15,
disclosures about derivative instruments and hedging activities
as discussed in Note 16 and business combinations as
discussed in Note 4, which we will apply prospectively to
business combinations with acquisition dates after
January 1, 2009. We also adopted a new accounting
pronouncement related to the determination of the useful lives
of intangible assets and an accounting pronouncement related to
the fair valuation of liabilities when a quoted price in an
active market is not available, with no impact on our financial
position, results of operations or cash flows.
Financial Accounting Standards Board (FASB)
Accounting Standards Codification (ASC)
Topic 105 Generally Accepted Accounting
Principles establishes the FASB ASC as the source
of authoritative accounting principles recognized by the FASB to
be applied in the preparation of financial statements in
conformity with GAAP. ASC 105 explicitly recognizes rules
and interpretive releases of the SEC under federal securities
laws as authoritative GAAP for SEC registrants. This topic,
which has changed the way we reference GAAP, is effective for
financial statements ending after September 15, 2009. This
topic does not change GAAP and did not have an impact on our
financial position, results of operations or cash flows.
SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting. In
December 2008, the SEC issued
Release 33-8995
adopting new rules for reserves estimate calculations and
related disclosures. The new reserve estimate disclosures apply
to all annual reports for fiscal years ending on or after
December 31, 2009 and thereafter, and to all registration
statements filed after that date. The new rules do not permit
companies to voluntarily comply at an earlier date. The revised
proved reserve definition incorporates a new definition of
reasonable certainty using the PRMS (Petroleum
Resource Management System) standard of high degree of
confidence for deterministic method estimates, or a
90 percent recovery probability for probabilistic methods
used in estimating proved reserves. The new rules also permit a
company to establish undeveloped reserves as proved with
appropriate degrees of reasonable certainty established absent
actual production tests and without artificially limiting such
reserves to spacing units adjacent to a producing well. For
reserve reporting purposes, the new rules also replace the
end-of-the-year oil and gas reserve pricing with an unweighted
average
first-day-of-the-month
pricing for the past 12 fiscal months. We use quarter-end
reserves to calculate quarterly DD&A and, as such, adoption
of the new standard had an impact on fourth quarter 2009
DD&A expense. See Note 22. The impact that adopting
Release
33-8995 has
had on our financial statements is not practical to estimate due
to the operational and technical challenges associated with
calculating a cumulative effect of adoption by preparing reserve
reports under both the old and new rules. Costs associated with
reserves will continue to be measured on the last day of the
fiscal year. A revised tabular presentation of reserves by
development category, final product type, and oil and gas
activity disclosure by geographic regions and significant fields
and a general disclosure of the internal controls a company uses
to assure objectivity in reserves estimation will be required.
See Note 22 for the impact Release
33-8995 has
had on the calculation of our crude oil and natural gas reserves.
Accounting Standards Update (ASU)
2010-03
Extractive Activities Oil and Gas.
In January 2010, the FASB issued ASU
2010-03 to
align the oil and gas reserve estimation and disclosure
requirements of Extractive Activities Oil and Gas
(Topic 932) with the requirements in the Securities and
Exchange Commissions final rule, Modernization of the Oil
and Gas Reporting Requirements which was issued on
December 31, 2008. We calculate total estimated proved
reserves and disclose our oil and natural gas activities in
accordance with ASC 932 Extractive
Activities Oil and Gas, which incorporates
SEC release
No. 33-8995,
Modernization of Oil and Gas Reporting. and ASU
2010-03
Extractive Activities Oil
and Gas.
ASU
2010-06
Fair Value Measurements and Disclosures. In
January 2010, the FASB issued
ASU 2010-06
to make certain amendments to Subtopic
820-10 that
require two additional disclosures and clarify two existing
disclosures. The new disclosures require details of significant
transfers in and out of level 1 and level 2
measurements and the reasons for the transfers, and a gross
presentation of activity within the level 3 roll forward
that presents separately, information about purchases, sales,
issuances and settlements.
123
The ASU clarifies the existing disclosures with regard to the
level of disaggregation of fair value measurements by class of
assets and liabilities rather than major category where the
reporting entities would need to apply judgment to determine the
appropriate classes of other assets and liabilities. The second
clarification relates to disclosures of valuation techniques and
inputs for recurring and non recurring fair value measurements
using significant other observable inputs and significant
unobservable inputs for level 2 and level 3
measurements, respectively.
ASU 2010-06
(ASC 820-10)
is prospectively effective for financial statements issued for
interim or annual periods beginning after December 15,
2009, except for the disclosures about purchases, sales,
issuances, and settlements in the roll forward of activity in
Level 3 fair value measurements which are effective for
fiscal years beginning after December 15, 2010 and for
interim periods within those fiscal years. We do not expect the
adoption of ASU
2010-06 (ASC
820-10) to
have an impact on our financial position, results of operations
or cash flows.
In June 2009, the FASB issued authoritative guidance for the
consolidation of variable interest entities, which changed the
consolidation guidance applicable to a variable interest entity
(VIE). The guidance governing the determination of
whether an enterprise is the primary beneficiary of a VIE, and
is, therefore, required to consolidate an entity, by requiring a
qualitative analysis rather than a quantitative analysis. The
qualitative analysis will include, among other things,
consideration of who has the power to direct the activities of
the entity that most significantly impact the entitys
economic performance and who has the obligation to absorb losses
or the right to receive benefits of the VIE that could
potentially be significant to the VIE. This guidance also
requires continuous reassessments of whether an enterprise is
the primary beneficiary of a VIE. Former guidance required
reconsideration of whether an enterprise was the primary
beneficiary of a VIE only when specific events had occurred. The
guidance also requires enhanced disclosures about an
enterprises involvement with a VIE. We will adopt this
guidance effective January 1, 2010, and we are assessing
the impact this guidance may have on our consolidated financial
statements.
On June 17, 2008, we purchased Provident Energy
Trusts 95.55 percent limited liability company
interest in BreitBurn Management for a purchase price of
approximately $10.0 million. This transaction resulted in
BreitBurn Management becoming our wholly owned subsidiary and
was accounted for as a business combination using the purchase
method.
The following table presents the purchase price allocation of
the BreitBurn Management Purchase:
|
|
|
|
|
Thousands of
dollars
|
|
|
|
|
Related party receivables current, net
|
|
$
|
10,662
|
|
Other current assets
|
|
|
21
|
|
Oil and gas properties
|
|
|
8,451
|
|
Non-oil and gas assets
|
|
|
4,343
|
|
Related party receivables non-current
|
|
|
6,704
|
|
Current liabilities
|
|
|
(13,510
|
)
|
Long-term liabilities
|
|
|
(6,704
|
)
|
|
|
|
|
|
|
|
$
|
9,967
|
|
|
|
|
|
|
Certain of the current and long-term related party receivables
are with the Partnership, so they are now eliminated in
consolidation.
Pro Forma
Information
The following unaudited pro forma financial information presents
a summary of our consolidated results of operations for 2007,
assuming the Quicksilver Acquisition and the acquisitions in
Florida and California had been completed as of the beginning of
the year, including adjustments to reflect the allocation of the
purchase price to the acquired net assets. The pro forma
financial information assumes our 2007 private placements of
Common Units (see Note 14) were completed as of the
beginning of the year, since the private
124
placements were contingent on two of the acquisitions. The
revenues and expenses of these three acquisitions are included
in the 2007 consolidated results of the Partnership effective
May 24, May 25 and November 1, 2007. The pro forma
financial information is not necessarily indicative of the
results of operations if the acquisitions had been effective as
of these dates.
|
|
|
|
|
|
|
Pro Forma Year Ended
|
|
Thousands of dollars, except
per unit amounts
|
|
December 31,
2007 (1)
|
|
|
Revenues
|
|
$
|
233,761
|
|
Net income (loss)
|
|
|
(43,966
|
)
|
Net income (loss) per unit
|
|
|
|
|
Basic
|
|
$
|
(0.65
|
)
|
Diluted
|
|
|
(0.65
|
)
|
(1) Results include losses on derivative instruments of
$101.0 million for the year ended December 31, 2007.
Effective January 1, 2009, we will account for all business
combinations using the acquisition method in accordance with ASC
805.
On July 17, 2009, we sold the Lazy JL Field located in
the Permian Basin of West Texas to a private buyer for
$23 million in cash. This transaction was effective
July 1, 2009. The proceeds from this transaction were used
to reduce our outstanding borrowings under our credit facility.
In connection with the sale, the borrowing base under our credit
facility was reduced by $3 million to $732 million.
The Lazy JL Field properties produced approximately 245 Boe per
day during the first six months of 2009, of which
96 percent was crude oil. The net carrying value at the
date of sale was $28.5 million, of which $28.7 million
was reflected in net property, plant and equipment on the
balance sheet and $0.2 million was reflected in asset
retirement obligation on the balance sheet. We recognized a
loss of $5.5 million in 2009 related to the sale of the
field.
|
|
6.
|
Impairments
and Price Related Depletion and Depreciation
Adjustments
|
We assess our developed and undeveloped oil and gas properties
and other long-lived assets for possible impairment whenever
events or changes in circumstances indicate that the carrying
value of the assets may not be recoverable. Such indicators
include changes in business plans, changes in commodity prices
and, for crude oil and natural gas properties, significant
downward revisions of estimated proved-reserve quantities. If
the carrying value of an asset exceeds the future undiscounted
cash flows expected from the asset, an impairment charge is
recorded for the excess of carrying value of the asset over its
estimated fair value.
Determination as to whether and how much an asset is impaired
involves management estimates on highly uncertain matters such
as future commodity prices, the effects of inflation and
technology improvements on operating expenses, production
profiles, and the outlook for market supply and demand
conditions for crude oil and natural gas. The impairment
reviews and calculations are based on assumptions that are
consistent with our business plans. The low commodity price
environment that existed at December 31, 2008 influenced
our future commodity price projections. As a result, the
expected discounted cash flows for many of our fields
(i.e., fair values) were negatively impacted resulting in a
charge to depletion and depreciation expense of approximately
$51.9 million for oil and gas property impairments for the
year ended December 31, 2008.
An estimate as to the sensitivity to earnings for these periods
if other assumptions had been used in impairment reviews and
calculations is not practicable, given the number of assumptions
involved in the estimates. That is, favorable changes to some
assumptions might have avoided the need to impair any assets in
these periods, whereas unfavorable changes might have caused an
additional unknown number of other assets to become impaired.
125
Lower commodity prices also negatively impacted our oil and gas
reserves in the fourth quarter of 2008 resulting in significant
price related adjustments to our depletion and depreciation
expense in the fourth quarter of 2008 as compared to the fourth
quarter of 2007. These price related reserve reductions in 2008
resulted in additional depletion and depreciation charges of
approximately $34.5 million for the fourth quarter and for
the year ended December 31, 2008.
For the years ended December 31, 2009 and 2007, we reviewed
our long-lived oil and gas assets and did not record any
material impairments or price related adjustments to depletion
and depreciation expense.
We, and all of our subsidiaries, with the exception of Phoenix
Production Company (Phoenix), Alamitos Company,
BreitBurn Management and BreitBurn Finance Corporation, are
partnerships or limited liability companies treated as
partnerships for federal and state income tax purposes.
Essentially all of our taxable income or loss, which may differ
considerably from the net income or loss reported for financial
reporting purposes, is passed through to the federal income tax
returns of our partners. As such, we have not recorded any
federal income tax expense for those pass-through entities.
The consolidated income tax expense (benefit) attributable to
our tax-paying entities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Federal income tax expense (benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
247
|
|
|
$
|
257
|
|
|
$
|
-
|
|
Deferred (a)
|
|
|
(1,790
|
)
|
|
|
1,207
|
|
|
|
(1,229
|
)
|
State income tax expense (benefit) (b)
|
|
|
15
|
|
|
|
475
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(1,528
|
)
|
|
$
|
1,939
|
|
|
$
|
(1,229
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Related to Phoenix Production Company, our wholly owned
subsidiary.
|
|
|
|
|
|
|
(b)
|
Primarily in the states of Michigan, California and Texas.
|
|
We record income tax expense for Phoenix, a tax-paying
corporation, in accordance with ASC 740 Income
Taxes. The following is a reconciliation of federal
income taxes at the statutory rates to federal income tax
expense (benefit) for Phoenix:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Income (loss) subject to federal income tax
|
|
|
(4,052
|
)
|
|
|
3,904
|
|
|
|
(4,498
|
)
|
Federal income tax rate
|
|
|
34
|
%
|
|
|
34
|
%
|
|
|
34
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax at statutory rate
|
|
|
(1,378
|
)
|
|
|
1,327
|
|
|
|
(1,529
|
)
|
Other
|
|
|
(299
|
)
|
|
|
-
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
|
$
|
(1,677
|
)
|
|
$
|
1,327
|
|
|
$
|
(1,229
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009 and 2008, a net deferred federal
income tax liability of $2.5 million and $4.3 million,
respectively, were reported in our consolidated balance sheet
for Phoenix. Deferred income taxes reflect the net tax effect
of temporary differences between the carrying amounts of assets
and liabilities for
126
financial reporting and the amount used for income tax
purposes. Significant components of our net deferred tax
liabilities are presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
422
|
|
|
$
|
767
|
|
Asset retirement obligation
|
|
|
358
|
|
|
|
337
|
|
Unrealized hedge loss
|
|
|
85
|
|
|
|
-
|
|
Other
|
|
|
276
|
|
|
|
103
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and intangible drilling costs
|
|
|
(3,101
|
)
|
|
|
(3,404
|
)
|
Unrealized hedge gain
|
|
|
-
|
|
|
|
(2,085
|
)
|
Deferred realized hedge gain
|
|
|
(532
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(2,492
|
)
|
|
$
|
(4,282
|
)
|
|
|
|
|
|
|
|
|
|
At December 31, 2009, we had $1.2 million of estimated
unused operating loss carry forwards. We did not provide a
valuation allowance against this deferred tax asset as we expect
sufficient future taxable income to offset the unused operating
loss carry forwards.
On a consolidated basis, cash paid for federal and state income
taxes totaled $0.6 million in 2009, $0.6 million in
2008 and $0.1 million in 2007.
ASC 740 Income Taxes, clarifies the
accounting for uncertainty in income taxes recognized in a
companys financial statements. A company can only
recognize the tax position in the financial statements if the
position is
more-likely-than-not
to be upheld on audit based only on the technical merits of the
tax position. This topic also provides guidance on thresholds,
measurement, derecognition, classification, interest and
penalties, accounting in interim periods, disclosure, and
transition that is intended to provide better
financial-statement comparability among different companies.
We performed evaluations as of December 31, 2009 and 2008
and concluded that there were no uncertain tax positions
requiring recognition in our financial statements.
|
|
8.
|
Related
Party Transactions
|
BreitBurn Management operates our assets and performs other
administrative services for us such as accounting, corporate
development, finance, land administration, legal and
engineering. All of our employees, including our executives,
are employees of BreitBurn Management. Prior to June 17,
2008, BreitBurn Management provided services to us and to BEC,
and allocated its expenses between the two entities. On
June 17, 2008, BreitBurn Management became our wholly-owned
subsidiary and entered into an Amended and Restated
Administrative Services Agreement with BEC, pursuant to which
BreitBurn Management agreed to continue to provide
administrative services to BEC, in exchange for a monthly fee
for indirect expenses. The monthly fee was set at $775,000 for
2008.
On August 26, 2008, members of our senior management, in
their individual capacities, together with Metalmark Capital
Partners (Metalmark), Greenhill Capital Partners
(Greenhill) and a third-party institutional
investor, completed the acquisition BEC. This transaction
included the acquisition of a 96.02 percent indirect
interest in BEC, previously owned by Provident Energy Trust
(Provident), and the remaining indirect interests in
BEC, previously owned by Randall H. Breitenbach, Halbert S.
Washburn and other members of our senior management. BEC is a
separate Delaware oil and gas partnership with operations in
California, was a separate U.S. subsidiary of Provident and
was our Predecessor.
In connection with the acquisition of Providents ownership
in BEC by members of senior management, Metalmark, Greenhill and
a third party institutional investor, BreitBurn Management
entered into the Second
127
Amended and Restated Administrative Services Agreement (the
Administrative Services Agreement) to manage
BECs properties for a term of five years. In addition to
the monthly fee, BreitBurn Management charges BEC for all direct
expenses including incentive plan costs and direct payroll and
administrative costs related to BEC properties and operations.
The monthly fee is contractually based on an annual projection
of anticipated time spent by each employee who provides services
to both us and BEC during the ensuing year and is subject to
renegotiation annually by the parties during the term of the
agreement. For 2009, each BreitBurn Management employee
estimated his or her time allocation independently based on
2008. These estimates were then reviewed and approved by each
employees manager or supervisor. The results of this
process were provided to both the audit committee of the board
of directors of our General Partner (composed entirely of
independent directors) (the audit committee) and the
board of representatives of BECs parent (the BEC
board). The audit committee and the non-management
members of the BEC board agreed on the 2009 monthly fee as
provided in the Administrative Services Agreement. Effective
January 1, 2009, the monthly fee was renegotiated to
$500,000. The reduction in the monthly fee is attributable to
the overall reduction in general and administrative expenses,
excluding unit-based compensation, for BreitBurn Management in
2009, the new time allocation study described above and the fact
that additional costs are being charged directly to us and BEC
compared to prior years. The monthly fee will be renegotiated
for 2010.
In addition, we entered into an Omnibus Agreement with BEC
detailing rights with respect to business opportunities and
providing us with a right of first offer with respect to the
sale of assets by BEC.
At December 31, 2009 and December 31, 2008, we had
current receivables of $1.4 million and $4.4 million,
respectively, due from BEC related to the Administrative
Services Agreement, outstanding liabilities for employee related
costs and oil and gas sales made by BEC on our behalf from
certain properties. During 2009, the monthly charges to BEC for
indirect expenses totaled $6.5 million and charges for
direct expenses including direct payroll and administrative
costs totaled $6.1 million. For the year ended
December 31, 2009, total oil and gas sales made by BEC on
our behalf were approximately $1.3 million. For the year
ended December 31, 2008, total oil and gas sales made by
BEC on our behalf were approximately $2.1 million. At
December 31, 2009 and 2008, we had receivables of
$0.3 million and $0.1 million, respectively, due from
certain of our affiliates for management fees due from equity
affiliates and operational expenses incurred on behalf of equity
affiliates.
Pursuant to a transition services agreement through March 2008,
Quicksilver provided to us services for accounting, land
administration, and marketing and charged us $0.9 million
for the first quarter of 2008. These charges were included in
general and administrative expenses on the consolidated
statements of operations. Quicksilver also buys natural gas
from us in Michigan. For the year ended December 31, 2009,
total net gas sales to Quicksilver were approximately
$2.8 million and the related receivable was
$0.4 million as of December 31, 2009. For the year
ended December 31, 2008, total net gas sales to Quicksilver
were approximately $8.0 million and the related receivable
was $0.6 million as of December 31, 2008.
On October 31, 2008, Quicksilver, an owner of approximately
40 percent of our Common Units, instituted a lawsuit in the
District Court of Tarrant County, Texas naming us as a defendant
along with others. The primary claims were as follows:
Quicksilver alleged that BOLP breached the Contribution
Agreement with Quicksilver, dated September 11, 2007, based
on allegations that we made false and misleading statements
relating to our relationship with Provident. Quicksilver also
alleged common law and statutory fraud claims against all of the
defendants by contending that the defendants made false and
misleading statements to induce Quicksilver to acquire Common
Units in us. Finally, Quicksilver also alleged claims for
breach of the Partnerships First Amended and Restated
Agreement of Limited Partnership, dated as of October 10,
2006 (Partnership Agreement), and other common law
claims relating to certain transactions and an amendment to the
Partnership Agreement that occurred in June 2008. Quicksilver
sought a permanent injunction, a declaratory judgment relating
primarily to the interpretation of the Partnership Agreement and
the voting rights in that agreement, indemnification, punitive
or exemplary damages, avoidance of BreitBurn GPs
assignment to us of all of its economic interest in us,
attorneys fees and costs, pre- and post-judgment interest,
and monetary damages.
128
In February 2010, we and Quicksilver agreed to settle all claims
with respect to the litigation filed by Quicksilver (the
Settlement). We expect the terms of the Settlement
to be implemented upon the dismissal of the lawsuit in Texas in
early April 2010. The parties have agreed to dismiss all
pending claims before the Court and have mutually released each
party, its affiliates, agents, officers, directors and attorneys
from any and all claims arising from the subject matter of the
pending case before the Court. We have also agreed to pay
Quicksilver $13.0 million and expect this amount to be paid
by insurance. In addition, Mr. Halbert S. Washburn and
Mr. Randall H. Breitenbach will resign from the Board of
Directors and the Board will appoint two new directors
designated by Quicksilver, one of whom will qualify as an
independent director and one of whom will be a current
independent board member now serving on Quicksilvers board
of directors, provided that such director not be a member of
Quicksilvers management.
At December 31, 2009, we recorded a $13.0 million
payable to Quicksilver in connection with the monetary portion
of the Settlement.
Mr. Greg L. Armstrong is the Chairman of the Board and
Chief Executive Officer of Plains All American GP LLC
(PAA). Mr. Armstrong was a director of our
General Partner until March 26, 2008 when his resignation
became effective. We sell all of the crude oil produced from
our Florida properties to Plains Marketing, L.P. (Plains
Marketing), a wholly owned subsidiary of PAA. In 2008,
prior to Mr. Armstrongs resignation on March 26,
2008, we sold $19.3 million of our crude oil to Plains
Marketing. At December 31, 2007, the receivable from
Plains Marketing was $10.5 million, which was collected in
the first quarter of 2008.
In Florida, crude oil inventory was $5.8 million and
$1.3 million at December 31, 2009 and 2008,
respectively. For the year ended December 31, 2009, we
sold 529 MBbls of crude oil and produced 590 MBbls
from our Florida operations. For the year ended
December 31, 2008, we sold 762 MBbls of crude oil and
produced 707 MBbls from our Florida operations. Crude oil
inventory additions are at cost and represent our production
costs. We match production expenses with crude oil sales.
Production expenses associated with unsold crude oil inventory
are recorded to inventory. Crude oil sales are a function of
the number and size of crude oil shipments in each quarter and
thus crude oil sales do not always coincide with volumes
produced in a given quarter.
We carry inventory at the lower of cost or market. When using
lower of cost or market to value inventory, market should not
exceed the net realizable value or the estimated selling price
less costs of completion and disposal. We assessed our
crude-oil inventory at December 31, 2009 and determined
that the carrying value of our inventory was below market value
and, therefore, no write-down was necessary. During the fourth
quarter of 2008, commodity prices decreased substantially. As a
result, we assessed our crude oil inventory and recorded
$1.2 million to write-down the Florida crude oil inventory
to our net realizable value at December 31, 2008.
For our properties in Florida, there are a limited number of
alternative methods of transportation for our production.
Substantially all of our oil production is transported by
pipelines, trucks and barges owned by third parties. The
inability or unwillingness of these parties to provide
transportation services for a reasonable fee could result in our
having to find transportation alternatives, increased
transportation costs, or involuntary curtailment of our oil
production, which could have a negative impact on our future
consolidated financial position, results of operations and cash
flows.
In May 2007, we acquired certain interests in oil leases and
related assets through the acquisition of a limited liability
company from Calumet Florida, L.L.C. As part of this
acquisition, we assumed certain crude oil sales contracts for
the remainder of 2007 and for 2008 through 2010. A
$3.4 million intangible asset was established to value the
portion of the crude oil contracts that were above market at
closing in the purchase price allocation. Realized gains or
losses from these contracts are recognized as part of oil sales
and the intangible asset will be amortized over the life of the
contracts. Amortization expense of $1.0 million for
129
2009 and 2008, respectively, is included in the oil, natural gas
and natural gas liquid sales line on the consolidated statements
of operations. As of December 31, 2009, our intangible
asset related to the crude oil sales contracts was
$0.5 million.
In November 2007, we acquired oil and gas properties and
facilities from Quicksilver. Included in the Quicksilver
purchase price was a $5.2 million intangible asset related
to retention bonuses. In connection with the acquisition, we
entered into an agreement with Quicksilver which provides for
Quicksilver to fund retention bonuses payable to 139 former
Quicksilver employees in the event these employees remain
continuously employed by BreitBurn Management from
November 1, 2007 through November 1, 2009 or in the
event of termination without cause, disability or death.
Amortization expense of $1.8 million and $2.1 million
for 2009 and 2008, respectively, is included in the total
operating expenses line on the consolidated statements of
operations. As of December 31, 2009, the intangible asset
related to these retention bonuses was fully amortized.
We had equity investments at December 31, 2009 and
December 31, 2008 of $8.2 million and
$9.5 million, respectively which primarily represent
investments in natural gas processing facilities. For the years
ended December 31, 2009 and 2008, we recorded less than
$0.1 million and $0.8 million, respectively, in
earnings from equity investments and $1.4 million and
$2.0 million, respectively, in dividends. Earnings from
equity investments are reported in the other revenue, net line
on the consolidated statements of operations.
At December 31, 2009, our equity investments consisted
primarily of a 24.5 percent limited partner interest and a
25.5 percent general partner interest in Wilderness Energy
Services LP, with a combined carrying value of
$7.0 million. The remaining $1.2 million consists of
smaller interests in several other investments. At
December 31, 2008, our equity investment totaled
$9.5 million. The decrease during 2009 is primarily due to
dividends received during the year.
On November 1, 2007, in connection with the Quicksilver
Acquisition, BOLP, as borrower, and we and our wholly owned
subsidiaries, as guarantors, entered into a four year,
$1.5 billion amended and restated revolving credit facility
with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC
and a syndicate of banks (the Amended and Restated Credit
Agreement).
The initial borrowing base of the Amended and Restated Credit
Agreement was $700 million and was increased to
$750 million on April 10, 2008. On June 17,
2008, in connection with the Purchase, Contribution and
Partnership Transactions, we and our wholly owned subsidiaries
entered into Amendment No. 1 to the Amended and Restated
Credit Agreement, with Wells Fargo Bank, National Association,
as administrative agent (the Agent). Amendment
No. 1 to the Credit Agreement increased the borrowing base
available under the Amended and Restated Credit Agreement, from
$750 million to $900 million. Borrowings under the
Amended and Restated Credit Agreement are secured by
first-priority liens on and security interests in substantially
all of our and certain of our subsidiaries assets,
representing not less than 80 percent of the total value of
our oil and gas properties.
The credit facility contains customary covenants, including
restrictions on our ability to: incur additional indebtedness;
make certain investments, loans or advances; make distributions
to our unitholders (including the restriction on our ability to
make distributions unless after giving effect to such
distribution, our outstanding debt is less than 90 percent
of the borrowing base, and we have the ability to borrow at
least ten percent of the borrowing base while remaining in
compliance with all terms and conditions of our credit facility,
including the leverage ratio not exceeding 3.50 to 1.00 (which
is total indebtedness to EBITDAX); make dispositions or enter
into sales and leasebacks; or enter into a merger or sale of our
property or assets, including the sale or transfer of interests
in our subsidiaries.
130
EBITDAX is not a defined GAAP measure. Our credit facility
defines EBITDAX as net income plus interest expense and other
financing costs, income tax provision, depletion, depreciation
and amortization, unrealized loss or gain on derivative
instruments, non-cash unit based compensation expense, loss or
gain on sale of assets, cumulative effect of changes in
accounting principles, amortization of intangible sales
contracts and amortization of intangible asset related to
employment retention allowance, excluding adjusted EBITDAX
attributable to our BEPI limited partner interest and including
the cash distribution received from BEPI.
In addition, Amendment No. 1 to the Credit Agreement
enacted certain additional amendments, waivers and consents to
the Amended and Restated Credit Agreement and the related
Security Agreement, dated November 1, 2007, among BOLP,
certain of its subsidiaries and the Agent, necessary to permit
the Amendment No. 1 to the First Amended and Restated
Limited Partnership Agreement and the transactions consummated
in the Purchase, Contribution and Partnership Transactions.
Under Amendment No. 1 to the Credit Agreement, the interest
margins applicable to borrowings, the letter of credit fee and
the commitment fee under the Amended and Restated Credit
Agreement were increased by amounts ranging from 12.5 to
25 basis points.
The events that constitute an Event of Default (as defined in
the Amended and Restated Credit Agreement) include: payment
defaults; misrepresentations; breaches of covenants;
cross-default and cross-acceleration to certain other
indebtedness; adverse judgments against us in excess of a
specified amount; changes in management or control; loss of
permits; failure to perform under a material agreement; certain
insolvency events; assertion of certain environmental claims;
and occurrence of a material adverse effect. At
December 31, 2009 and December 31, 2008, we were in
compliance with the credit facilitys covenants.
In January 2009, we monetized certain in-the-money commodity
hedges for approximately $46 million, the net proceeds of
which were used to reduce outstanding borrowings under our
credit facility. In April 2009, in connection with a scheduled
redetermination, our borrowing base under our Amended and
Restated Credit Agreement was redetermined at
$760 million. In June 2009, we monetized additional
in-the-money commodity hedges for approximately
$25 million, the net proceeds of which were used to reduce
outstanding borrowings under our credit facility. As a result
of the monetization, our borrowing base was reset at
$735 million.
On July 17, 2009, we sold the Lazy JL Field for
$23 million in cash. The proceeds from this transaction
were used to reduce outstanding borrowings under our credit
facility and our borrowing base was reduced by $3 million
to $732 million.
In October 2009, in connection with our semi-annual borrowing
base redetermination, our borrowing base was reaffirmed at
$732 million. Our next semi-annual borrowing base
redetermination is scheduled for April 2010.
As of December 31, 2009 and December 31, 2008, we had
$559.0 million and $736.0 million, respectively, in
indebtedness outstanding under the credit facility, which will
mature on November 1, 2011. At December 31, 2009, we
had $173.0 million available under our borrowing base. At
December 31, 2009, the
1-month
LIBOR interest rate plus an applicable spread was
1.990 percent on the
1-month
LIBOR portion of $552.0 million and the prime rate plus an
applicable spread was 4.000 percent on the prime debt
portion of $7.0 million. The amounts reported on our
consolidated balance sheets for long-term debt approximate fair
value due to the variable nature of our interest rates.
At December 31, 2009 and 2008, we had $0.3 million in
letters of credit outstanding.
131
Our interest expense is detailed in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Credit agreement (including commitment fees)
|
|
$
|
15,532
|
|
|
$
|
26,534
|
|
|
$
|
5,876
|
|
Amortization of discount and deferred issuance costs
|
|
|
3,295
|
|
|
|
2,613
|
|
|
|
382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
18,827
|
|
|
$
|
29,147
|
|
|
$
|
6,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
28,350
|
|
|
$
|
29,767
|
|
|
$
|
3,545
|
|
|
|
13.
|
Asset
Retirement Obligation
|
Our asset retirement obligation is based on our net ownership in
wells and facilities and our estimate of the costs to abandon
and remediate those wells and facilities as well as our estimate
of the future timing of the costs to be incurred. The total
undiscounted amount of future cash flows required to settle our
asset retirement obligations is estimated to be
$257.4 million at December 31, 2009 and was
$256.8 million at December 31, 2008. Payments to
settle asset retirement obligations occur over the operating
lives of the assets, estimated to be from less than one year to
50 years. We expect our cash settlements to be
approximately $1.1 million and less than $0.1 million
for 2010 and 2012, respectively. Cash settlements for the years
after 2014 are expected to be $35.5 million. Estimated
cash flows have been discounted at our credit adjusted risk free
rate of seven percent and adjusted for inflation using a rate of
two percent. Our credit adjusted risk free rate is calculated
based on our cost of borrowing adjusted for the effect of our
credit standing and specific industry and business risk. Each
year we review and, to the extent necessary, revise our asset
retirement obligation estimates. During 2009, we obtained new
estimates to evaluate the cost of abandoning our properties. As
a result, we increased our ARO estimates by $4.9 million to
reflect recent costs incurred for plugging and abandonment
activities in Michigan and Florida.
ASC 820 Fair Value Measurements and Disclosures
establishes a fair value hierarchy that prioritizes the
inputs to valuation techniques into three broad levels based
upon how observable those inputs are. The highest priority of
Level 1 is given to unadjusted quoted prices in active
markets for identical assets or liabilities. Level 2
includes inputs other than quoted prices that are included in
Level 1, and can be derived from observable data, including
third party data providers. These inputs may also include
observable transactions in the market place. Level 3 is
given to unobservable inputs. We consider the inputs to our
asset retirement obligation valuation to be Level 3 as fair
value is determined using discounted cash flow methodologies
based on standardized inputs that are not readily observable in
public markets.
Changes in the asset retirement obligation for the years ended
December 31, 2009 and 2008 are presented in the following
table:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
Carrying amount, beginning of period
|
|
$
|
30,086
|
|
|
$
|
27,819
|
|
Liabilities settled in the current period
|
|
|
(470
|
)
|
|
|
(1,054
|
)
|
Revisions (a)
|
|
|
4,883
|
|
|
|
1,363
|
|
Acquisitions (dispositions) (b)
|
|
|
(252
|
)
|
|
|
-
|
|
Accretion expense
|
|
|
2,388
|
|
|
|
1,958
|
|
|
|
|
|
|
|
|
|
|
Carrying amount, end of period
|
|
$
|
36,635
|
|
|
$
|
30,086
|
|
|
|
|
|
|
|
|
|
|
(a) Increased cost estimates and revisions to reserve life.
(b) Relates to disposition of the Lazy JL Field.
At December 31, 2009, we had 52,784,201 Common Units
outstanding.
132
At December 31, 2009 and December 31, 2008, we had
6,700,000 units authorized for issuance under our
long-term
incentive compensation plans. At December 31, 2009 and
December 31, 2008, there were 2,961,659 and 1,422,171,
respectively, of partnership-based units outstanding that are
eligible to be paid in Common Units upon vesting.
In February 2009, 134,377 Common Units were issued to employees
under our 2006 Long-Term Incentive Plan.
In October 2009, 14,190 Common Units were issued to outside
directors for phantom units and distribution equivalent rights
which were granted in 2006 and vested in October 2009.
On June 17, 2008, we purchased 14,404,962 Common Units from
subsidiaries of Provident at $23.26 per unit, for a purchase
price of approximately $335 million. These units have been
cancelled and are no longer outstanding. This transaction was
accounted for as a repurchase of issued Common Units and a
cancellation of those Common Units. This transaction decreased
equity by $336.2 million, including $1.2 million in
capitalized transaction costs. We also purchased
Providents 95.55 percent limited liability company
interest in BreitBurn Management, which owned the General
Partner. Also on June 17, 2008, we entered into a
contribution agreement with the General Partner, BreitBurn
Management and BreitBurn Corporation, pursuant to which
BreitBurn Corporation contributed its 4.45 percent limited
liability company interest in BreitBurn Management to us in
exchange for 19,955 Common Units and BreitBurn Management
contributed its 100 percent limited liability company
interest in the General Partner to us. On the same date, we
entered into Amendment No. 1 to the First Amended and
Restated Agreement of Limited Partnership of the Partnership,
pursuant to which the economic portion of the General
Partners 0.66473 percent general partner interest in
us was eliminated. As a result of these transactions, the
General Partner and BreitBurn Management became our wholly owned
subsidiaries.
On December 22, 2008, we entered into a Unit Purchase
Rights Agreement, dated as of December 22, 2008 (the
Rights Agreement), between us and American Stock
Transfer & Trust Company LLC, as Rights Agent.
Under the Rights Agreement, each holder of Common Units at the
close of business on December 31, 2008 automatically
received a distribution of one unit purchase right (a
Right), which entitles the registered holder to
purchase from us one additional Common Unit at a price of $40.00
per Common Unit, subject to adjustment. We entered into the
Rights agreement to increase the likelihood that our unitholders
receive fair and equal treatment in the event of a takeover
proposal.
The issuance of the Rights was not taxable to the holders of the
Common Units, had no dilutive effect, will not affect our
reported earnings per Common Unit, and will not change the
method of trading the Common Units. The Rights will not trade
separately from the Common Units unless the Rights become
exercisable. The Rights will become exercisable if a person or
group acquires beneficial ownership of 20 percent or more
of the outstanding Common Units or commences, or announces its
intention to commence, a tender offer that could result in
beneficial ownership of 20 percent or more of the
outstanding Common Units. If the Rights become exercisable,
each Right will entitle holders, other than the acquiring party,
to purchase a number of Common Units having a market value of
twice the then- current exercise price of the Right. Such
provision will not apply to any person who, prior to the
adoption of the Rights Agreement, beneficially owns
20 percent or more of the outstanding Common Units until
such person acquires beneficial ownership of any additional
Common Units.
The Rights Agreement has a term of three years and will expire
on December 22, 2011, unless the term is extended, the
Rights are earlier redeemed or we terminate the Rights Agreement.
On May 24, 2007, we sold 4,062,500 Common Units, at a
negotiated purchase price of $32.00 per unit, to certain
investors (the Purchasers). We used
$108 million from such sale to fund the cash consideration
for the Calumet Acquisition and the remaining $22 million
of the proceeds was used to repay indebtedness under our credit
facility. Most of the debt repaid was associated with our first
quarter 2007 acquisition of the Lazy JL Field properties in
West Texas.
133
On May 25, 2007, we sold an additional 2,967,744 Common
Units to the same Purchasers at a negotiated purchase price of
$31.00 per unit. We used the proceeds of approximately
$92 million to fund the BEPI Acquisition, including the
termination of existing hedge contracts related to future
production from BEPI.
On November 1, 2007, we sold 16,666,667 Common Units, at a
negotiated purchase price of $27.00 per unit, to certain
investors in a third private placement. We used the proceeds
from such sale to fund a portion of the cash consideration for
the Quicksilver Acquisition. Also on November 1, 2007, we
issued 21,347,972 Common Units to Quicksilver as partial
consideration for the Quicksilver Acquisition as a private
placement.
In connection with the private placements of Common Units to
finance the Quicksilver Acquisition, we entered into
registration rights agreements with the institutional investors
in our private placements and Quicksilver to file shelf
registration statements to register the resale of the Common
Units sold or issued in the Private Placements and to use our
commercially reasonable efforts to cause the registration
statements to become effective with respect to the Common Units
sold to the institutional investors not later than
August 2, 2008 and, with respect to the Common Units issued
to Quicksilver, within one year from November 1, 2007.
Quicksilver was prohibited from selling any of the Common Units
issued to it prior to the first anniversary of November 1,
2007 or more than 50 percent of such Common Units prior to
18 months after November 1, 2007. In addition, the
agreements gave the institutional investors and Quicksilver
piggyback registration rights under certain circumstances.
These registration rights are transferable to affiliates of the
institutional investors and Quicksilver and, in certain
circumstances, to third parties.
On July 31, 2008, the registration statement relating to
the resale of the Common Units issued in the private placement
to the institutional investors was declared effective. On
October 28, 2008, the registration statement relating to
the resale of the Common Units issued in the private placement
to Quicksilver was declared effective.
Earnings
per Common Unit
ASC 260 Earnings per Share requires use of
the two-class method of computing earnings per unit
for all periods presented. The two-class method is
an earnings allocation formula that determines earnings per unit
for each class of Common Unit and participating security as if
all earnings for the period had been distributed. Unvested
restricted unit awards that earn non-forfeitable dividend rights
qualify as participating securities and, accordingly, are
included in the basic computation. Our unvested RPUs and CPUs
participate in dividends on an equal basis with Common Units;
therefore, there is no difference in undistributed earnings
allocated to each participating security. Accordingly, the
presentation below is prepared on a combined basis and is
presented as earnings per Common Unit.
The following is a reconciliation of net earnings and weighted
average units for calculating basic net earnings per Common Unit
and diluted net earnings per Common Unit. For the years ended
December 31, 2009 and 2007, RPUs and CPUs have been
excluded from the calculation of basic earnings per unit, as we
were in a net loss position.
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands, except per unit
amounts
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Net income (loss) attributable to limited partners
|
|
$
|
(107,290
|
)
|
|
$
|
380,255
|
|
|
$
|
(59,685
|
)
|
Distributions on participating units not expected to vest
|
|
|
-
|
|
|
|
22
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common unitholders and
participating securities
|
|
$
|
(107,290
|
)
|
|
$
|
380,277
|
|
|
$
|
(59,685
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of units used to calculate basic and
diluted net income (loss) per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units
|
|
|
52,757
|
|
|
|
59,239
|
|
|
|
32,577
|
|
Participating securities (a)
|
|
|
-
|
|
|
|
1,184
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per Common Unit
|
|
|
52,757
|
|
|
|
60,423
|
|
|
|
32,577
|
|
Dilutive units (b)
|
|
|
-
|
|
|
|
142
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per Common Unit
|
|
|
52,757
|
|
|
|
60,565
|
|
|
|
32,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common unit
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(2.03
|
)
|
|
$
|
6.29
|
|
|
$
|
(1.83
|
)
|
Diluted
|
|
$
|
(2.03
|
)
|
|
$
|
6.28
|
|
|
$
|
(1.83
|
)
|
(a) The year ended December 31, 2009 excludes
2,636,800 of potentially issuable weighted average RPUs and CPUs
from participating securities, as we were in a loss position.
For the year ended December 31, 2008, basic earnings per
unit is based upon the weighted average number of Common Units
outstanding plus the weighted average number of potentially
issuable RPUs and CPUs. The year ended December 31, 2007
had no potentially issuable weighted average RPUs and CPUs from
participating securities.
(b) The years ended December 31, 2009 and 2007 exclude
102,090 and 150,813, respectively, of weighted average
anti-dilutive
units from the calculation of the denominator for diluted
earnings per Common Unit. Weighted average dilutive units for
the year ended December 31, 2008 include units potentially
issuable under compensation plans that do not qualify as
participating securities.
Cash
Distributions
The partnership agreement requires us to distribute all of our
available cash quarterly. Available cash is cash on hand,
including cash from borrowings, at the end of a quarter after
the payment of expenses and the establishment of reserves for
future capital expenditures and operational needs. We may fund
a portion of capital expenditures with additional borrowings or
issuances of additional units. We may also borrow to make
distributions to unitholders, for example, in circumstances
where we believe that the distribution level is sustainable over
the long term, but short-term factors have caused available cash
from operations to be insufficient to pay the distribution at
the current level. The partnership agreement does not restrict
our ability to borrow to pay distributions. The cash
distribution policy reflects a basic judgment that unitholders
will be better served by us distributing our available cash,
after expenses and reserves, rather than retaining it.
Distributions are not cumulative. Consequently, if
distributions on Common Units are not paid with respect to any
fiscal quarter at the initial distribution rate, our unitholders
will not be entitled to receive such payments in the future.
Distributions are paid within 45 days of the end of each
fiscal quarter to holders of record on or about the first or
second week of each such month. If the distribution date does
not fall on a business day, the distribution will be made on the
business day immediately preceding the indicated distribution
date.
We do not have a legal obligation to pay distributions at any
rate except as provided in the partnership agreement. Our
distribution policy is consistent with the terms of our
partnership agreement, which requires that we distribute all of
our available cash quarterly. Under the partnership agreement,
available cash is defined to generally mean, for each fiscal
quarter, cash generated from our business in excess of the
amount of
135
reserves the General Partner determines is necessary or
appropriate to provide for the conduct of the business, to
comply with applicable law, any of its debt instruments or other
agreements or to provide for future distributions to its
unitholders for any one or more of the upcoming four quarters.
The partnership agreement provides that any determination made
by the General Partner in its capacity as general partner must
be made in good faith and that any such determination will not
be subject to any other standard imposed by the partnership
agreement, the Delaware limited partnership statute or any other
law, rule or regulation or at equity.
On February 13, 2009, we paid a cash distribution of
approximately $27.4 million to our common unitholders of
record as of the close of business on February 9, 2009.
The distribution that was paid to unitholders was $0.52 per
Common Unit. During the three months ended March 31, 2009,
we also paid cash equivalent to the distribution paid to our
unitholders of $0.7 million to holders of outstanding
Restricted Phantom Units and Convertible Phantom Units issued
under our Long-Term Incentive Plans.
With the borrowing base redetermination in April 2009 (see
Note 12), our borrowings exceeded 90 percent of the
reset borrowing base and, therefore, under the terms of our
credit facility we were restricted from making a distribution
for the first quarter of 2009. Although we were not restricted
from making distributions under the terms of our credit facility
for the second, third and fourth quarters of 2009, we elected
not to declare distributions in light of total leverage levels
and other factors. We are restricted from paying distributions
under our credit facility unless, after giving effect to such
distribution, our outstanding debt is less than 90 percent
of the borrowing base and we have the ability to borrow at least
ten percent of the borrowing base while remaining in compliance
with all terms and conditions of our credit facility, including
the leverage ratio not exceeding 3.50 to 1.00 (which is total
indebtedness to EBITDAX).
|
|
15.
|
Noncontrolling
interest
|
ASC 810 Consolidation requires that
noncontrolling interests be classified as a component of equity
and establishes reporting requirements that provide sufficient
disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the noncontrolling
owners.
On May 25, 2007, we acquired the limited partner interest
(99 percent) of BEPI from TIFD. As such, we are fully
consolidating the results of BEPI and thus are recognizing a
noncontrolling interest representing the book value of the
general partners interests. At December 31, 2009 and
December 31, 2008, the amount of this noncontrolling
interest was $0.4 million and $0.5 million,
respectively. For the years ended December 31, 2009 and
2008, we recorded net income attributable to the noncontrolling
interest of less than $0.1 million and $0.2 million,
respectively, and $0.1 million and $0.2 million,
respectively, in dividends.
BEPIs general partner interest is held by a wholly owned
subsidiary of BEC. The general partner of BEPI holds a
35 percent reversionary interest under the existing limited
partnership agreement applicable to the properties. This
reversionary interest is expected to occur at a defined payout,
which is estimated to occur in 2015 based on year-end price and
cost projections.
|
|
16.
|
Financial
Instruments
|
Fair
Value of Financial Instruments
Our risk management programs are intended to reduce our exposure
to commodity prices and interest rates and to assist with
stabilizing cash flow. Routinely, we utilize derivative
financial instruments to reduce this volatility. To the extent
we have hedged prices for a significant portion of our expected
production through commodity derivative instruments and the cost
for goods and services increase, our margins would be adversely
affected.
Credit
and Counterparty Risk
Financial instruments which potentially subject us to
concentrations of credit risk consist principally of derivatives
and accounts receivable. Our derivatives expose us to credit
risk from counterparties. As of December 31, 2009, our
derivative counterparties were Barclays Bank PLC, Bank of
Montreal, Citibank, N.A,
136
Credit Suisse International, Credit Suisse Energy LLC, Union
Bank N.A, Wells Fargo Bank N.A., JP Morgan Chase Bank N.A.,
Royal Bank of Scotland plc, The Bank of Nova Scotia and
Toronto-Dominion Bank. We terminated all derivative financial
instruments with Lehman Brothers on September 19, 2008.
Our counterparties are all lenders under our Amended and
Restated Credit Agreement. During 2008, there was extreme
volatility and disruption in the capital and credit markets
which reached unprecedented levels. Continued volatility and
disruption may adversely affect the financial condition of our
derivative counterparties. On all transactions where we are
exposed to counterparty risk, we analyze the counterpartys
financial condition prior to entering into an agreement,
establish limits, and monitor the appropriateness of these
limits on an ongoing basis. We periodically obtain credit
default swap information on our counterparties. Although we
currently do not believe we have a specific counterparty risk
with any party, our loss could be substantial if any of these
parties were to fail to perform in accordance with the terms of
the contract. This risk is managed by diversifying the
derivative portfolio. As of December 31, 2009, each of
these financial institutions carried an S&P credit rating
of A or above. As of December 31, 2009, our largest
derivative asset balances were with JP Morgan Chase Bank
N.A., who accounted for approximately 64 percent of our
derivative asset balances, and Credit Suisse International and
Credit Suisse Energy LLC, who together accounted for
approximately 26 percent of our derivative asset balances.
Commodity
Activities
The derivative instruments we utilize are based on index prices
that may and often do differ from the actual crude oil and
natural gas prices realized in our operations. These variations
often result in a lack of adequate correlation to enable these
derivative instruments to qualify for cash flow hedges under ASC
815 Derivatives and Hedging. Accordingly, we
do not attempt to account for our derivative instruments as cash
flow hedges for financial reporting purposes and instead
recognize changes in the fair value immediately in earnings. We
had a realized gain of $167.7 million and an unrealized
loss of $219.1 million for the year ended December 31,
2009 relating to our various market-based commodity contracts.
We had a net derivative asset relating to our commodity
contracts of $73.2 million at December 31, 2009.
In January 2009, we terminated a portion of our 2011 and 2012
crude oil derivative contracts and replaced them with new
contracts with the same counterparty for the same volumes at
market prices. We realized $32.3 million from this
termination. In January 2009, we also terminated a portion of
our 2011 and 2012 natural gas derivative contracts and replaced
them with new contracts with the same counterparty for the same
volumes at market prices. We realized $13.3 million from
this termination. Proceeds from these contracts were used to
pay down outstanding borrowings under our credit facility.
In June 2009, we terminated an additional portion of our 2011
and 2012 crude oil and natural gas derivative contracts and
replaced them with new contracts for the same volumes at market
prices. We realized $18.9 million from the termination of
natural gas derivative contracts and $6.1 million from the
termination of crude oil contracts. Proceeds from these
contracts were used to pay down outstanding borrowings under our
credit facility.
For the year ended December 31, 2008, we had realized
losses of $55.9 million and unrealized gains of
$388.0 million relating to our market based commodity
contracts. We had net financial instruments receivable relating
to our commodity contracts of $292.3 million at
December 31, 2008. On September 19, 2008, due to
Lehman Brothers bankruptcy, we terminated our crude oil
derivative instruments with Lehman Brothers. Our derivative
contract with Lehman Brothers, commonly referred to as a
zero cost collar, was for oil volumes of
1,000 Bbls/d for the full year 2011. This represented
approximately eight percent of our total 2011 oil and natural
gas hedge portfolio. The floor price for the collar was $105.00
per Bbl and the ceiling price was $174.50 per Bbl. This
contract was replaced by contracts with substantially similar
terms, with different counterparties, for oil volumes of
1,000 Bbls/d covering January 1, 2011 to
January 31, 2011 and March 1, 2011 to
December 31, 2011.
For the year ended December 31, 2007, we had realized
losses of $6.6 million and unrealized losses of
$103.9 million relating to our market based commodity
contracts.
137
Including the impact of the changes noted above we had the
following contracts in place at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
Gas Positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (MMBtu/d)
|
|
|
43,869
|
|
|
|
25,955
|
|
|
|
19,129
|
|
|
|
27,000
|
|
|
|
-
|
|
Average Price ($/MMBtu)
|
|
$
|
8.20
|
|
|
$
|
7.26
|
|
|
$
|
7.10
|
|
|
$
|
6.92
|
|
|
$
|
-
|
|
Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (MMBtu/d)
|
|
|
3,405
|
|
|
|
16,016
|
|
|
|
19,129
|
|
|
|
-
|
|
|
|
-
|
|
Average Floor Price ($/MMBtu)
|
|
$
|
9.00
|
|
|
$
|
9.00
|
|
|
$
|
9.00
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Average Ceiling Price ($/MMBtu)
|
|
$
|
12.79
|
|
|
$
|
11.28
|
|
|
$
|
11.89
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (MMBtu/d)
|
|
|
47,275
|
|
|
|
41,971
|
|
|
|
38,257
|
|
|
|
27,000
|
|
|
|
-
|
|
Average Price ($/MMBtu)
|
|
$
|
8.26
|
|
|
$
|
7.92
|
|
|
$
|
8.05
|
|
|
$
|
6.92
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (Bbls/d)
|
|
|
2,808
|
|
|
|
2,616
|
|
|
|
2,539
|
|
|
|
3,500
|
|
|
|
748
|
|
Average Price ($/Bbl)
|
|
$
|
81.35
|
|
|
$
|
66.22
|
|
|
$
|
67.24
|
|
|
$
|
76.79
|
|
|
$
|
88.65
|
|
Participating Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (Bbls/d)
|
|
|
1,993
|
|
|
|
1,439
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Average Price ($/Bbl)
|
|
$
|
64.40
|
|
|
$
|
61.29
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Average Participation %
|
|
|
55.5
|
%
|
|
|
53.2
|
%
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (Bbls/d)
|
|
|
1,279
|
|
|
|
2,048
|
|
|
|
2,477
|
|
|
|
500
|
|
|
|
-
|
|
Average Floor Price ($/Bbl)
|
|
$
|
102.85
|
|
|
$
|
103.42
|
|
|
$
|
110.00
|
|
|
$
|
77.00
|
|
|
$
|
-
|
|
Average Ceiling Price ($/Bbl)
|
|
$
|
136.16
|
|
|
$
|
152.61
|
|
|
$
|
145.39
|
|
|
$
|
103.10
|
|
|
$
|
-
|
|
Floors:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (Bbls/d)
|
|
|
500
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Average Floor Price ($/Bbl)
|
|
$
|
100.00
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (Bbls/d)
|
|
|
6,580
|
|
|
|
6,103
|
|
|
|
5,016
|
|
|
|
4,000
|
|
|
|
748
|
|
Average Price ($/Bbl)
|
|
$
|
81.81
|
|
|
$
|
77.54
|
|
|
$
|
88.35
|
|
|
$
|
76.82
|
|
|
$
|
88.65
|
|
(a) A participating swap combines a swap and a call option
with the same strike price.
Interest
Rate Activities
We are subject to interest rate risk associated with loans under
our credit facility that bear interest based on floating rates.
As of December 31, 2009, our total debt outstanding was
$559 million. In order to mitigate
138
our interest rate exposure, we had the following interest rate
swaps in place at December 31, 2009, to fix a portion of
floating
LIBOR-base
debt on our credit facility:
|
|
|
|
|
|
|
|
|
Notional amounts in
thousands of dollars
|
|
Notional Amount
|
|
|
Fixed Rate
|
|
Period Covered
|
|
|
|
|
|
|
|
|
January 1, 2010 to January 8, 2010
|
|
$
|
100,000
|
|
|
|
3.3873%
|
|
January 1, 2010 to December 20, 2010
|
|
|
300,000
|
|
|
|
3.6825%
|
|
January 20, 2010 to October 20, 2011
|
|
|
100,000
|
|
|
|
1.6200%
|
|
December 20, 2010 to October 20, 2011
|
|
|
200,000
|
|
|
|
2.9900%
|
|
For the year ended December 31, 2009, we had realized
losses of $13.1 million and unrealized gains of
$5.9 million relating to our interest rate swaps. We had
net financial instruments payable related to our interest rate
swaps of $11.4 million at December 31, 2009.
For the year ended December 31, 2008, we had realized
losses of $2.7 million and unrealized losses of
$17.3 million relating to our interest rate swaps. We had
net financial instruments payable related to our interest rate
swaps of $17.3 million at December 31, 2008. On
September 19, 2008, due to Lehman Brothers
bankruptcy, we terminated, at no cost, our interest rate swap
with Lehman Brothers for $50 million at a fixed rate of
3.438 percent, which covered the period from
January 8, 2008 to July 8, 2009. On October 2,
2008, we entered into a new interest rate swap for
$50 million at a fixed rate of 3.0450 percent, for the
period from September 8, 2008 to July 8, 2009.
ASC 815 requires disclosures about how and why an entity uses
derivative instruments, how derivative instruments and related
hedge items are accounted for under ASC 815, and how derivative
instruments and related hedged items affect an entitys
financial position, financial performance, and cash flows. This
topic requires the disclosures detailed below.
Fair value of derivative instruments not designated as hedging
instruments under ASC 815:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Interest
|
|
|
Commodity
|
|
|
Total
|
|
|
|
Commodity
|
|
|
Commodity
|
|
|
Rate
|
|
|
derivative
|
|
|
Financial
|
|
Balance sheet location, thousands of dollars
|
|
Derivatives
|
|
|
Derivatives
|
|
|
Derivatives
|
|
|
netting (a)
|
|
|
Instruments
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets - derivative instruments
|
|
$
|
17,666
|
|
|
$
|
39,467
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
57,133
|
|
Other long-term assets - derivative instruments
|
|
|
35,382
|
|
|
|
42,620
|
|
|
|
-
|
|
|
|
(3,243)
|
|
|
|
74,759
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
53,048
|
|
|
|
82,087
|
|
|
|
-
|
|
|
|
(3,243)
|
|
|
|
131,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities - derivative instruments
|
|
|
(10,234
|
)
|
|
|
-
|
|
|
|
(9,823
|
)
|
|
|
-
|
|
|
|
(20,057
|
)
|
Long-term liabilities - derivative instruments
|
|
|
(51,730
|
)
|
|
|
-
|
|
|
|
(1,622
|
)
|
|
|
3,243
|
|
|
|
(50,109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
(61,964
|
)
|
|
|
-
|
|
|
|
(11,445
|
)
|
|
|
3,243
|
|
|
|
(70,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
(8,916
|
)
|
|
$
|
82,087
|
|
|
$
|
(11,445
|
)
|
|
$
|
-
|
|
|
$
|
61,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets - derivative instruments
|
|
$
|
44,086
|
|
|
$
|
32,138
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
76,224
|
|
Other long-term assets - derivative instruments
|
|
|
145,061
|
|
|
|
73,942
|
|
|
|
-
|
|
|
|
-
|
|
|
|
219,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
189,147
|
|
|
|
106,080
|
|
|
|
-
|
|
|
|
-
|
|
|
|
295,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities - derivative instruments
|
|
|
(1,115
|
)
|
|
|
-
|
|
|
|
(9,077
|
)
|
|
|
-
|
|
|
|
(10,192
|
)
|
Long-term liabilities - derivative instruments
|
|
|
(1,820
|
)
|
|
|
-
|
|
|
|
(8,238
|
)
|
|
|
-
|
|
|
|
(10,058
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
(2,935
|
)
|
|
|
-
|
|
|
|
(17,315
|
)
|
|
|
-
|
|
|
|
(20,250
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
186,212
|
|
|
$
|
106,080
|
|
|
$
|
(17,315
|
)
|
|
$
|
-
|
|
|
$
|
274,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
139
|
|
|
(a)
|
|
Represents counterparty netting
under derivative netting agreements these contracts
are reflected net on the balance sheet.
|
Gains and losses on derivative instruments not designated as
hedging instruments under ASC 815:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Natural Gas
|
|
|
|
Total
|
|
|
Commodity
|
|
Commodity
|
|
Interest Rate
|
|
Financial
|
Location of gain/loss,
thousands of dollars
|
|
Derivatives (a)
|
|
Derivatives (a)
|
|
Derivatives (b)
|
|
Instruments
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gains (losses)
|
|
|
66,176
|
|
|
101,507
|
|
|
(13,115)
|
|
$
|
154,568
|
Unrealized gains (losses)
|
|
|
(195,127)
|
|
|
(23,993)
|
|
|
5,869
|
|
|
(213,251)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gains (losses)
|
|
$
|
(128,951)
|
|
$
|
77,514
|
|
$
|
(7,246)
|
|
$
|
(58,683)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized losses
|
|
$
|
(35,146)
|
|
$
|
(20,800)
|
|
$
|
(2,721)
|
|
$
|
(58,667)
|
Unrealized gains (losses)
|
|
|
293,720
|
|
|
94,328
|
|
|
(17,314)
|
|
|
370,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gains (losses)
|
|
$
|
258,574
|
|
$
|
73,528
|
|
$
|
(20,035)
|
|
$
|
312,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Included in gains (losses) on commodity derivative instruments
on the consolidated statements of operations. |
(b) |
|
Included in loss on interest rate swaps on the consolidated
statements of operations. |
Effective January 1, 2008, we adopted
SFAS No. 157, Fair Value Measurements, now
codified within ASC 820 Fair Value Measurements and
Disclosures. ASC 820 defines fair value, establishes a
framework for measuring fair value and establishes required
disclosures about fair value measurements. Fair value
measurement under ASC 820 is based upon a hypothetical
transaction to sell an asset or transfer a liability at the
measurement date, considered from the perspective of a market
participant that holds the asset or owes the liability. The
objective of fair value measurement as defined in ASC 820 is to
determine the price that would be received in selling the asset
or transferring the liability in an orderly transaction between
market participants at the measurement date. If there is an
active market for the asset or liability, the fair value
measurement shall represent the price in that market whether the
price is directly observable or otherwise obtained using a
valuation technique.
ASC 820 requires valuation techniques consistent with the market
approach, income approach or cost approach to be used to measure
fair value. The market approach uses prices and other relevant
information generated by market transactions involving identical
or comparable assets or liabilities. The income approach uses
valuation techniques to convert future cash flows or earnings to
a single present value amount and is based upon current market
expectations about those future amounts. The cost approach,
sometimes referred to as the current replacement cost approach,
is based upon the amount that would currently be required to
replace the service capacity of an asset.
We principally use the income approach for our recurring fair
value measurements and strive to use the best information
available. We use valuation techniques that maximize the use of
observable inputs and obtain the majority of our inputs from
published objective sources or third party market participants.
We incorporate the impact of nonperformance risk, including
credit risk, into our fair value measurements.
ASC 820 also establishes a fair value hierarchy that prioritizes
the inputs to valuation techniques into three broad levels based
upon how observable those inputs are. The highest priority of
Level 1 is given to unadjusted quoted prices in active
markets for identical assets or liabilities and the lowest
priority of Level 3 is given to unobservable inputs. We
categorize our fair value financial instruments based upon the
objectivity of the inputs and how observable those inputs are.
The three levels of inputs as defined in ASC 820 are described
further as follows:
Level 1 Unadjusted quoted prices in active
markets for identical assets or liabilities as of the reporting
date. Active markets are markets in which transactions for the
asset or liability occur with sufficient frequency
140
and volume to provide pricing information on an ongoing basis.
An example of a Level 1 input would be quoted prices for
exchange traded commodity futures contracts.
Level 2 Inputs other than quoted prices that
are included in Level 1. Level 2 includes financial
instruments that are actively traded but are valued using models
or other valuation methodologies. These models include industry
standard models that consider standard assumptions such as
quoted forward prices for commodities, interest rates,
volatilities, current market and contractual prices for
underlying assets as well as other relevant factors.
Substantially all of these inputs are evident in the market
place throughout the terms of the financial instruments and can
be derived by observable data, including third party data
providers. These inputs may also include observable
transactions in the market place. We consider the over the
counter (OTC) commodity and interest rate swaps in
our portfolio to be Level 2. These are assets and
liabilities that can be bought and sold in active markets and
quoted prices are available from multiple potential
counterparties.
Level 3 Inputs that are not directly observable
for the asset or liability and are significant to the fair value
of the asset or liability. These inputs generally reflect
managements estimates of the assumptions market
participants would use when pricing the instruments.
Level 3 includes financial instruments that are not
actively traded and have little or no observable data for input
into industry standard models. Level 3 instruments
primarily include derivative instruments for which we do not
have sufficient corroborating market evidence, such as binding
broker quotes, to support classifying the asset or liability as
Level 2. Level 3 also includes complex structured
transactions that sometimes require the use of non-standard
models.
Certain OTC derivatives that trade in less liquid markets or
contain limited observable model inputs are currently included
in Level 3. We include these assets and liabilities in
Level 3 as required by current interpretations of ASC 820.
As of December 31, 2009 and December 31, 2008, our
Level 3 derivative assets and liabilities consisted
entirely of OTC commodity put and call options.
Financial assets and liabilities that are categorized in
Level 3 may later be reclassified to the Level 2
category at the point we are able to obtain sufficient binding
market data or the interpretation of Level 2 criteria is
modified in practice to include non-binding market corroborated
data.
Through December 2009, we contracted with Provident on a
month-to-month basis for certain derivative instrument valuation
services. Providents risk management group calculated the
fair values of our commodity and interest rate hedges using
software that marks to market our hedge contracts using forward
commodity price curves and interest rates. Inputs were obtained
from third party data providers and were verified to published
data where available (e.g., NYMEX).
Beginning in the fourth quarter of 2009, our Treasury/Risk
Management group began calculating the fair value of our
commodity and interest rate swaps and options. For the fourth
quarter of 2009, we compared our fair value calculations to
those received from the counterparties to our derivative
instruments and to those received from Provident, our former
fair valuation provider, and determined that our valuation
results were consistent with those of our counterparties and
Provident. As such, we used our valuation for December 31,
2009. Beginning January 1, 2010, we no longer obtain fair
value calculations for our derivative instruments from
Provident, but calculate them internally and continue to compare
these fair value amounts to the fair value amounts that we
receive from the counterparties on a monthly basis. Any
differences will be resolved and any required changes will be
recorded prior to the issuance of our financial statements.
The model we utilize to calculate the fair value of our
commodity derivative instruments is a standard option pricing
model. Inputs to the option pricing models include fixed
monthly commodity strike prices and volumes from each specific
contract, commodity prices from commodity forward price curves,
volatility and interest rate factors and time to expiry. Model
inputs are obtained from our counterparties and third party data
providers and are verified to published data where available
(e.g., NYMEX).
Financial assets and liabilities carried at fair value on a
recurring basis are presented in the table below. Our
assessment of the significance of an input to its fair value
measurement requires judgment and can affect the valuation of
the assets and liabilities as well as the category within which
they are categorized.
141
Recurring fair value measurements at December 31, 2009 and
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
Thousands of
dollars
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets (Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives (swaps, put and call options)
|
|
$
|
-
|
|
|
$
|
(29,303
|
)
|
|
$
|
102,475
|
|
|
$
|
73,172
|
|
Other Derivatives (interest rate swaps)
|
|
|
-
|
|
|
|
(11,446
|
)
|
|
|
-
|
|
|
|
(11,446
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
-
|
|
|
$
|
(40,749
|
)
|
|
$
|
102,475
|
|
|
$
|
61,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,2008
|
|
Thousands of
dollars
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets (Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivatives (swaps, put and call options)
|
|
$
|
-
|
|
|
$
|
139,074
|
|
|
$
|
153,218
|
|
|
$
|
292,292
|
|
Other Derivatives (interest rate swaps)
|
|
|
-
|
|
|
|
(17,315
|
)
|
|
|
-
|
|
|
|
(17,315
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
-
|
|
|
$
|
121,759
|
|
|
$
|
153,218
|
|
|
$
|
274,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation primarily of
changes in fair value of our derivative instruments classified
as Level 3:
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
Thousands of
dollars
|
|
2009
|
|
2008
|
|
Assets (Liabilities):
|
|
|
|
|
|
|
Beginning balance
|
|
$
|
153,218
|
|
$
|
44,236
|
Realized and unrealized gains (losses)
|
|
|
(44,713)
|
|
|
106,154
|
Purchases and issuances
|
|
|
-
|
|
|
7,452
|
Settlements (a)
|
|
|
(6,030)
|
|
|
(4,624)
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
102,475
|
|
$
|
153,218
|
|
|
|
|
|
|
|
(a) Settlements reflect the monetization of oil collar
contracts in June 2009 and the termination of derivative
contracts with Lehman in September 2008 due to the Lehman
bankruptcy.
Unrealized losses of $63.8 million for the year ended
December 31, 2009 related to our derivative instruments
classified as Level 3 are included in Gains (losses) on
commodity derivative instruments, net on the consolidated
statements of operations. Realized gains of $19.1 million
for the year ended December 31, 2009 related to our
derivative instruments classified as Level 3 are also
included in gains (losses) on commodity derivative instruments,
net on the consolidated statements of operations. Unrealized
gains of $112.2 million for the year ended
December 31, 2008 related to our derivative instruments
classified as Level 3 are included in gains (losses) on
commodity derivative instruments, net on the consolidated
statements of operations. Realized losses of $6.0 million
for the year ended December 31, 2008 related to our
derivative instruments classified as Level 3 are also
included in gains (losses) on commodity derivative instruments,
net on the consolidated statements of operations. Determination
of fair values incorporates various factors as required by ASC
820 including, but not limited to, the credit standing of the
counterparties, the impact of guarantees as well as our own
abilities to perform on our liabilities.
|
|
17.
|
Unit and
Other Valuation-Based Compensation Plans
|
BreitBurn Management operates our assets and performs other
administrative services for us such as accounting, corporate
development, finance, land administration, legal and
engineering. All of our employees, including our executives,
are employees of BreitBurn Management. On June 17, 2008,
in connection with the Purchase, Contribution and Partnership
Transactions, BreitBurn Management became our wholly owned
subsidiary and entered into an Amended and Restated
Administrative Services Agreement with BEC, pursuant
142
to which BreitBurn Management agreed to continue to provide
administrative services to BEC. In addition, BreitBurn
Management agreed to continue to charge BEC for direct expenses,
including incentive plan costs and direct payroll and
administrative costs. Beginning on June 17, 2008, all of
BreitBurn Managements costs that were not charged to BEC
are consolidated with our results.
Prior to June 17, 2008, BreitBurn Management provided
services to us and to BEC, and allocated its expenses between
the two entities. We were managed by our General Partner, the
executive officers of which were and are employees of BreitBurn
Management. We had entered into an Administrative Services
Agreement with BreitBurn Management. Under the Administrative
Services Agreement, we reimbursed BreitBurn Management for all
direct and indirect expenses it incurred in connection with the
services it performed on our behalf (including salary, bonus,
certain incentive compensation and other amounts paid to
executive officers and other employees).
Effective on the initial public offering date of
October 10, 2006, BreitBurn Management adopted the existing
Long- Term Incentive Plan (BreitBurn Management LTIP) and the
Unit Appreciation Rights Plan (UAR plan) of the predecessor as
previously amended. The predecessors Executive Phantom
Option Plan, Unit Appreciation Plan for Officers and Key
Individuals (Founders Plan), and the Performance
Trust Units awarded to the Chief Financial Officer during
2006 under the BreitBurn Management LTIP, were adopted by
BreitBurn Management with amendments at the initial public
offering date as described in the subject plan discussions below.
We may terminate or amend the long-term incentive plan at any
time with respect to any units for which a grant has not yet
been made. We also have the right to alter or amend the
long-term incentive plan or any part of the plan from time to
time, including increasing the number of units that may be
granted subject to the requirements of the exchange upon which
the Common Units are listed at that time. However, no change in
any outstanding grant may be made that would materially reduce
the rights or benefits of the participant without the consent of
the participant. The plan will expire when units are no longer
available under the plan for grants or, if earlier, it is
terminated by us.
Unit
Based Compensation
ASC 718 Compensation Stock
Compensation establishes standards for charging
compensation expenses based on fair value provisions. At
December 31, 2009, the Restricted Phantom Units (RPUs) and
the Convertible Phantom Units (CPUs) granted under the BreitBurn
Management LTIP as well as the outstanding Directors RPUs
discussed below were all classified as equity awards under the
provisions of ASC 718. These awards are being recognized
as compensation expense on a straight line basis over the annual
vesting periods as prescribed in the award agreements.
Prior year awards classified as liabilities were revalued at
each reporting period using the Black-Scholes option pricing
model and changes in the fair value of the options were
recognized as compensation expense over the vesting schedules of
the awards. These awards were settled in cash or had the option
of being settled in cash or units at the choice of the holder,
and were indexed to either our Common Units or to Provident
Trust Units. The liability-classified option awards were
distribution-protected awards through either an Adjustment Ratio
as defined in the plan or the holders received cumulative
distribution amounts upon vesting equal to the actual
distribution amounts per Common Unit of the underlying notional
Units.
In connection with the changes to BreitBurn Managements
executive compensation program during 2007, employees of
BreitBurn Management began to receive two new types of awards
under our LTIP, namely, Restricted Phantom Units (RPUs) and
Convertible Phantom Units (CPUs).
We recognized $12.7 million of compensation expense related
to our various plans for the year ended December 31, 2009.
Restricted
Phantom Units (RPUs)
RPUs are phantom equity awards that, to the extent vested,
represent the right to receive actual partnership units upon
specified payment events. Certain employees of BreitBurn
Management including its
143
executives are eligible to receive RPU awards. We believe that
RPUs properly incentivize holders of these awards to grow stable
distributions for our common unitholders. RPUs generally vest
in three equal annual installments on each anniversary of the
vesting commencement date of the award. In addition, each RPU
is granted in tandem with a distribution equivalent right that
will remain outstanding from the grant of the RPU until the
earlier to occur of its forfeiture or the payment of the
underlying unit, and which entitles the grantee to receive
payment of amounts equal to distributions paid to each holder of
an actual partnership unit during such period. RPUs that do not
vest for any reason are forfeited upon a grantees
termination of employment.
RPU awards were granted to BreitBurn Management employees in
2009, 2008 and 2007 as shown in the table below. We recorded
compensation expense of $9.1 million in 2009,
$3.4 million in 2008 and $7.0 million in 2007. As of
December 31, 2009, there was $13.7 million of total
unrecognized compensation cost remaining for the unvested RPUs.
This amount is expected to be recognized over the remaining two
year vesting period.
Compensation expense recorded in 2009 and 2008 relates to the
amortization of outstanding RPUs over their related vesting
periods. Compensation expense of $7.0 million recorded in
2007 was primarily due to the exchange of executive phantom
options awards for RPUs in 2007. Pursuant to the employment
agreements between the predecessor and the Co-Chief Executive
Officers, which were adopted by us and BreitBurn Management at
January 1, 2007, the Co- Chief Executive Officers were each
awarded 336,364 phantom option units at a grant price of $24.10
per unit under the executive phantom option plan. These phantom
units, in late 2007, were cancelled and terminated in exchange
for the right to receive a lump-sum payment of $2.4 million
and 184,400 of Restricted Phantom Units (RPUs) at a grant price
of $31.68 per unit, which has a fair value of
$5.8 million. The RPUs will vest and be paid in Common
Units in three equal annual installments on each anniversary
date of the vesting commencement date of the award. They will
receive quarterly distributions at the same rate payable to
common unitholders immediately after grant. Of the total amount
expensed in 2007, $4.6 million was recorded to equity. The
remaining fair value of the awards in the amount of
$1.2 million is being expensed ratably over a three-year
period beginning in 2008. The remaining 188,545 RPUs issued in
2007 were issued to the top seven executives
including the Co-Chief Executive Officers at a grant
price of $30.29 per Common Unit.
The following table summarizes information about RPUs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007 (a)
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
Number of
|
|
|
Weighted
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
RPU
|
|
|
Average
|
|
|
RPU
|
|
|
Average
|
|
|
RPU
|
|
|
Average
|
|
|
|
Units
|
|
|
Fair Value *
|
|
|
Units
|
|
|
Fair Value *
|
|
|
Units
|
|
|
Fair Value *
|
|
|
Outstanding, beginning of period
|
|
|
607,263
|
|
|
$
|
26.91
|
|
|
|
372,945
|
|
|
$
|
30.98
|
|
|
|
-
|
|
|
$
|
-
|
|
Granted
|
|
|
1,790,589
|
|
|
|
8.17
|
|
|
|
245,290
|
|
|
|
20.44
|
|
|
|
372,945
|
|
|
|
30.98
|
|
Exercised
|
|
|
(808,700
|
)
|
|
|
13.08
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cancelled
|
|
|
(14,402
|
)
|
|
|
14.45
|
|
|
|
(10,972
|
)
|
|
|
20.83
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
1,574,750
|
|
|
$
|
12.82
|
|
|
|
607,263
|
|
|
$
|
26.91
|
|
|
|
372,945
|
|
|
$
|
30.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
* At grant date
(a) 2007 includes Co-Chief Executive Officers 184,400
RPUs received as a result of the termination of the executive
phantom option plan in November 2007.
Convertible
Phantom Units (CPUs)
In December 2007, seven executives received 681,500 units
of CPUs at a grant price of $30.29 per Common Unit. Each of the
awards has the vesting commencement date of January 1,
2008. CPUs are significantly tied to the amount of
distributions we make to holders of our Common Units. As
discussed further below, the number of CPUs ultimately awarded
to each of these senior executives will be based upon the level
of distributions to common unitholders achieved during the term
of the CPUs. The CPU grants vest
144
over a longer-term period of up to five years. Therefore, these
grants will not be made on an annual basis. New grants could be
made at the Boards discretion at a future date after the
present CPU grants have vested.
CPUs vest on the earliest to occur of (i) January 1,
2013, (ii) the date on which the aggregate amount of
distributions paid to common unitholders for any four
consecutive quarters during the term of the award is greater
than or equal to $3.10 per Common Unit and (iii) upon the
occurrence of the death or disability of the grantee
or his or her termination without cause or for
good reason (as defined in the holders
employment agreement, if applicable). Unvested CPUs are
forfeited in the event that the grantee ceases to remain in the
service of BreitBurn Management. Prior to vesting, a holder of
a CPU is entitled to receive payments equal to the amount of
distributions made by us with respect to each of the Common
Units multiplied by the number of Common Unit equivalents
underlying the CPUs at the time of the distribution.
Under the original CPU Agreements, one Common Unit Equivalent
(CUE) underlies each CPU at the time it was awarded to the
grantee. However, the number of CUEs underlying the CPUs would
increase at a compounded rate of 25 percent upon the
achievement of each 5 percent compounded increase in the
distributions paid by us to our common unitholders. Conversely,
the number of CUEs underlying the CPUs would decrease at a
compounded rate of 25 percent if the distributions paid by
us to our common unitholders decreases at a compounded rate of
5 percent.
On October 29, 2009, the Compensation and Governance
Committee approved an amendment to each of the existing CPU
Agreements entered into with each named executive officer.
Originally under the CPU Agreements, the number of CUEs per CPU
could be reduced over the five year life of the agreement to a
minimum of zero, or be multiplied by a maximum of 4.768 times,
based on our distribution levels. We suspended the payment of
distributions in April 2009; therefore, holders of CPUs
did not receive any distributions under the CPU Agreements as
long as distributions were suspended. Under the original chart,
if the CPUs were to vest currently for
instance in the case of the death or disability of a
holder zero units would vest to that holder. The
Committee determined that the elimination of multipliers between
zero and one best represented the original incentive and
retention purpose of the CPU Agreements. With this modification
to the CPU Agreements, the number of CUEs per CPU can no longer
be less than one, regardless of Common Unit distribution levels.
On January 29, 2010, the Committee also approved an
amendment to each of the existing Convertible Phantom Unit
(CPU) Agreements entered into with each named
executive officer. Under these agreements, each CPU entitles
its holder to receive (i) a number of our Common Units at
the time of vesting equal to the number of common unit
equivalents (CUEs) underlying the CPU at
vesting, and (ii) current distributions on Common Units
during the vesting period based on the number of CUEs underlying
the CPU at the time of such distribution. The number of CUEs
underlying each CPU is determined by reference to Common Unit
distribution levels during the applicable vesting period,
generally calculated based upon the aggregate amount of
distributions made per Common Unit for the four quarters
preceding vesting. The amendment to the CPU agreements now
limits the multiplier for 20 percent of the total number of
CPUs and related CUEs granted in each award to 1.
As a result, upon vesting, CPUs for 20 percent of each
award will convert to Common Units on a 1:1 basis, and with
respect to that portion of the award, holders will lose the
ability to earn additional Common Units based on increased
distributions on Common Units. No other modification was made
to the CPU Agreements under this amendment. Because we were
accruing compensation expense using a CPU multiplier of one,
these amendments had no impact on compensation expense recorded.
In the event that the CPUs vest on January 1, 2013 or if
the aggregate amount of distributions paid to common unitholders
for any four consecutive quarters during the term of the award
is greater than $3.10 per Common Unit, the CPUs would convert
into a number of Common Units equal to the number of Common Unit
equivalents underlying the CPUs at such time (calculated based
upon the aggregate amount of distributions made per Common Unit
for the preceding four quarters subject to the 80 percent
limitation put in place on January 29, 2010 as noted above).
In the event that CPUs vest due to the death or disability of
the grantee or his or her termination without cause or good
reason, the CPUs would convert into a number of Common Units
equal to the number of Common Unit equivalents underlying the
CPUs at such time, pro-rated based the date of death or
disability.
145
First, the number of Common Unit equivalents would be calculated
based upon the aggregate amount of distributions made per Common
Unit for the preceding four quarters or, if such calculation
would provide for a greater number of Common Unit equivalents,
the most recently announced quarterly distribution level by us
on an annualized basis (subject to the 80 percent
limitation noted above). Then, this number would be pro rated
by multiplying it by a percentage equal to:
|
|
|
|
|
if such termination occurs on or before December 31, 2008,
a percentage equal to 40 percent;
|
|
|
|
if such termination occurs on or before December 31, 2009,
a percentage equal to 60 percent;
|
|
|
|
if such termination occurs on or before December 31, 2010,
a percentage equal to 80 percent; and
|
|
|
|
if such termination occurs on or after January 1, 2011, a
percentage equal to 100 percent.
|
For the CPUs, we recorded compensation expense of
$4.1 million in 2009 and $4.1 million in 2008. At
December 31, 2009, there was $12.3 million of total
unrecognized compensation cost related to the unvested CPUs
remaining. This amount is expected to be recognized over the
next three years.
Founders
Plan Awards
Under the Founders Plan, participants received unit appreciation
rights which provide cash compensation in relation to the
appreciation in the value of a specified number of underlying
notional phantom units. The value of the unit appreciation
rights was determined on the basis of a valuation of the
predecessor at the end of the fiscal period plus distributions
during the period less the value of the predecessor at the
beginning of the period. The base price and vesting terms were
determined by BreitBurn Management at the time of the grant.
Outstanding unit appreciation rights vest in the following
manner: one-third vest three years after the grant date,
one-third vest four years after the grant date and one-third
vest five years after the grant date and are subject to
specified service requirements.
Effective on the initial public offering date of
October 10, 2006, all outstanding unit appreciation rights
under the Founders Plan were adopted by BreitBurn Management and
converted into three separate awards. The first and second
awards became the obligations of our predecessor. The third
award represented 309,570 Partnership unit appreciation rights
at a base price of $18.50 per unit with respect to the
operations of the properties that were transferred to us for the
period beginning on the initial public offering date of
October 10, 2006. The award is liability-classified and is
being charged to us as compensation expense over the remaining
vesting schedule. The value of the outstanding Partnership unit
appreciation rights is remeasured each period using a
Black-Scholes option pricing model. Market prices of $10.59,
$7.05 and $28.90 were used in the model for the periods ending
December 31, 2009, 2008 and 2007, respectively. Expected
volatility ranged from 9 percent to 21 percent and had
a weighted average volatility of 9.8 percent. The average
risk free rate used was approximately 3.3 percent. The
expected option terms ranged from one half year to two and one
half years.
We recorded credits of approximately $0.4 million and
$0.3 million and a charge of $2.7 million of
compensation expense under the plan for the years ended
December 31, 2009, December 31, 2008 and
December 31, 2007, respectively. The aggregate value of
the vested and unvested unit appreciation rights was zero at
December 31, 2009.
146
The following table summarizes information about Appreciation
Rights Units issued under the Founders Plan:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Number of
|
|
|
|
|
Weighted
|
|
|
Number of
|
|
|
Weighted
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
Appreciation
|
|
|
|
|
Average
|
|
|
Appreciation
|
|
|
Average
|
|
|
Appreciation
|
|
|
Average
|
|
|
|
Rights Units
|
|
|
|
|
Exercise Price
|
|
|
Rights Units
|
|
|
Exercise Price
|
|
|
Rights Units
|
|
|
Exercise Price
|
|
|
Outstanding, beginning of period
|
|
|
122,644
|
|
|
|
|
$
|
18.50
|
|
|
|
214,107
|
|
|
$
|
18.50
|
|
|
|
305,570
|
|
|
$
|
18.50
|
|
Exercised
|
|
|
-
|
|
|
|
|
|
-
|
|
|
|
(91,463
|
)
|
|
|
18.50
|
|
|
|
(91,463
|
)
|
|
|
18.50
|
|
Cancelled(a)
|
|
|
(101,856
|
)
|
|
|
|
|
18.50
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
20,788
|
|
|
|
|
$
|
18.50
|
|
|
|
122,644
|
|
|
$
|
18.50
|
|
|
|
214,107
|
|
|
$
|
18.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
-
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
(a) These units expired out of the money and the remaining
units outstanding at year end will vest one half in 2010 and one
half in 2011.
BreitBurn
Management LTIP and the Partnership LTIP
BreitBurn
Management LTIP
In September 2005, certain employees other than the Co-Chief
Executive Officers of the predecessor were granted restricted
units (RTUs)
and/or
performance units (PTUs), both of which entitle the employee to
receive cash compensation in relation to the value of a
specified number of underlying notional trust units indexed to
Provident Energy Trust Units. The grants are based on
personal performance objectives. This plan replaced the Unit
Appreciation Right Plan for Employees and Consultants for the
period after September 2005 and subsequent years. RTUs vest one
third at the end of year one, one third at the end of year two
and one third at the end of year three after grant. In general,
cash payments equal to the value of the underlying notional
units were made on the anniversary dates of the RTU to the
employees entitled to receive them. PTUs vest three years from
the end of the third year after grant and the payout can range
from zero to two hundred percent of the initial grant depending
on the total return of the underlying notional units as compared
to the returns of selected peer companies. The total return of
the Provident Energy Trust unit is compared with the return of
25 selected Canadian trusts and funds. The Provident indexed
PTUs granted in 2005 and 2006 entitle employees to receive cash
payments equal to the market price of the underlying notional
units. Under our LTIP, Partnership indexed PTUs were granted in
2007 and are payable in cash or may be paid in Common Units if
elected at least 60 days prior to vesting by the grantees.
The total return of the Partnership unit is compared with the
return of 49 companies in the Alerian MLP Index for the
payout multiplier. All of the grants are liability-classified.
Underlying notional units are established based on target salary
LTIP threshold for each employee. The awarded notional units
are adjusted cumulatively thereafter for distribution payments
through the use of an adjustment ratio. The estimated fair
value associated with RTUs and PTUs is expensed in the statement
of income over the vesting period.
On June 17, 2008, we entered into the BreitBurn Management
Purchase agreement with Pro LP and Pro GP. The BreitBurn
Management Purchase Agreement contains certain covenants of the
parties relating to the allocation of responsibility for
liabilities and obligations under certain pre-existing
equity-based compensation plans adopted by BreitBurn Management,
BEC and us. The pre-existing compensation plans include the
outstanding 2005 and 2006 LTIP grants which are indexed to the
Provident Trust Units. As a result, we paid
$0.9 million for our share of the 2005 LTIP grants that
vested in June 2008 in accordance with the agreed allocation of
liability.
In September 2008, BreitBurn Management made an offer to holders
of the 2006 LTIP grants to cash out their Provident-indexed
units at $10.32 per share before the normal vesting date of
December 31, 2008. By the end of September 2008, the offer
was accepted by all employees who had outstanding 2006 LTIP
grants. Consequently, compensation expense was recognized for
the full amount of the remaining unvested liability during 2008.
BreitBurn Management paid employees $0.6 million in 2008
for its share of the 2006 LTIP grants in accordance with the
agreed allocation of liability.
147
We recognized no expense for the year ended December 31,
2009, $0.9 million and $0.4 million of compensation
expense for the years ended December 31, 2008 and,
December 31, 2007, respectively. The following table
summarizes information about the restricted/performance units
granted in 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PVE indexed units
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
Number of
|
|
|
Average
|
|
|
|
Units
|
|
|
Grant Price
|
|
|
Units
|
|
|
Grant Price
|
|
|
Outstanding, beginning of period
|
|
|
267,702
|
|
|
$
|
10.77
|
|
|
|
318,389
|
|
|
$
|
10.82
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exercised
|
|
|
(267,351
|
)
|
|
|
10.77
|
|
|
|
(36,203
|
)
|
|
|
10.87
|
|
Cancelled
|
|
|
(351
|
)
|
|
|
10.73
|
|
|
|
(14,484
|
)
|
|
|
11.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
-
|
|
|
$
|
10.77
|
|
|
|
267,702
|
|
|
$
|
10.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
Partnership
LTIP
Under our LTIP, Partnership-indexed restricted units (RTUs)
and/or
performance units (PTUs) were granted in 2007 certain
individuals other than the Co-Chief Executive Officers. RTUs
vest one third at the end of year one, one third at the end of
year two and one third at the end of year three after grant. In
general, cash payments equal to the value of the underlying
notional units were made on the anniversary dates of the RTUs.
PTUs vest three years from the end of third year after grant and
are payable in cash or in Common Units of the Partnership if
elected by the grantee at least 60 days prior to the
vesting date. PTU payouts are further determined by a
performance multiplier which can range from zero to two hundred
percent of the initial grant depending on the total return of
the underlying notional units as compared to the returns of a
selected peer group of companies. The multiplier is determined
by comparing our total return to the returns of
49 companies in the Alerian MLP Index. Underlying notional
units are established based on target salary LTIP threshold for
each employee. The awarded notional units are adjusted
cumulatively thereafter for distribution payments through the
use of an adjustment ratio. The estimated fair value associated
with RTUs and PTUs is expensed in the statement of income over
the vesting period.
We recognized credits of $0.5 million and $1.4 million
and a charge of $2.1 million of compensation expense for
the years ended December 31, 2009, December 31, 2008
and December 31, 2007, respectively. Our share of the
aggregate liability or the remaining unvested value under the
BreitBurn Management LTIP was less than $0.1 million at
December 31, 2009.
Due to the suspension of our distribution in April 2009, the
multiplier as calculated at the end of 2009 was below that
required to generate a payout. As a result, all outstanding
PTUs vested and expired January 1, 2010 and no payout was
made.
148
The following table summarizes information about the
restricted/performance units granted in 2007. Market prices of
$10.59, $7.05 and $28.90 were used in the model for the periods
ending December 31, 2009 December 31, 2008 and
December 31, 2007, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PTUs and RTUs
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
Number of
|
|
|
Average
|
|
|
Number of
|
|
|
Average
|
|
|
|
Units
|
|
|
Grant Price
|
|
|
Units
|
|
|
Grant Price
|
|
|
Units
|
|
|
Grant Price
|
|
|
Outstanding, beginning of period
|
|
|
86,992
|
|
|
$
|
24.10
|
|
|
|
108,717
|
|
|
$
|
23.64
|
|
|
|
20,483
|
|
|
$
|
21.67
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
91,834
|
|
|
|
24.10
|
|
Exercised
|
|
|
(6,357
|
)
|
|
|
24.10
|
|
|
|
(20,645
|
)
|
|
|
20.39
|
|
|
|
(98
|
)
|
|
|
24.10
|
|
Cancelled
|
|
|
(75,034
|
)
|
|
|
24.10
|
|
|
|
(1,080
|
)
|
|
|
24.10
|
|
|
|
(3,502
|
)
|
|
|
24.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
5,601
|
|
|
$
|
24.10
|
|
|
|
86,992
|
|
|
$
|
24.10
|
|
|
|
108,717
|
|
|
$
|
23.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
Unit
Appreciation Right Plan Awards
In 2004, the predecessor adopted the Unit Appreciation Right
Plan for Employees and Consultants (the UAR Plan).
Under the UAR Plan, certain employees of the predecessor were
granted unit appreciation rights (UARs). The UARs
entitle the employee to receive cash compensation in relation to
the value of a specified number of underlying notional trust
units of Provident (Phantom Units). The exercise
price and the vesting terms of the UARs were determined at the
sole discretion of the Plan Administrator at the time of the
grant. The UAR Plan was replaced with the BreitBurn Management
LTIP at the end of September 2005. The grants issued prior to
the replacement of the UAR Plan fully vested in 2008.
UARs vest one third at the end of year one, one third at the end
of year two and one third at the end of year three after grant.
Upon vesting, the employee is entitled to receive a cash payment
equal to the excess of the market price of Providents
units (PVE units) over the exercise price of the Phantom Units
at the grant date, adjusted for an additional amount equal to
any Excess Distributions, as defined in the plan. The
predecessor settles rights earned under the plan in cash. All
of the outstanding UAR units at December 31, 2008 expired
during 2009.
The total compensation expense for the UAR plan is allocated
between us and our predecessor. Our share of expense was an
immaterial amount in 2009 and 2008. We recorded
$0.4 million in expense for 2007 under the UAR Plan.
Director
Restricted Phantom Units
Effective with the initial public offering, we also made grants
of Restricted Phantom Units in the Partnership to the
non-employee directors of our General Partner. Each phantom
unit is accompanied by a distribution equivalent unit right
entitling the holder to an additional number of phantom units
with a value equal to the amount of distributions paid on each
of our Common Units until settlement. Upon vesting, the
majority of the phantom units will be paid in Common Units,
except for certain directors awards which will be settled
in cash. The unit-settled awards are classified as equity and
the cash-settled awards are classified as liabilities. The
estimated fair value associated with these phantom units is
expensed in the statement of income over the vesting period.
The accumulated compensation expense for unit-settled awards is
reported in equity, and for cash-settled grants, it is reflected
as a liability on the consolidated balance sheet.
We recorded compensation expense for the directors phantom
units of approximately $0.4 million in 2009,
$0.1 million in 2008 and $0.5 million in 2007. As of
December 31, 2009, there was $0.5 million of total
unrecognized compensation cost for the unvested Director
Performance Units and such cost is expected to be recognized
over the next two years. The total fair value of units vested
in 2009 was $0.2 million.
149
The following table summarizes information about the Director
Restricted Phantom Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Number of
|
|
|
Weighted
|
|
|
Number of
|
|
|
Weighted
|
|
|
Number of
|
|
|
Weighted
|
|
|
|
Performance
|
|
|
Average
|
|
|
Performance
|
|
|
Average
|
|
|
Performance
|
|
|
Average
|
|
|
|
Units
|
|
|
Fair Value *
|
|
|
Units
|
|
|
Fair Value *
|
|
|
Units
|
|
|
Fair Value *
|
|
|
Outstanding, beginning of period
|
|
|
35,429
|
|
|
$
|
22.60
|
|
|
|
37,473
|
|
|
$
|
21.11
|
|
|
|
20,026
|
|
|
$
|
18.50
|
|
Granted
|
|
|
56,736
|
|
|
|
9.20
|
|
|
|
20,146
|
|
|
|
25.02
|
|
|
|
17,447
|
|
|
|
24.10
|
|
Exercised
|
|
|
(10,810
|
)
|
|
|
18.50
|
|
|
|
(22,190
|
)
|
|
|
22.28
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
81,355
|
|
|
$
|
13.80
|
|
|
|
35,429
|
|
|
$
|
22.60
|
|
|
|
37,473
|
|
|
$
|
21.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of period
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
* At grant date
|
|
18.
|
Commitments
and Contingencies
|
Lease
Rental Obligations
We had operating leases for office space and other property and
equipment having initial or remaining non-cancelable lease terms
in excess of one year. Our future minimum rental payments for
operating leases at December 31, 2009 are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
Thousands of
dollars
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2013
|
|
|
after 2013
|
|
|
Total
|
|
|
Operating leases
|
|
$
|
2,838
|
|
|
$
|
2,636
|
|
|
$
|
2,174
|
|
|
$
|
814
|
|
|
$
|
465
|
|
|
$
|
543
|
|
|
$
|
9,470
|
|
Net rental payments made under non-cancelable operating leases
were $2.6 million, $2.8 million and $0.4 million
in 2009, 2008 and 2007, respectively. As of December 31,
2009, we had no purchase obligations for the next five years.
Surety
Bonds and Letters of Credit
In the normal course of business, we have performance
obligations that are secured, in whole or in part, by surety
bonds or letters of credit. These obligations primarily cover
self-insurance and other programs where governmental
organizations require such support. These surety bonds and
letters of credit are issued by financial institutions and are
required to be reimbursed by us if drawn upon. At
December 31, 2009, we had $10.6 million in surety
bonds and $0.3 million in letters of credit outstanding.
At December 31, 2008, we had $10.1 million in surety
bonds and $0.3 million in letters of credit outstanding.
Legal
Proceedings
Although we may, from time to time, be involved in litigation
and claims arising out of our operations in the normal course of
business, we are not currently a party to any material legal
proceedings other than the Quicksilver lawsuit, which was
settled in February 2010 (see Note 21). In addition, we
are not aware of any material legal or governmental proceedings
against us, or contemplated to be brought against us, under the
various environmental protection statues to which we are subject.
We have no independent assets or operations other than those of
our subsidiaries. BOLP or BOGP may guarantee debt securities
that may be issued by us and BreitBurn Finance Corporation, our
wholly owned subsidiary. See Note 1 for a description of
BreitBurn Finance Corporation. The guarantees will be full and
unconditional and joint and several.
BreitBurn Management operates our assets and performs other
administrative services for us such as accounting, corporate
development, finance, land administration, legal and
engineering. All of our employees, including our executives,
are employees of BreitBurn Management. BreitBurn Management has
a defined
150
contribution retirement plan, which, through November 30,
2007, covered substantially all of its employees who had
completed at least three months of service and, starting
December 1, 2007, covers substantially all of its employees
on the first day of the month following the month of hire. The
plan provides for BreitBurn Management to make regular
contributions based on employee contributions as provided for in
the plan agreement. Employees fully vest in BreitBurn
Managements contributions after five years of service.
BEC is charged for a portion of the matching contributions made
by BreitBurn Management. For the year ended December 31,
2009, the matching contribution paid by us was
$1.0 million. For the year ended December 31, 2008
and December 31, 2007, the matching contributions paid by
us were $0.4 million and a $0.1 million, respectively.
|
|
20.
|
Significant
Customers
|
We sell oil, natural gas and natural gas liquids primarily to
large domestic refiners. For the year ended December 31,
2009, purchasers that accounted for ten percent or more of our
net sales were ConocoPhillips which accounted for
30 percent of net sales, Marathon Oil Company which
accounted for 16 percent of net sales, and Plains
Marketing & Transportation LLC which accounted for
11 percent of net sales. For the years ended
December 31, 2008 and 2007, ConocoPhillips purchased
approximately 25 percent and 20 percent of our
production, respectively, and Marathon Oil Company purchased
approximately 13 percent and 24 percent of our
production, respectively. Plains Marketing &
Transportation LLC accounted for less than ten percent of our
total production for the years ended December 31, 2008 and
2007, respectively.
In January 2010, 496,194 Common Units were issued to employees
under our 2006 Long-Term Incentive Plan and 13,617 Common Units
were issued to outside directors for phantom units and
distribution equivalent rights which were granted in 2007 and
vested in January 2010.
On February 19, 2010, we entered into a crude oil fixed
price swap contract for 500 Bbl/d for 2013 at a price of
$84.55. On March 3, 2010, we entered into a crude oil
fixed price swap contract for 400 Bbl/d for 2011 through
2013 at $84.30 per Bbl. On March 10, 2010, we entered into
a crude oil fixed price swap contract for
600 Bbl/d
for 2011 through 2013 at $86.35 per Bbl.
In February 2010, we and Quicksilver agreed to settle all claims
with respect to the litigation filed by Quicksilver. The terms
of the Settlement which we expect to be implemented in April
2010 include a monetary settlement to Quicksilver, which we
expect will be paid by insurance. See Note 8 for a
discussion of the monetary settlement. In addition,
Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach
will resign from the Board of Directors and the Board will
appoint two new directors designated by Quicksilver, one of whom
will qualify as an independent director and the other will be a
current independent board member now serving on
Quicksilvers board of directors, provided that such
director not be a member of Quicksilvers management.
|
|
22.
|
Supplemental
Information about Oil and Natural Gas Activities
(Unaudited)
|
In December 2008, the SEC issued Release
33-8995
adopting new rules for reserves estimate calculations and
related disclosures. The new reserve estimate disclosures apply
to all annual reports for fiscal years ending on or after
December 31, 2009 and thereafter, and to all registration
statements filed after that date. The new rules did not permit
companies to voluntarily comply at an earlier date. The revised
proved reserve definition incorporates a new definition of
reasonable certainty using the PRMS (Petroleum
Resource Management System) standard of high degree of
confidence for deterministic method estimates, or a
90 percent recovery probability for probabilistic methods
used in estimating proved reserves. The new rules also permit a
company to establish undeveloped reserves as proved with
appropriate degrees of reasonable certainty established absent
actual production tests and without artificially limiting such
reserves to spacing units adjacent to a producing well. For
reserve reporting purposes, the new rules also replace the
end-of-the-year oil and gas reserve pricing with an unweighted
average
first-day-of-the-month
pricing for the past 12 fiscal months. Additionally, it has
been our historical practice to use our year-end reserve report
to adjust our
151
depreciation, depletion, and amortization expense for the fourth
quarter. We continued this practice in 2009 using the new
unweighted average
first-day-of-the-month
pricing. The impact of the adoption of the SEC final rule on
our financial statements, including our fourth quarter
depreciation, depletion, and amortization is not practicable to
estimate due to the operational and technical challenges
associated with calculating a cumulative effect of adoption by
preparing reserve reports under both the old and new rules.
Costs associated with reserves will continue to be measured on
the last day of the fiscal year. A revised tabular presentation
of reserves by development category, final product type, and oil
and gas activity disclosure by geographic regions and
significant fields and a general disclosure of the internal
controls a company uses to assure objectivity in reserves
estimation will be required. This release became effective for
us with this filing and is applied prospectively beginning with
the year ended December 31, 2009. We calculate total
estimated proved reserves and disclose our oil and natural gas
activities in accordance with ASC 932 Extractive
Activities Oil and Gas, which incorporates
Release
No. 33-8995.
Costs
incurred
Our oil and natural gas activities are conducted in the United
States. The following table summarizes the costs incurred
by us:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1,437,129
|
|
Unproved
|
|
|
-
|
|
|
|
-
|
|
|
|
213,344
|
|
Development costs
|
|
|
28,669
|
|
|
|
129,503
|
|
|
|
26,959
|
|
Asset retirement costs
|
|
|
4,883
|
|
|
|
1,363
|
|
|
|
3,583
|
|
Pipelines and processing facilities
|
|
|
-
|
|
|
|
-
|
|
|
|
48,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
33,552
|
|
|
$
|
130,866
|
|
|
$
|
1,729,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized
costs
The following table presents the aggregate capitalized costs
subject to depreciation, depletion and amortization relating to
oil and gas activities, and the aggregate related accumulated
allowance.
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
Proved properties and related producing assets
|
|
$
|
1,726,722
|
|
|
$
|
1,734,932
|
|
Pipelines and processing facilities
|
|
|
136,556
|
|
|
|
112,726
|
|
Unproved properties
|
|
|
195,690
|
|
|
|
209,873
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(321,851
|
)
|
|
|
(223,575
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
1,737,117
|
|
|
$
|
1,833,956
|
|
|
|
|
|
|
|
|
|
|
The average DD&A rate per equivalent unit of production for
our year ended December 31, 2009 was $16.39 per Boe. The
average DD&A rate per equivalent unit of production for us
over the year ended December 31, 2008 was $26.42 per Boe.
The decrease in the DD&A rate was primarily due to price
related reserve reductions at year end 2008 due to using
year-end pricing at December 31, 2008.
Results
of operations for oil and gas producing activities
The results of operations from oil and gas producing activities
below exclude non-oil and gas revenues and expenses, general and
administrative expenses, interest expenses and interest income.
152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Oil, natural gas and NGL sales
|
|
$
|
254,917
|
|
|
$
|
467,381
|
|
|
$
|
184,372
|
|
Realized gain (loss) on derivative instruments
|
|
|
167,683
|
|
|
|
(55,946
|
)
|
|
|
(6,556
|
)
|
Unrealized gain (loss) on derivative instruments
|
|
|
(219,120
|
)
|
|
|
388,048
|
|
|
|
(103,862
|
)
|
Operating costs
|
|
|
(138,498
|
)
|
|
|
(162,005
|
)
|
|
|
(73,989
|
)
|
Depreciation, depletion, and amortization
|
|
|
(104,299
|
)
|
|
|
(178,657
|
)
|
|
|
(29,277
|
)
|
Income tax (expense) benefit
|
|
|
1,528
|
|
|
|
(1,939
|
)
|
|
|
1,229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations from producing activities
|
|
$
|
(37,789
|
)
|
|
$
|
456,882
|
|
|
$
|
(28,083
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
reserve information
The following information summarizes our estimated proved
reserves of oil (including condensate and natural gas liquids)
and natural gas and the present values thereof for the years
ended December 31, 2009, 2008 and 2007. The following
reserve information is based upon reports by Netherland,
Sewell & Associates, Inc. and Schlumberger
Data & Consulting Services, independent petroleum
engineering firms. Netherland, Sewell & Associates,
Inc. provides reserve data for our California, Wyoming and
Florida properties and Schlumberger Data & Consulting
Services provides reserve data for our Michigan, Kentucky and
Indiana properties. The estimates are prepared in accordance
with SEC regulations. We only utilize large, widely known,
highly regarded, and reputable engineering consulting firms.
Not only the firms, but the technical persons that sign and seal
the reports are licensed and certify that they meet all
professional requirements. Licensing requirements formally
require mandatory continuing education and professional
qualifications. They are independent petroleum engineers,
geologists, geophysicists and petrophysicists.
Our reserve estimation process involves petroleum engineers and
geoscientists. As part of this process, all reserves volumes
are estimated using a forecast of production rates, current
operating costs and projected capital expenditures. Prices are
based upon the average prior 12 month spot prices as
specified by the SEC. Price differentials are than applied to
adjust to expected realized field price. Specifics of each
operating agreement are then used to estimate the net reserves.
Production rate forecasts are derived by a number of methods,
including decline curve analyses, volumetrics, material balance
or computer simulation of the reservoir performance. Operating
costs and capital costs are forecast using current costs
combined with expectations of future costs for specific
reservoirs. In many cases, activity-based cost models for a
reservoir are utilized to project operating costs as production
rates and the number of wells for production and injection vary.
Our Reserves and Planning Manager, who reports directly to our
Chief Operating Officer, maintains our reserves databases,
provides reserve reports to accounting based on SEC guidance and
updates production forecasts. He provides access to our
reserves databases to Netherland, Sewell & Associates,
Inc. and Schlumberger Data & Consulting Services and
oversees the compilation of and reviews their reserve reports.
He is a Registered Texas Professional Engineer with Masters
Degrees in Engineering and Business and thirty-five years of oil
and gas experience included experience as a senior officer with
international engineering consulting firms.
Management believes the reserve estimates presented herein, in
accordance with generally accepted engineering and evaluation
principles consistently applied, are reasonable. However, there
are numerous uncertainties inherent in estimating quantities and
values of the estimated proved reserves and in projecting future
rates of production and timing of development expenditures,
including many factors beyond our control. Reserve engineering
is a subjective process of estimating the recovery from
underground accumulations of oil and gas that cannot be measured
in an exact manner and the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and
geological interpretation and judgment. Because all reserve
estimates are to some degree speculative, the quantities of oil
and gas that are ultimately recovered,
153
production and operating costs, the amount and timing of future
development expenditures and future oil and gas sales prices may
all differ from those assumed in these estimates. In addition,
different reserve engineers may make different estimates of
reserve quantities and cash flows based upon the same available
data. Therefore, the standardized measure of discounted net
future cash flows shown below represents estimates only and
should not be construed as the current market value of the
estimated oil and gas reserves attributable to our properties.
In this regard, the information set forth in the following
tables includes revisions of reserve estimates attributable to
proved properties included in the preceding years
estimates. Such revisions reflect additional information from
subsequent exploitation and development activities, production
history of the properties involved and any adjustments in the
projected economic life of such properties resulting from
changes in product prices. Decreases in the prices of oil and
natural gas and increases in operating expenses have had, and
could have in the future, an adverse effect on the carrying
value of our proved reserves and revenues, profitability and
cash flow.
The following table sets forth certain data pertaining to our
estimated proved and proved developed reserves for the years
ended December 31, 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
In Thousands
|
|
(MBoe)
|
|
|
(MBbl)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
(MBbl)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
(MBbl)
|
|
|
(MMcf)
|
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
|
103,649
|
|
|
|
25,910
|
|
|
|
466,434
|
|
|
|
142,273
|
|
|
|
58,095
|
|
|
|
505,069
|
|
|
|
30,740
|
|
|
|
30,042
|
|
|
|
4,190
|
|
Revision of previous
estimates (a)
|
|
|
15,303
|
|
|
|
17,034
|
|
|
|
(10,389
|
)
|
|
|
(31,815
|
)
|
|
|
(29,106
|
)
|
|
|
(16,251
|
)
|
|
|
3,171
|
|
|
|
3,260
|
|
|
|
(534
|
)
|
Extensions, discoveries and other
additions (a)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
118
|
|
|
|
118
|
|
|
|
-
|
|
Purchase of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
111,263
|
|
|
|
27,005
|
|
|
|
505,547
|
|
Sale of reserves in-place
|
|
|
(1,135
|
)
|
|
|
(1,109
|
)
|
|
|
(154
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(6,516
|
)
|
|
|
(2,989
|
)
|
|
|
(21,161
|
)
|
|
|
(6,810
|
)
|
|
|
(3,079
|
)
|
|
|
(22,384
|
)
|
|
|
(3,019
|
)
|
|
|
(2,330
|
)
|
|
|
(4,134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
|
111,301
|
|
|
|
38,846
|
|
|
|
434,730
|
|
|
|
103,649
|
|
|
|
25,910
|
|
|
|
466,434
|
|
|
|
142,273
|
|
|
|
58,095
|
|
|
|
505,069
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
|
95,643
|
|
|
|
23,346
|
|
|
|
433,780
|
|
|
|
128,344
|
|
|
|
52,103
|
|
|
|
457,444
|
|
|
|
28,484
|
|
|
|
27,786
|
|
|
|
4,190
|
|
Ending balance
|
|
|
100,968
|
|
|
|
34,436
|
|
|
|
399,190
|
|
|
|
95,643
|
|
|
|
23,346
|
|
|
|
433,780
|
|
|
|
128,343
|
|
|
|
52,103
|
|
|
|
457,444
|
|
Proved Undeveloped
Reserves (b) (c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance
|
|
|
8,006
|
|
|
|
2,564
|
|
|
|
32,654
|
|
|
|
13,930
|
|
|
|
5,992
|
|
|
|
47,625
|
|
|
|
2,256
|
|
|
|
2,256
|
|
|
|
-
|
|
Ending balance
|
|
|
10,333
|
|
|
|
4,410
|
|
|
|
35,540
|
|
|
|
8,006
|
|
|
|
2,564
|
|
|
|
32,654
|
|
|
|
13,930
|
|
|
|
5,992
|
|
|
|
47,625
|
|
(a) Additions to proved
reserves classified in revisions due to infill drilling,
re-completions and workovers were approximately 1,563 MBbl
for oil and 32,376 MMcf for natural gas in 2009,
741 MBbl for oil and 35,834 MMcf for natural gas in
2008 and 1,422 MBbl for oil and 19 MMcf for natural
gas in 2007.
(b) During the year ended
December 31, 2009, we incurred $5,807 in capital
expenditures and drilled 11 wells to convert 568 MBbl
of oil and 484 MMcf of natural gas from proved undeveloped
to proved developed.
(c) As of December 31,
2009, we had no material proved undeveloped reserves that have
remained undeveloped for more than five years. The increase in
proved undeveloped reserves during the year ended
December 31, 2009 was primarily due to the economic effect
of higher 2009 SEC pricing on properties previously deemed
uneconomical as well as revisions of estimates, partially offset
by the conversion of proved undeveloped reserves to proved
developed.
154
Standardized
measure of discounted future net cash flows
The Standardized Measure of discounted future net cash flows
relating to our estimated proved crude oil and natural gas
reserves as of December 31, 2009, 2008 and 2007 is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of
dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Future cash inflows
|
|
$
|
3,837,605
|
|
|
$
|
3,523,524
|
|
|
$
|
8,154,921
|
|
Future development costs
|
|
|
(197,709
|
)
|
|
|
(212,951
|
)
|
|
|
(370,594
|
)
|
Future production expense
|
|
|
(2,103,381
|
)
|
|
|
(1,843,986
|
)
|
|
|
(3,360,451
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
1,536,515
|
|
|
|
1,466,587
|
|
|
|
4,423,876
|
|
Discounted at 10% per year
|
|
|
(776,893
|
)
|
|
|
(874,327
|
)
|
|
|
(2,511,409
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
759,622
|
|
|
$
|
592,260
|
|
|
$
|
1,912,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The standardized measure of discounted future net cash flows
discounted at ten percent from production of proved reserves was
developed as follows:
|
|
|
|
1.
|
An estimate was made of the quantity of proved reserves and the
future periods in which they are expected to be produced based
on year-end economic conditions.
|
|
|
2.
|
In accordance with SEC guidelines, the reserve engineers
estimates of future net revenues from our estimated proved
properties and the present value thereof for 2009 are made using
unweighted average
first-day-of-the-month
oil and gas sales prices and are held constant throughout the
life of the properties, except where such guidelines permit
alternate treatment, including the use of fixed and determinable
contractual price escalations. We have entered into various
arrangements to fix or limit the prices relating to a portion of
our oil and gas production. Arrangements in effect at
December 31, 2009 are discussed in Note 16. Such risk
management arrangements are not reflected in the reserve
reports. Representative unweighted average
first-day-of-the-month
market prices for the reserve reports for the year ended
December 31, 2009 were $61.18 ($51.29 for Wyoming) per
barrel of oil and $3.87 per MMBtu of gas.
|
|
|
3.
|
In accordance with SEC guidelines for 2008 and 2007, the reserve
engineers estimates of future net revenues from our
estimated proved properties and the present value thereof are
made using oil and gas prices in effect as of the dates of such
estimates and are held constant throughout the life of the
properties, except where such guidelines permit alternate
treatment, including the use of fixed and determinable
contractual price escalations. Representative market prices at
the as-of date for the reserve reports as of December 31,
2008 and 2007 were $44.60 ($20.12 for Wyoming) and $95.95
($54.52 for Wyoming) per barrel of oil, respectively, and $5.71
and $6.80 per MMBtu of gas, respectively.
|
|
|
4.
|
The future gross revenue streams were reduced by estimated
future operating costs (including production and ad valorem
taxes) and future development and abandonment costs, all of
which were based on current costs. Future net cash flows assume
no future income tax expense as we are essentially a non-taxable
entity except for two tax paying corporations whose future
income tax liabilities on a discounted basis are insignificant.
|
|
|
5.
|
It is not practical to estimate the impact that adopting SEC
Release
33-8995 had
on our financial statements due to the technical challenges of
calculating a cumulative effect of adoption by preparing reserve
reports under both old and new rules.
|
155
The principal sources of changes in the Standardized Measure of
the future net cash flows for the years ended December 31,
2009, 2008 and 2007 are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Thousands of dollars
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Beginning balance
|
|
$
|
592,260
|
|
|
$
|
1,912,467
|
|
|
|
312,499
|
|
Sales, net of production expense
|
|
|
(116,419
|
)
|
|
|
(305,376
|
)
|
|
|
(110,383
|
)
|
Net change in sales and transfer prices, net of production
expense
|
|
|
217,756
|
|
|
|
(1,306,752
|
)
|
|
|
243,374
|
|
Previously estimated development costs incurred during year
|
|
|
29,041
|
|
|
|
57,694
|
|
|
|
15,451
|
|
Changes in estimated future development costs
|
|
|
(37,002
|
)
|
|
|
(98,064
|
)
|
|
|
(22,683
|
)
|
Extensions, discoveries and improved recovery, net of costs
|
|
|
-
|
|
|
|
-
|
|
|
|
2,602
|
|
Purchase of reserves in place
|
|
|
-
|
|
|
|
-
|
|
|
|
1,386,133
|
|
Sale of reserves in-place
|
|
|
(4,001
|
)
|
|
|
-
|
|
|
|
-
|
|
Revision of quantity estimates and timing of estimated production
|
|
|
18,761
|
|
|
|
141,044
|
|
|
|
54,224
|
|
Accretion of discount
|
|
|
59,226
|
|
|
|
191,247
|
|
|
|
31,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
759,622
|
|
|
$
|
592,260
|
|
|
$
|
1,912,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.
|
Quarterly
Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
Thousands of dollars except per unit amounts
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Oil, natural gas and natural gas liquid sales
|
|
$
|
57,643
|
|
|
$
|
59,872
|
|
|
$
|
62,674
|
|
|
$
|
74,728
|
|
Gains (losses) on derivative instruments
|
|
|
70,020
|
|
|
|
(97,259
|
)
|
|
|
12,719
|
|
|
|
(36,917
|
)
|
Other revenue, net
|
|
|
276
|
|
|
|
393
|
|
|
|
261
|
|
|
|
452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
127,939
|
|
|
$
|
(36,994
|
)
|
|
$
|
75,654
|
|
|
$
|
38,263
|
|
Operating income (loss)
|
|
|
53,696
|
|
|
|
(104,346
|
)
|
|
|
2,848
|
|
|
|
(35,009
|
)
|
Net income (loss)
|
|
|
46,357
|
|
|
|
(108,525
|
)
|
|
|
(5,396
|
)
|
|
|
(39,693
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net loss per limited partner unit (a)
|
|
|
0.85
|
|
|
|
(2.06
|
)
|
|
|
(0.10
|
)
|
|
|
(0.75
|
)
|
Diluted net loss per limited partner unit (a)
|
|
|
0.84
|
|
|
|
(2.06
|
)
|
|
|
(0.10
|
)
|
|
|
(0.75
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
Thousands of dollars except per unit amounts
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Oil, natural gas and natural gas liquid sales
|
|
$
|
115,849
|
|
|
$
|
139,962
|
|
|
$
|
130,249
|
|
|
$
|
81,321
|
|
Gains (losses) on derivative instruments
|
|
|
(83,387
|
)
|
|
|
(353,282
|
)
|
|
|
407,441
|
|
|
|
361,330
|
|
Other revenue, net
|
|
|
875
|
|
|
|
643
|
|
|
|
806
|
|
|
|
596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
33,337
|
|
|
$
|
(212,677
|
)
|
|
$
|
538,496
|
|
|
$
|
443,247
|
|
Operating income (loss) (b)
|
|
|
(34,455
|
)
|
|
|
(282,267
|
)
|
|
|
468,625
|
|
|
|
277,451
|
|
Net income (loss) (b)
|
|
|
(41,086
|
)
|
|
|
(286,170
|
)
|
|
|
454,505
|
|
|
|
251,175
|
|
Limited Partners interest in loss (b)
|
|
|
(40,867
|
)
|
|
|
(284,494
|
)
|
|
|
454,454
|
|
|
|
251,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net loss per limited partner unit (a)
|
|
|
(0.61
|
)
|
|
|
(4.39
|
)
|
|
|
8.43
|
|
|
|
4.66
|
|
Diluted net loss per limited partner unit (a)
|
|
|
(0.61
|
)
|
|
|
(4.39
|
)
|
|
|
8.41
|
|
|
|
4.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Due to changes in the number of weighted average common
units outstanding that may occur each quarter, the earnings per
unit amounts for certain quarters may not be additive.
(b) Fourth quarter 2008 includes $86.4 million for
impairments and price related adjustments and depreciation
expense.
156
Exhibits
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
**2
|
.1
|
|
Contribution Agreement, dated September 11, 2007, between
Quicksilver Resources Inc. and BreitBurn Operating
L.P. (filed as Exhibit 10.2 to the
Companys
Form 8-K
filed November 7, 2007 and included herein by reference.)
|
|
**2
|
.2
|
|
Purchase and Sale Agreement, dated as of July 3, 2008,
among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus
Development, L.P., and Perot Investment Partners, Ltd., as
Sellers, and Quicksilver Resources Inc., as Purchaser (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed July 7, 2008 and included herein by reference).
|
|
**2
|
.3
|
|
Purchase and Sale Agreement, dated as of July 3, 2008,
among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P.,
Chief Resources, LP, Hillwood Alliance Operating Company, L.P.,
Chief Resources Alliance Pipeline LLC, Chief Oil & Gas
LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark
Rollins, as Sellers, and Quicksilver Resources Inc., as
Purchaser (filed as Exhibit 10.2 to the Companys
Form 8-K
filed July 7, 2008 and included herein by reference).
|
|
3
|
.1
|
|
Amended and Restated Certificate of Incorporation of Quicksilver
Resources Inc. filed with the Secretary of State of the State of
Delaware on May 21, 2008 (filed as Exhibit 4.1 to the
Companys
Form S-3,
File
No. 333-151847,
filed June 23, 2008 and included herein by reference).
|
|
3
|
.2
|
|
Amended and Restated Certificate of Designation of Series A
Junior Participating Preferred Stock of Quicksilver Resources
Inc. (filed as Exhibit 3.3 to the Companys
Form 10-Q
filed May 6, 2006 and included herein by reference).
|
|
3
|
.3
|
|
Amended and Restated Bylaws of Quicksilver Resources
Inc. (filed as Exhibit 3.1 to the Companys
Form 8-K
filed November 16, 2007 and included herein by reference).
|
|
4
|
.1
|
|
Indenture Agreement for 1.875% Convertible Subordinated
Debentures Due 2024, dated as of November 1, 2004, between
Quicksilver Resources Inc., as Issuer, and The Bank of New York,
as Trustee (as successor in interest to JPMorgan Chase Bank,
National Association) (filed as Exhibit 4.1 to the
Companys
Form 8-K
filed November 1, 2004 and included herein by reference).
|
|
4
|
.2
|
|
First Supplemental Indenture, dated July 31, 2009, between
Quicksilver Resources Inc. and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.2
to the Companys
Form 10-Q
filed August 10, 2009 and included herein by reference).
|
|
4
|
.3
|
|
Indenture, dated as of December 22, 2005, between
Quicksilver Resources Inc. and The Bank of New York, as Trustee
(as successor in interest to JPMorgan Chase Bank, National
Association) (filed as Exhibit 4.7 to the Companys
Form S-3,
File
No. 333-130597,
filed December 22, 2005 and included herein by reference).
|
|
4
|
.4
|
|
First Supplemental Indenture, dated as of March 16, 2006,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York, as Trustee (as successor
in interest to JPMorgan Chase Bank, National Association) (filed
as Exhibit 4.1 to the Companys
Form 8-K
filed March 21, 2006 and included herein by reference).
|
|
*4
|
.5
|
|
Second Supplemental Indenture, dated as of July 31, 2006,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York, as Trustee (as successor
in interest to JPMorgan Chase Bank, National Association).
|
|
4
|
.6
|
|
Third Supplemental Indenture, dated as of September 26,
2006, among Quicksilver Resources Inc., the subsidiary
guarantors named therein and The Bank of New York, as Trustee
(as successor in interest to JPMorgan Chase Bank, National
Association) (filed as Exhibit 4.1 to the Companys
Form 10-Q
filed November 7, 2006 and included herein by reference).
|
|
*4
|
.7
|
|
Fourth Supplemental Indenture, dated as of October 31,
2007, among Quicksilver Resources Inc., the subsidiary
guarantors named therein and The Bank of New York, as Trustee
(as successor in interest to JPMorgan Chase Bank, National
Association).
|
|
4
|
.8
|
|
Fifth Supplemental Indenture, dated as of June 27, 2008,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Trust Company, N.A.,
as trustee (filed as Exhibit 4.1 to the Companys
Form 8-K
filed June 30, 2008 and included herein by reference).
|
157
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
4
|
.9
|
|
Sixth Supplemental Indenture, dated as of July 10, 2008,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.1
to the Companys
Form 8-K
filed July 10, 2008 and included herein by reference).
|
|
4
|
.10
|
|
Seventh Supplemental Indenture, dated as of June 25, 2009,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.1
to the Companys
Form 8-K
filed June 26, 2009 and included herein by reference).
|
|
4
|
.11
|
|
Eighth Supplemental Indenture, dated as of August 14, 2009,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.1
to the Companys
Form 8-K
filed August 17, 2009 and included herein by reference).
|
|
4
|
.12
|
|
Amended and Restated Rights Agreement, dated as of
December 20, 2005, between Quicksilver Resources Inc. and
Mellon Investor Services LLC, as Rights Agent (filed as
Exhibit 4.1 to the Companys
Form 8-A/A
(Amendment No. 1) filed December 21, 2005 and
included herein by reference).
|
|
10
|
.1
|
|
Wells Agreement dated as of December 15, 1970, between
Union Oil Company of California and Montana Power Company (filed
as Exhibit 10.5 to the Companys Predecessor, MSR
Exploration Ltd.s
Form S-4/A,
File
No. 333-29769,
filed August 21, 1997 and included herein by reference).
|
|
+ 10
|
.2
|
|
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.6 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.3
|
|
Form of Incentive Stock Option Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed January 28, 2005 and included herein by reference).
|
|
+ 10
|
.4
|
|
Form of Non-Qualified Stock Option Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.3 to the Companys
Form 8-K
filed January 28, 2005 and included herein by reference).
|
|
+ 10
|
.5
|
|
Form of Retention Share Agreement pursuant to the Quicksilver
Resources Inc. Amended and Restated 1999 Stock Option
and Retention Stock Plan (filed as Exhibit 10.3 to the
Companys
Form 8-K
filed April 19, 2005 and included herein by reference).
|
|
+ 10
|
.6
|
|
Form of Restricted Stock Unit Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.4 to the Companys
Form 8-K
filed April 19, 2005 and included herein by reference).
|
|
+ 10
|
.7
|
|
Quicksilver Resources Inc. Amended and Restated 2004
Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
the Companys
Form 8-K
filed May 25, 2007 and included herein by reference).
|
|
+ 10
|
.8
|
|
Form of Non-Qualified Stock Option Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 2004
Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
the Companys
Form 8-K
filed January 28, 2005 and included herein by reference).
|
|
+ 10
|
.9
|
|
Form of Restricted Share Agreement pursuant to the Quicksilver
Resources Inc. Amended and Restated 2004 Non-Employee
Director Equity Plan (filed as Exhibit 10.2 to the
Companys
Form 8-K
filed May 18, 2005 and included herein by reference).
|
|
+ 10
|
.10
|
|
Quicksilver Resources Inc. Third Amended and Restated
2006 Equity Plan (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed May 22, 2009 and included herein by reference).
|
|
+ 10
|
.11
|
|
Form of Restricted Share Agreement pursuant to the Quicksilver
Resources Inc. 2006 Equity Plan, as amended (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.12
|
|
Form of Restricted Stock Unit Agreement pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.2 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
158
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
+ 10
|
.13
|
|
Form of Quicksilver Resources Canada Inc. Restricted
Stock Unit Agreement (Cash Settlement) pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.3 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.14
|
|
Form of Quicksilver Resources Canada Inc. Restricted
Stock Unit Agreement (Stock Settlement) pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.4 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.15
|
|
Form of Incentive Stock Option Agreement pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.5 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.16
|
|
Form of Nonqualified Stock Option Agreement pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.6 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.17
|
|
Form of Non-Employee Director Nonqualified Stock Option
Agreement pursuant to the Quicksilver Resources
Inc. 2006 Equity Plan, as amended (One-Year Vesting)
(filed as Exhibit 10.8 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.18
|
|
Form of Non-Employee Director Nonqualified Stock Option
Agreement pursuant to the Quicksilver Resources
Inc. 2006 Equity Plan, as amended (Three-Year
Vesting) (filed as Exhibit 10.5 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.19
|
|
Form of Non-Employee Director Restricted Share Agreement
pursuant to the Quicksilver Resources Inc. 2006
Equity Plan, as amended (One-Year Vesting) (filed as
Exhibit 10.7 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.20
|
|
Form of Non-Employee Director Restricted Share Agreement
pursuant to the Quicksilver Resources Inc. 2006
Equity Plan, as amended (Three-Year Vesting) (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed May 25, 2007 and included herein by reference).
|
|
+ 10
|
.21
|
|
Quicksilver Resources Inc. 2008 Executive Bonus Plan
(filed as Exhibit 10.1 to the Companys
Form 8-K
filed December 14, 2007 and included herein by reference).
|
|
*+ 10
|
.22
|
|
Quicksilver Resources Inc. Amended and Restated 2009 Executive
Bonus Plan.
|
|
+ 10
|
.23
|
|
Quicksilver Resources Inc. 2010 Executive Bonus Plan
(filed as Exhibit 10.1 to the Companys
Form 8-K
filed December 10, 2009 and included herein by reference).
|
|
+ 10
|
.24
|
|
Quicksilver Resources Inc. Amended and Restated
Change in Control Retention Incentive Plan (filed as
Exhibit 10.9 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.25
|
|
Quicksilver Resources Inc. Second Amended and
Restated Key Employee Change in Control Retention Incentive Plan
(filed as Exhibit 10.8 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.26
|
|
Quicksilver Resources Inc. Amended and Restated
Executive Change in Control Retention Incentive Plan (filed as
Exhibit 10.7 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.27
|
|
Form of Director and Officer Indemnification Agreement (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed August 26, 2005 and included herein by reference).
|
|
10
|
.28
|
|
Amended and Restated Credit Agreement, dated as of
February 9, 2007, among Quicksilver Resources Inc. and the
lenders identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed February 12, 2007 and included herein by reference).
|
|
10
|
.29
|
|
Amended and Restated Credit Agreement, dated as of
February 9, 2007, among Quicksilver Resources Canada Inc.
and the lenders and/or agents identified therein (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed February 12, 2007 and included herein by reference).
|
|
* 10
|
.30
|
|
First Amendment to Combined Credit Agreements, dated as of
February 4, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein.
|
159
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
* 10
|
.31
|
|
Second Amendment to Combined Credit Agreements, dated as of
May 8, 2008, among Quicksilver Resources Inc., Quicksilver
Resources Canada Inc. and the agents and combined lenders
identified therein.
|
|
* 10
|
.32
|
|
Third Amendment to Combined Credit Agreements, dated as of
May 28, 2008, among Quicksilver Resources Inc., Quicksilver
Resources Canada Inc. and the agents and combined lenders
identified therein.
|
|
10
|
.33
|
|
Fourth Amendment to Combined Credit Agreements, dated as of
June 20, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed June 25, 2008 and included herein by reference).
|
|
10
|
.34
|
|
Fifth Amendment to Combined Credit Agreements, dated as of
August 4, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed August 5, 2008 and included herein by reference).
|
|
* 10
|
.35
|
|
Sixth Amendment to Combined Credit Agreements, dated as of
September 30, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein.
|
|
* 10
|
.36
|
|
Seventh Amendment to Combined Credit Agreements, dated as of
April 20, 2009, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein.
|
|
10
|
.37
|
|
Eighth Amendment to Combined Credit Agreements, dated as of
May 28, 2009, among Quicksilver Resources Inc., Quicksilver
Resources Canada Inc. and the agents and combined lenders
identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed June 17, 2009 and included herein by reference).
|
|
10
|
.38
|
|
Credit Agreement, dated as of August 8, 2008, among
Quicksilver Resources Inc., the lenders party thereto and Credit
Suisse, Cayman Islands Branch, as administrative agent (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed August 8, 2008 and included herein by reference).
|
|
10
|
.39
|
|
Amendment No. 1 to Credit Agreement, dated as of
June 3, 2009, among Quicksilver Resources Inc., the lenders
party thereto and Credit Suisse, Cayman Islands Branch, as
administrative agent (filed as Exhibit 10.2 to the
Companys
Form 8-K
filed June 17, 2009 and included herein by reference).
|
|
10
|
.40
|
|
Registration Rights Agreement, dated as of November 1,
2007, between Quicksilver Resources Inc. and BreitBurn Energy
L.P. (filed as Exhibit 10.1 to the Companys
Form 8-K
filed November 7, 2007 and included herein by reference).
|
|
+ 10
|
.41
|
|
Quicksilver Gas Services LP Second Amended and Restated 2007
Equity Plan (filed as Exhibit 10.16 to Quicksilver Gas
Services LPs
Form 10-K,
File
No. 001-3363,
filed March 15, 2010 and included herein by reference).
|
|
+ 10
|
.42
|
|
Form of Phantom Unit Award Agreement for
Non-Directors
pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
amended (Cash) (filed as Exhibit 10.10 to Quicksilver Gas
Services LPs
Form S-1/A,
File
No. 333-140599,
filed July 17, 2007 and included herein by reference).
|
|
+ 10
|
.43
|
|
Form of Phantom Unit Award Agreement for
Non-Directors
pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
amended (Units) (filed as Exhibit 10.11 to Quicksilver Gas
Services LPs
Form S-1/A,
File
No. 333-140599,
filed July 25, 2007 and included herein by reference).
|
|
+ 10
|
.44
|
|
Quicksilver Gas Services LP Annual Bonus Plan (filed as
Exhibit 10.1 to Quicksilver Gas Services LPs
Form 8-K,
File
No. 001-33631,
filed December 13, 2007 and included herein by reference).
|
|
+ 10
|
.45
|
|
Form of Indemnification Agreement by and between Quicksilver Gas
Services GP LLC and its officers and directors (filed as
Exhibit 10.7 to Quicksilver Gas Services LPs
Form S-1/A,
File
No. 333-140599,
filed July 17, 2007 and included herein by reference).
|
160
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
10
|
.46
|
|
Asset Purchase Agreement, dated as of May 15, 2009, among
Quicksilver Resources Inc., as Seller, and ENI US Operating Co.
Inc. and ENI Petroleum US LLC, as Buyers (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed May 19, 2009 and included herein by reference).
|
|
10
|
.47
|
|
Letter Agreement, dated as of June 15, 2009, among
Quicksilver Resources Inc., Quicksilver Resources Canada Inc.
and the agents and combined lenders identified therein (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed June 17, 2009 and included herein by reference).
|
|
* 21
|
.1
|
|
List of subsidiaries of Quicksilver Resources Inc.
|
|
* 23
|
.1
|
|
Consent of Deloitte & Touche LLP..
|
|
* 23
|
.2
|
|
Consent of PricewaterhouseCoopers LLP.
|
|
* 23
|
.3
|
|
Consent of Schlumberger Data and Consulting Services.
|
|
* 23
|
.4
|
|
Consent of LaRoche Petroleum Consultants, Ltd.
|
|
* 23
|
.5
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
* 23
|
.6
|
|
Consent of Schlumberger Data and Consulting Services.
|
|
* 31
|
.1
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
* 31
|
.2
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
* 32
|
.1
|
|
Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
* 99
|
.1
|
|
Report of Schlumberger Data and Consulting Services.
|
|
* 99
|
.2
|
|
Report of LaRoche Petroleum Consultants, Ltd.
|
|
* 99
|
.3
|
|
Report of Netherland, Sewell & Associates, Inc.
|
|
* 99
|
.4
|
|
Report of Schlumberger Data and Consulting Services.
|
|
|
|
* |
|
Filed herewith. |
|
** |
|
Excludes schedules and exhibits we agree to furnish
supplementally to the SEC upon request. |
|
+ |
|
Identifies management contracts and compensatory plans or
arrangements. |
161
SIGNATURES
Pursuant to the requirements of Section 13 of the
Securities Exchange Act of 1934, the registrant has duly caused
this Annual Report to be signed on its behalf by the
undersigned, thereunto duly authorized.
Quicksilver Resources Inc.
(the
Registrant)
Glenn Darden
President and Chief Executive Officer
Dated: March 15, 2010
Pursuant to the requirements of the Securities Exchange Act of
1934, the following persons on behalf of the registrant and in
the capacities and on the dates indicated have signed this
report below.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Thomas
F. Darden
Thomas
F. Darden
|
|
Chairman of the Board; Director
|
|
March 15, 2010
|
|
|
|
|
|
/s/ Glenn
Darden
Glenn
Darden
|
|
President and Chief Executive Officer
(Principal Executive Officer); Director
|
|
March 15, 2010
|
|
|
|
|
|
/s/ Philip
Cook
Philip
Cook
|
|
Senior Vice President Chief Financial Officer
(Principal Financial Officer)
|
|
March 15, 2010
|
|
|
|
|
|
/s/ John
C. Regan
John
C. Regan
|
|
Vice President, Controller and Chief Accounting Officer
(Principal Accounting Officer)
|
|
March 15, 2010
|
|
|
|
|
|
/s/ Anne
Darden Self
Anne
Darden Self
|
|
Director
|
|
March 15, 2010
|
|
|
|
|
|
/s/ W.
Byron Dunn
W.
Byron Dunn
|
|
Director
|
|
March 15, 2010
|
|
|
|
|
|
/s/ Steven
M. Morris
Steven
M. Morris
|
|
Director
|
|
March 15, 2010
|
|
|
|
|
|
/s/ Yandell
Rogers, III
W.
Yandell Rogers, III
|
|
Director
|
|
March 15, 2010
|
|
|
|
|
|
/s/ Mark
J. Warner
Mark
J. Warner
|
|
Director
|
|
March 15, 2010
|
162
EXHIBIT INDEX
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
**2
|
.1
|
|
Contribution Agreement, dated September 11, 2007, between
Quicksilver Resources Inc. and BreitBurn Operating
L.P. (filed as Exhibit 10.2 to the
Companys
Form 8-K
filed November 7, 2007 and included herein by reference.)
|
|
**2
|
.2
|
|
Purchase and Sale Agreement, dated as of July 3, 2008,
among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus
Development, L.P., and Perot Investment Partners, Ltd., as
Sellers, and Quicksilver Resources Inc., as Purchaser (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed July 7, 2008 and included herein by reference).
|
|
**2
|
.3
|
|
Purchase and Sale Agreement, dated as of July 3, 2008,
among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P.,
Chief Resources, LP, Hillwood Alliance Operating Company, L.P.,
Chief Resources Alliance Pipeline LLC, Chief Oil & Gas
LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark
Rollins, as Sellers, and Quicksilver Resources Inc., as
Purchaser (filed as Exhibit 10.2 to the Companys
Form 8-K
filed July 7, 2008 and included herein by reference).
|
|
3
|
.1
|
|
Amended and Restated Certificate of Incorporation of Quicksilver
Resources Inc. filed with the Secretary of State of the State of
Delaware on May 21, 2008 (filed as Exhibit 4.1 to the
Companys
Form S-3,
File
No. 333-151847,
filed June 23, 2008 and included herein by reference).
|
|
3
|
.2
|
|
Amended and Restated Certificate of Designation of Series A
Junior Participating Preferred Stock of Quicksilver Resources
Inc. (filed as Exhibit 3.3 to the Companys
Form 10-Q
filed May 6, 2006 and included herein by reference).
|
|
3
|
.3
|
|
Amended and Restated Bylaws of Quicksilver Resources
Inc. (filed as Exhibit 3.1 to the Companys
Form 8-K
filed November 16, 2007 and included herein by reference).
|
|
4
|
.1
|
|
Indenture Agreement for 1.875% Convertible Subordinated
Debentures Due 2024, dated as of November 1, 2004, between
Quicksilver Resources Inc., as Issuer, and The Bank of New York,
as Trustee (as successor in interest to JPMorgan Chase Bank,
National Association) (filed as Exhibit 4.1 to the
Companys
Form 8-K
filed November 1, 2004 and included herein by reference).
|
|
4
|
.2
|
|
First Supplemental Indenture, dated July 31, 2009, between
Quicksilver Resources Inc. and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.2
to the Companys
Form 10-Q
filed August 10, 2009 and included herein by reference).
|
|
4
|
.3
|
|
Indenture, dated as of December 22, 2005, between
Quicksilver Resources Inc. and The Bank of New York, as Trustee
(as successor in interest to JPMorgan Chase Bank, National
Association) (filed as Exhibit 4.7 to the Companys
Form S-3,
File
No. 333-130597,
filed December 22, 2005 and included herein by reference).
|
|
4
|
.4
|
|
First Supplemental Indenture, dated as of March 16, 2006,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York, as Trustee (as successor
in interest to JPMorgan Chase Bank, National Association) (filed
as Exhibit 4.1 to the Companys
Form 8-K
filed March 21, 2006 and included herein by reference).
|
|
*4
|
.5
|
|
Second Supplemental Indenture, dated as of July 31, 2006,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York, as Trustee (as successor
in interest to JPMorgan Chase Bank, National Association).
|
|
4
|
.6
|
|
Third Supplemental Indenture, dated as of September 26,
2006, among Quicksilver Resources Inc., the subsidiary
guarantors named therein and The Bank of New York, as Trustee
(as successor in interest to JPMorgan Chase Bank, National
Association) (filed as Exhibit 4.1 to the Companys
Form 10-Q
filed November 7, 2006 and included herein by reference).
|
|
*4
|
.7
|
|
Fourth Supplemental Indenture, dated as of October 31,
2007, among Quicksilver Resources Inc., the subsidiary
guarantors named therein and The Bank of New York, as Trustee
(as successor in interest to JPMorgan Chase Bank, National
Association).
|
|
4
|
.8
|
|
Fifth Supplemental Indenture, dated as of June 27, 2008,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Trust Company, N.A.,
as trustee (filed as Exhibit 4.1 to the Companys
Form 8-K
filed June 30, 2008 and included herein by reference).
|
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
4
|
.9
|
|
Sixth Supplemental Indenture, dated as of July 10, 2008,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.1
to the Companys
Form 8-K
filed July 10, 2008 and included herein by reference).
|
|
4
|
.10
|
|
Seventh Supplemental Indenture, dated as of June 25, 2009,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.1
to the Companys
Form 8-K
filed June 26, 2009 and included herein by reference).
|
|
4
|
.11
|
|
Eighth Supplemental Indenture, dated as of August 14, 2009,
among Quicksilver Resources Inc., the subsidiary guarantors
named therein and The Bank of New York Mellon
Trust Company, N.A., as trustee (filed as Exhibit 4.1
to the Companys
Form 8-K
filed August 17, 2009 and included herein by reference).
|
|
4
|
.12
|
|
Amended and Restated Rights Agreement, dated as of
December 20, 2005, between Quicksilver Resources Inc. and
Mellon Investor Services LLC, as Rights Agent (filed as
Exhibit 4.1 to the Companys
Form 8-A/A
(Amendment No. 1) filed December 21, 2005 and
included herein by reference).
|
|
10
|
.1
|
|
Wells Agreement dated as of December 15, 1970, between
Union Oil Company of California and Montana Power Company (filed
as Exhibit 10.5 to the Companys Predecessor, MSR
Exploration Ltd.s
Form S-4/A,
File
No. 333-29769,
filed August 21, 1997 and included herein by reference).
|
|
+ 10
|
.2
|
|
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.6 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.3
|
|
Form of Incentive Stock Option Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed January 28, 2005 and included herein by reference).
|
|
+ 10
|
.4
|
|
Form of Non-Qualified Stock Option Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.3 to the Companys
Form 8-K
filed January 28, 2005 and included herein by reference).
|
|
+ 10
|
.5
|
|
Form of Retention Share Agreement pursuant to the Quicksilver
Resources Inc. Amended and Restated 1999 Stock Option
and Retention Stock Plan (filed as Exhibit 10.3 to the
Companys
Form 8-K
filed April 19, 2005 and included herein by reference).
|
|
+ 10
|
.6
|
|
Form of Restricted Stock Unit Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 1999
Stock Option and Retention Stock Plan (filed as
Exhibit 10.4 to the Companys
Form 8-K
filed April 19, 2005 and included herein by reference).
|
|
+ 10
|
.7
|
|
Quicksilver Resources Inc. Amended and Restated 2004
Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
the Companys
Form 8-K
filed May 25, 2007 and included herein by reference).
|
|
+ 10
|
.8
|
|
Form of Non-Qualified Stock Option Agreement pursuant to the
Quicksilver Resources Inc. Amended and Restated 2004
Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
the Companys
Form 8-K
filed January 28, 2005 and included herein by reference).
|
|
+ 10
|
.9
|
|
Form of Restricted Share Agreement pursuant to the Quicksilver
Resources Inc. Amended and Restated 2004 Non-Employee
Director Equity Plan (filed as Exhibit 10.2 to the
Companys
Form 8-K
filed May 18, 2005 and included herein by reference).
|
|
+ 10
|
.10
|
|
Quicksilver Resources Inc. Third Amended and Restated
2006 Equity Plan (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed May 22, 2009 and included herein by reference).
|
|
+ 10
|
.11
|
|
Form of Restricted Share Agreement pursuant to the Quicksilver
Resources Inc. 2006 Equity Plan, as amended (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.12
|
|
Form of Restricted Stock Unit Agreement pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.2 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.13
|
|
Form of Quicksilver Resources Canada Inc. Restricted
Stock Unit Agreement (Cash Settlement) pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.3 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
+ 10
|
.14
|
|
Form of Quicksilver Resources Canada Inc. Restricted
Stock Unit Agreement (Stock Settlement) pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.4 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.15
|
|
Form of Incentive Stock Option Agreement pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.5 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.16
|
|
Form of Nonqualified Stock Option Agreement pursuant to the
Quicksilver Resources Inc. 2006 Equity Plan, as
amended (filed as Exhibit 10.6 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.17
|
|
Form of Non-Employee Director Nonqualified Stock Option
Agreement pursuant to the Quicksilver Resources
Inc. 2006 Equity Plan, as amended (One-Year Vesting)
(filed as Exhibit 10.8 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.18
|
|
Form of Non-Employee Director Nonqualified Stock Option
Agreement pursuant to the Quicksilver Resources
Inc. 2006 Equity Plan, as amended (Three-Year
Vesting) (filed as Exhibit 10.5 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.19
|
|
Form of Non-Employee Director Restricted Share Agreement
pursuant to the Quicksilver Resources Inc. 2006
Equity Plan, as amended (One-Year Vesting) (filed as
Exhibit 10.7 to the Companys
Form 8-K
filed May 25, 2006 and included herein by reference).
|
|
+ 10
|
.20
|
|
Form of Non-Employee Director Restricted Share Agreement
pursuant to the Quicksilver Resources Inc. 2006
Equity Plan, as amended (Three-Year Vesting) (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed May 25, 2007 and included herein by reference).
|
|
+ 10
|
.21
|
|
Quicksilver Resources Inc. 2008 Executive Bonus Plan
(filed as Exhibit 10.1 to the Companys
Form 8-K
filed December 14, 2007 and included herein by reference).
|
|
*+ 10
|
.22
|
|
Quicksilver Resources Inc. Amended and Restated 2009
Executive Bonus Plan.
|
|
+ 10
|
.23
|
|
Quicksilver Resources Inc. 2010 Executive Bonus Plan
(filed as Exhibit 10.1 to the Companys
Form 8-K
filed December 10, 2009 and included herein by reference).
|
|
+ 10
|
.24
|
|
Quicksilver Resources Inc. Amended and Restated
Change in Control Retention Incentive Plan (filed as
Exhibit 10.9 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.25
|
|
Quicksilver Resources Inc. Second Amended and
Restated Key Employee Change in Control Retention Incentive Plan
(filed as Exhibit 10.8 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.26
|
|
Quicksilver Resources Inc. Amended and Restated
Executive Change in Control Retention Incentive Plan (filed as
Exhibit 10.7 to the Companys
Form 8-K
filed November 24, 2008 and included herein by reference).
|
|
+ 10
|
.27
|
|
Form of Director and Officer Indemnification Agreement (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed August 26, 2005 and included herein by reference).
|
|
10
|
.28
|
|
Amended and Restated Credit Agreement, dated as of
February 9, 2007, among Quicksilver Resources Inc. and the
lenders identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed February 12, 2007 and included herein by reference).
|
|
10
|
.29
|
|
Amended and Restated Credit Agreement, dated as of
February 9, 2007, among Quicksilver Resources Canada Inc.
and the lenders and/or agents identified therein (filed as
Exhibit 10.2 to the Companys
Form 8-K
filed February 12, 2007 and included herein by reference).
|
|
* 10
|
.30
|
|
First Amendment to Combined Credit Agreements, dated as of
February 4, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein.
|
|
* 10
|
.31
|
|
Second Amendment to Combined Credit Agreements, dated as of
May 8, 2008, among Quicksilver Resources Inc., Quicksilver
Resources Canada Inc. and the agents and combined lenders
identified therein.
|
|
* 10
|
.32
|
|
Third Amendment to Combined Credit Agreements, dated as of
May 28, 2008, among Quicksilver Resources Inc., Quicksilver
Resources Canada Inc. and the agents and combined lenders
identified therein.
|
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
10
|
.33
|
|
Fourth Amendment to Combined Credit Agreements, dated as of
June 20, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed June 25, 2008 and included herein by reference).
|
|
10
|
.34
|
|
Fifth Amendment to Combined Credit Agreements, dated as of
August 4, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed August 5, 2008 and included herein by reference).
|
|
* 10
|
.35
|
|
Sixth Amendment to Combined Credit Agreements, dated as of
September 30, 2008, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein.
|
|
* 10
|
.36
|
|
Seventh Amendment to Combined Credit Agreements, dated as of
April 20, 2009, among Quicksilver Resources Inc.,
Quicksilver Resources Canada Inc. and the agents and combined
lenders identified therein.
|
|
10
|
.37
|
|
Eighth Amendment to Combined Credit Agreements, dated as of
May 28, 2009, among Quicksilver Resources Inc., Quicksilver
Resources Canada Inc. and the agents and combined lenders
identified therein (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed June 17, 2009 and included herein by reference).
|
|
10
|
.38
|
|
Credit Agreement, dated as of August 8, 2008, among
Quicksilver Resources Inc., the lenders party thereto and Credit
Suisse, Cayman Islands Branch, as administrative agent (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed August 8, 2008 and included herein by reference).
|
|
10
|
.39
|
|
Amendment No. 1 to Credit Agreement, dated as of
June 3, 2009, among Quicksilver Resources Inc., the lenders
party thereto and Credit Suisse, Cayman Islands Branch, as
administrative agent (filed as Exhibit 10.2 to the
Companys
Form 8-K
filed June 17, 2009 and included herein by reference).
|
|
10
|
.40
|
|
Registration Rights Agreement, dated as of November 1,
2007, between Quicksilver Resources Inc. and BreitBurn Energy
L.P. (filed as Exhibit 10.1 to the
Companys
Form 8-K
filed November 7, 2007 and included herein by reference).
|
|
+ 10
|
.41
|
|
Quicksilver Gas Services LP Second Amended and Restated 2007
Equity Plan (filed as Exhibit 10.16 to Quicksilver Gas
Services LPs
Form 10-K,
File
No. 001-3363,
filed March 15, 2010 and included herein by reference).
|
|
+ 10
|
.42
|
|
Form of Phantom Unit Award Agreement for
Non-Directors
pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
amended (Cash). (filed as Exhibit 10.10 to Quicksilver Gas
Services LPs
Form S-1/A,
File
No. 333-140599,
filed July 17, 2007 and included herein by reference).
|
|
+ 10
|
.43
|
|
Form of Phantom Unit Award Agreement for
Non-Directors
pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
amended (Units) (filed as Exhibit 10.11 to Quicksilver Gas
Services LPs
Form S-1/A,
File
No. 333-140599,
filed July 25, 2007 and included herein by reference).
|
|
+ 10
|
.44
|
|
Quicksilver Gas Services LP Annual Bonus Plan (filed as
Exhibit 10.1 to Quicksilver Gas Services LPs
Form 8-K,
File
No. 001-33631,
filed December 13, 2007 and included herein by reference).
|
|
+ 10
|
.45
|
|
Form of Indemnification Agreement by and between Quicksilver Gas
Services GP LLC and its officers and directors (filed as
Exhibit 10.7 to Quicksilver Gas Services LPs
Form S-1/A,
File
No. 333-140599,
filed July 17, 2007 and included herein by reference).
|
|
10
|
.46
|
|
Asset Purchase Agreement, dated as of May 15, 2009, among
Quicksilver Resources Inc., as Seller, and ENI US Operating Co.
Inc. and ENI Petroleum US LLC, as Buyers (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed May 19, 2009 and included herein by reference).
|
|
10
|
.47
|
|
Letter Agreement, dated as of June 15, 2009, among
Quicksilver Resources Inc., Quicksilver Resources Canada Inc.
and the agents and combined lenders identified therein (filed as
Exhibit 10.1 to the Companys
Form 8-K
filed June 17, 2009 and included herein by reference).
|
|
* 21
|
.1
|
|
List of subsidiaries of Quicksilver Resources Inc.
|
|
* 23
|
.1
|
|
Consent of Deloitte & Touche LLP.
|
|
* 23
|
.2
|
|
Consent of PricewaterhouseCoopers LLP.
|
|
|
|
|
|
Exhibit No.
|
|
Sequential Description
|
|
|
* 23
|
.3
|
|
Consent of Schlumberger Data and Consulting Services.
|
|
* 23
|
.4
|
|
Consent of LaRoche Petroleum Consultants, Ltd.
|
|
* 23
|
.5
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
* 23
|
.6
|
|
Consent of Schlumberger Data and Consulting Services.
|
|
* 31
|
.1
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
* 31
|
.2
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
* 32
|
.1
|
|
Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
* 99
|
.1
|
|
Report of Schlumberger Data and Consulting Services.
|
|
* 99
|
.2
|
|
Report of LaRoche Petroleum Consultants, Ltd.
|
|
* 99
|
.3
|
|
Report of Netherland, Sewell & Associates, Inc.
|
|
* 99
|
.4
|
|
Report of Schlumberger Data and Consulting Services.
|
|
|
|
* |
|
Filed herewith. |
|
** |
|
Excludes schedules and exhibits we agree to furnish
supplementally to the SEC upon request. |
|
+ |
|
Identifies management contracts and compensatory plans or
arrangements |