text:
Quicksilver Resources 10-K 2007 Documents found in this filing:
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Washington, D.C.
Commission file number:
(Registrants telephone
number, including area code)
Securities registered pursuant to Section 12(b) of the
Securities registered pursuant to Section 12(g) of the
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
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
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of 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, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act.
Large accelerated
filer þ
filer o Non-accelerated
filer 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, 2006, the aggregate market value of the
registrants common stock held by non-affiliates of the
registrant was $1,849,435,922 based on the closing sale price of
$36.81 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the
issuers classes of common stock, as of the latest
practicable date.
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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
All share and per share amounts have been adjusted to reflect a
stock split effected in the form of a stock dividend in June
Quantities of natural gas are expressed in this report in terms
of thousand cubic feet (Mcf), million cubic feet
(MMcf), billion cubic feet (Bcf) or
trillion cubic feet (Tcf). Crude oil and natural gas
liquids are quantified in terms of barrels (Bbl),
thousands of barrels (MBbl) or millions of barrels
(MMBbl). Crude oil and natural gas liquids are
compared to natural gas in terms of thousands of cubic feet of
natural gas equivalent (Mcfe), millions of cubic
feet of natural gas equivalent (MMcfe) or billions
of cubic feet of natural gas equivalent (Bcfe). One
barrel of crude oil or natural gas liquids is the energy
equivalent of six Mcf of natural gas. Natural gas volumes also
may be expressed in terms of one million British thermal units
(MMBtu), which is approximately equal to one Mcf.
Daily natural gas and crude oil production is signified by the
addition of the letter d to the end of the terms
defined above. With respect to information relating to working
interests in wells or acreage, net natural gas and
crude oil wells or acreage is determined by multiplying gross
wells or acreage by the working interest we own. Unless
otherwise specified, all reference to wells and acres are gross.
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We are a Fort Worth, Texas-based independent oil and gas
company engaged in the development and production of natural
gas, natural gas liquids (NGLs) and crude oil, which
we attain through a combination of developmental drilling,
exploitation and property acquisitions. Our efforts are
principally focused on unconventional reservoirs found in
fractured shales, coal seams and tight sands. We were organized
as a Delaware corporation in 1997 and became a public company in
1999 through a merger with MSR Exploration Ltd.
(MSR). Mercury Exploration Company
(Mercury), which made significant contributions of
properties to us at the time of our formation, was founded by
Frank Darden in 1963 to explore for and develop conventional oil
and gas properties in the United States. As of December 31,
2006, members of the Darden family, together with Quicksilver
Energy, L.P., an entity controlled by members of the Darden
family, beneficially owned approximately 34% of our outstanding
common stock. Thomas Darden, Glenn Darden and Anne Darden Self
serve on our Board of Directors along with four independent
directors. Thomas Darden is Chairman of our Board, Glenn Darden
is our President and Chief Executive Officer and Anne Darden
Self is our Vice President-Human Resources.
Our operations are concentrated in the Fort Worth, Michigan
and Western Canadian Sedimentary Basins. At December 31,
2006, we had estimated proved reserves of 1.57 Tcfe, of
which approximately 98% were natural gas and NGLs and
approximately 63% were proved developed. Our asset base is
geographically diverse, with approximately 45% of our reserves
in Texas, 33% in Michigan and 20% in Canada. Since going public
in 1999, we have grown our reserves and production at a compound
annual growth rate of 25% and 16%, respectively. We believe that
much of our future growth will be through development,
exploitation and exploration of our leasehold interests,
including those in the Barnett Shale formation in the
Fort Worth Basin in north Texas, coal bed methane
(CBM) formations in Alberta, Canada, and the Barnett
Shale and Woodford Shale formations in the Delaware Basin in
west Texas. Although our Michigan operations generate
significant cash flow, we believe that our future reserve and
production growth will come primarily from our Canadian and
Texas operations. These projects represent an extension of our
significant expertise in unconventional gas reserves.
We intend to focus our capital-spending program primarily on the
continued development, exploitation and exploration of our
properties in Texas and Alberta, Canada. For 2007, we have
established a capital budget of $610 million, of which we
have allocated $502 million for drilling activities,
$88 million for gathering and processing facilities,
$18 million for acquisition of additional leasehold
interests and $2 million for other property and equipment.
On a regional basis, $425 million has been allocated to the
Fort Worth Basin for drilling approximately 170 wells,
an increase of over 50 percent when compared to 2006
drilling activity. Canada has been allocated $54 million
for drilling and is expected to increase production by
approximately 10% in 2007 when compared to 2006 production. In
Michigan $18 million has been allocated for drilling in
2007. The remaining $5 million of drilling capital is
spread among our other operating areas, Indiana, Kentucky and
Montana. The budget for gathering and processing by region is
$69 million for Texas, $15 million for Canada, and
$4 million for Michigan.
For the year ended December 31, 2006, we had average daily
production of 167.8 MMcfed and total production of
61.3 Bcfe. The following table presents our proved reserves
and our average daily production for the year ended
December 31, 2006. In addition, our geographic segment
information is included at note 22 of our consolidated
financial statements included in Item 8 of this report.
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Our operations in Texas are located in the Fort Worth
Basin. Since 2003, when we began exploration and development
there, 116 (96.0 net) wells have been completed and tied
into sales. We drilled 111.3 net wells in the
Fort Worth Basin during 2006 bringing the total number of
wells we have drilled in the basin to 157 net wells through
December 31, 2006. Substantially all these wells have been
horizontal wells. We anticipate drilling an additional 160 to
180 net wells in the basin during 2007 and approximately
200 to 220 net wells in 2008. We expect that wells we plan
to drill in 2007 and 2008 will be substantially horizontal
wells. At December 31, 2006, we had 12 drilling rigs
operating for us in the Fort Worth Basin, and we expect to
increase the number of rigs to 16 during 2007. In 2006, sales
from Texas averaged 34.7 MMcfed and at December 31,
2006, our wells in the Fort Worth Basin were producing
approximately 53.9 net MMcfed. At December 31, 2006,
proved reserves from our interests in the Fort Worth Basin
totaled 703.9 Bcfe, and we held a net acreage position of
approximately 275,000 acres in Texas.
We have constructed additional infrastructure to augment our
development, exploitation and exploration of the Fort Worth
Basin. At the end of 2006, we had approximately 120 miles
of natural gas gathering lines, ranging from 2 inches to
20 inches, which we refer to as the Cowtown Pipeline. The
Cowtown Pipeline transports natural gas produced from
Quicksilver and third party wells to our natural gas processing
plant in Hood County, Texas (Cowtown Plant). We also
own a
22-mile NGL
pipeline that runs from our Cowtown Plant to a third party
pipeline interconnect. During 2007, we expect to add natural gas
gathering lines as we, and other third parties, continue to
drill and complete wells in the area. We have acquired
and are in the process of building a second NGL transportation
line to an NGL intrastate pipeline approximately four miles east
of our Cowtown Plant. Upon completion of a new
gas processing unit in early 2007, Cowtown Plant will have
processing capacity of 200 MMcfd. We have begun planning
for a third gas processing unit that we anticipate will be
operational in late 2008 and bring processing capacity to
325 MMcfd.
We conduct our Canadian operations through our wholly-owned
subsidiary, Quicksilver Resources Canada Inc.,
(QRCI), formerly known as MGV Energy Inc. Since
2003, when QRCI ended its joint venture with EnCana, we have
expanded our operations in the Western Canadian Sedimentary
Basin. Net gas sales from our projects in Alberta averaged
50.1 MMcfd for 2006 and were producing approximately
57.4 MMcfed at December 31, 2006. During 2006, we
drilled 400 (215.2 net) productive wells with
336 gross (187.2 net) wells completed and tied into
sales. Also during 2006, we installed ten CBM facilities for
processing our natural gas production. During 2007, QRCI plans
to drill 438 (225 net) wells and has included
$3 million in its 2007 drilling budget for additional
testing in its Mannville exploration project.
As of December 31, 2006, we had 308.4 Bcfe of Canadian
proved reserves, which were primarily attributable to our CBM
projects, and held approximately 234,300 net undeveloped
acres. At December 31, 2006, Canada comprised 20% of our
reserves, 30% of our annual production and approximately
$69 million, or 32%, of our cash flow from operations.
In Michigan we produce gas from the Antrim Shale as well as
non-Antrim reservoirs. Total production in Michigan for 2006
averaged 75.1 MMcfd and total proved reserves in Michigan
were 521.4 Bcfe at December 31, 2006. In the Michigan
Antrim Shale, we drilled or participated in 83 (49.3 net)
Antrim wells during 2006. Net production in 2006 for our
interests in the Antrim Shale averaged 55.6 MMcfd and
December 31, 2006 proved reserves were 451.5 Bcf. Net
production from our Michigan non-Antrim properties averaged
19.5 MMcfed. Proved reserves from our interests in our
non-Antrim properties were 69.9 Bcfe.
Production from our Indiana/Kentucky properties averaged
4.7 MMcfd for 2006 while production from our properties in
the Rocky Mountains averaged 3.3 MMcfed. At
December 31, 2006, our proved reserves were 17.4 Bcfe
from our Indiana/Kentucky interests and 16.4 Bcfe from
Rocky Mountain interests in the U.S.
High quality asset base with long reserve
life. We had total proved reserves of
1.57 Tcfe as of December 31, 2006, of which
approximately 98% were natural gas and NGLs and approximately
63% were proved developed. The majority of these reserves are
located in three core areas: the Fort Worth Basin in Texas,
the Michigan Basin and the Western Canadian Sedimentary Basin in
Alberta, Canada, which accounted for approximately 45%, 33% and
20%, respectively, of our proved reserves. Based on average
daily production of 167.8 MMcfe for the year ended
December 31, 2006, our implied reserve life (proved
reserves divided by 2006 annual production) was 25.6 years
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and our implied proved developed reserve life was
16.1 years. We believe our assets are characterized by long
reserve lives and predictable well production profiles. As of
December 31, 2006, we were the operator of approximately
78% of our proved reserves.
Significant development and exploitation drilling
inventory. As of December 31, 2006, we owned
leases covering over 1.4 million net acres in our core
areas of operation, of which 71% were undeveloped. This drilling
inventory should provide us with more than 4,000 identified
drilling locations which we expect to exploit over the next
eight to ten years. Our drilling success rate has averaged 98%
over 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. For 2007, we have
budgeted approximately $502 million for drilling projects.
Proven track record of organic reserve and production
growth. Over the last three years, we have added
approximately 865 Bcfe to our reserves, virtually all of
which was achieved organically. This growth was the result of
our ability to acquire attractive undeveloped acreage and apply
our technical expertise to find and develop reserves and was
accompanied by a significant increase in our overall production.
In recent years, we have demonstrated this ability particularly
in the Horseshoe Canyon formation in Alberta and the Barnett
Shale formation in the Fort Worth Basin. We believe our
current acreage position will enable us to continue our reserve
and production growth.
Experienced management and technical
teams. Our CEO, Glenn Darden, and our Chairman,
Thomas Darden, are founding members of our company and have held
executive positions at Quicksilver since we were formed in 1997.
They both have been in the oil and 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 reserves. Our executive management team is
supported by a core team of technical and operating managers who
have significant industry experience, including experience in
drilling and completing horizontal wells and in unconventional
Our business strategy is designed to achieve our principal
objectives of cost effective growth in reserves and production
which result in growth of earnings and cash flow. Key elements
of our business strategy include:
Focus on core areas of operation. We intend to
continue to focus on exploiting our significant development
inventory in our Barnett Shale properties in the Fort Worth
Basin and our Canadian CBM properties in the Western Canadian
Sedimentary Basin. We anticipate drilling approximately 400 net
development wells in these formations in 2007. We also plan to
continue to evaluate potential development opportunities in the
Mannville CBM in Canada by drilling resource assessment wells
and complete our evaluation of three resource assessment wells
drilled during 2006 in the Delaware Basin in west Texas. We also
plan to optimize our production in Michigan through additional
horizontal recompletions and other infill drilling
opportunities. We believe that operating in concentrated areas
allows us to more efficiently deploy our resources and manage
costs. In addition we can further leverage our base of technical
expertise in these regions.
Pursue disciplined organic growth
strategy. Through our activities in each of the
Michigan, Western Canadian Sedimentary and Fort Worth
Basins, we have developed significant expertise in developing
and operating reservoirs found in fractured shales, coal seams
and tight sands. We have focused on identifying and evaluating
opportunities that allow us to apply this expertise and
experience to the development and operation of other
unconventional reservoirs. Our Barnett Shale play in Texas and
our Horseshoe Canyon CBM play in Canada are the most significant
examples of the success of this strategy. The Delaware Basin in
Texas and the Mannville CBM in Canada represent our most recent
opportunities to apply this strategy again in areas that are
today considered exploration plays.
Enhance profitability through control and marketing of our
equity natural gas and crude oil. We seek to
maximize profitability by exercising control over the delivery
of natural gas and crude oil from the areas where we have
production to third-party distribution pipelines. We seek to
achieve this by continuing to improve upon and add to our
processing and distribution infrastructure. We believe this
allows us to better manage the physical movement
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of our production and the costs of our operations by decreasing
dependency on third-party providers. We also monitor on a daily
basis the spot markets and seek to sell our uncommitted
production into the most attractive markets.
Maintain conservative financial profile. We
believe that maintaining a conservative financial structure will
position us to capitalize on opportunities to limit our
financial risk. We have also established return thresholds for
new projects. In addition, to help ensure a level of
predictability in the prices we receive for our natural gas and
crude oil production, we have entered into natural gas sales
contracts with price floors and natural gas and crude oil
financial hedges.
We own significant natural gas and crude oil production
interests in the following geographic areas:
Our operations in the Fort Worth Basin in northern Texas
comprised approximately 45% of our estimated proved reserves and
approximately 21% of our average daily production for the year
ended December 31, 2006. The 2007 capital budget allocated
to our Texas interests is approximately $425 million for
drilling 191 (171 net) wells. We anticipate drilling
approximately 200 to 220 net wells in 2008.
During 2006, we drilled 111.3 net wells in the
Fort Worth Basin Barnett Shale and at December 31,
2006, we had drilled a total of 157 net wells in the basin and
were producing from 116 (96.0 net) wells. Our interests are
spread over an area stretching
from central Tarrant County to central Bosque County, and
from eastern Erath County through Hill County. At
December 31, 2006, we held approximately 275,000 net
acres in the Fort Worth Basin Barnett Shale play with
approximately 2,000 drilling locations.
In April 2006, we began operation of a 75 MMcfd natural gas
processing unit in Hood County, Texas. Completion of a newly
processing unit with processing capacity of 125 MMcfd is
expected in early 2007. At our Cowtown Plant, we process natural
gas to extract the NGLs from the natural gas stream and deliver
the residue gas to third party intrastate pipelines. We have
begun planning for a third processing unit that we expect to
become operational in the fourth quarter of 2008. We expect the
third unit to provide 125 MMcfd of additional capacity and
bring the total processing capacity to 325 MMcfd.
Our pipeline system located in the southern portion of the
Fort Worth Basin includes approximately 120 miles of
natural gas gathering pipelines, ranging from 2 inches to
20 inches in diameter and a
22-mile NGL
pipeline that runs from the Cowtown Plant to an interconnecting
third party pipeline. The pipeline system gathers and delivers
natural gas produced by our wells and those of third parties to
the Cowtown Plant. We expect to continue to construct additional
pipelines to gather and transport natural gas to the Cowtown
Plant as additional wells in the Fort Worth Basin are
drilled and completed. We have acquired
and are in the process of building a second NGL transportation
line to an NGL intrastate pipeline four miles east of our
Cowtown Plant. The budget for 2007 includes approximately
$69 million for our Fort Worth Basin pipelines and
natural gas processing facility.
During 2005, we acquired approximately 310,000 net acres in
a contiguous block of west Texas. We drilled three resource
assessment wells on that acreage to evaluate the Barnett and
Woodford Shales in the Delaware Basin during 2006. We are
continuing to evaluate these resource assessment wells and hope
to complete that evaluation during 2007.
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Our Michigan operations comprised approximately 33% of our
estimated proved reserves and approximately 45% of our average
daily production for the year ended December 31, 2006.
Michigan has favorable natural gas supply/demand characteristics
as the state has been importing an increasing percentage of its
natural gas and currently imports approximately 75% of its
demand. This supply/demand situation has allowed us to sell our
natural gas production at a slight premium to industry benchmark
The Antrim Shale underlies a large percentage of our Michigan
acreage and is fairly homogeneous in terms of reservoir quality;
wells tend to produce relatively predictable amounts of natural
gas in this reservoir. Subsurface fracturing can increase
reserves and production attributable to any particular well. On
average, Antrim Shale wells have a total productive life of more
than 20 years. As new wells produce and the de-watering
process takes place, they tend to reach a maximum production
level in six to 12 months, remaining at these levels for
one to two years, and then declining at 8% to 10% per year
thereafter. The wells tend to produce the best economic results
when drilled in large numbers in a fairly concentrated area.
This well concentration provides for a more rapid de-watering of
a specific area, which decreases the time to natural gas
production and increases the amount of natural gas production.
It also enables us to maximize the use of existing production
infrastructure, which decreases per unit operating costs. Since
reserve quantities and production levels over a large number of
wells are fairly predictable, maximizing per well recoveries and
minimizing per unit production costs through a sizeable
well-engineered drilling program are the keys to profitable
Antrim development.
Our non-Antrim interests are located in several reservoirs
including the Prairie du Chien (PdC), Richfield,
Detroit River Zone III (DRZ3) and Niagaran
pinnacle reefs. Depending upon the area and the particular zone,
the PdC will produce dry gas, gas and condensate or oil with
associated gas. Our PdC production is well established, and
there are numerous proved non-producing zones in existing well
bores that provide recompletion opportunities, allowing us to
maintain or, in some cases, increase production from our PdC
wells as currently producing reservoirs deplete.
Our Richfield/Detroit River wells are located in Kalkaska and
Crawford counties in the Garfield and Beaver Creek fields. The
Garfield Richfield has seven wells producing under primary
solution gas drive. Potential exploitation of the Garfield
Richfield either by secondary waterflood
improved oil recovery with CO2 injection is under evaluation;
however, because this concept has not been proved there are no
recorded reserves related to these techniques.
The DRZ3 at Beaver Creek lies approximately 200 feet above
the Richfield reservoir. We had 26 producing wells as of
December 31, 2006. Production from the DRZ3 at Beaver Creek
consists of oil with associated natural gas. While there is the
opportunity for improving production and proved reserve
quantities, we have determined that our resources are better
allocated to continued development, exploitation and exploration
of our many unconventional gas projects.
Our Niagaran wells produce from numerous
Silurian-age Niagaran pinnacle reefs located in nine
northern Michigan counties. Depending upon the location of the
specific reef in the pinnacle reef belt of the northern shelf
area, the Niagaran reefs will produce dry gas, gas and
condensate or oil with associated gas.
We began to focus on the potential of Canadian CBM through QRCI
in 2000. In late 2000, we entered into a joint venture with
EnCana to explore for and develop CBM reserves initially in the
West Palliser block in Alberta. In January 2003, we entered into
an asset rationalization agreement with EnCana that divided the
assets and rights subject to the joint venture and allowed us to
pursue independent operations. Since that time, QRCI held
interests in
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1,924 (925.3 net) productive wells at December 31,
2006. Our total Canadian proved reserves at December 31,
2006 were estimated to be 308.4 Bcf while our average daily
production in Canada for 2006 was 50.1 MMcfed.
During 2007, we expect to drill 438 (225 net) wells and
install five new CBM processing facilities. Each plant will be
capable of processing five to ten MMcfd of natural gas
production. Approximately $54 million will be committed to
Canadian drilling including approximately $3 million for
additional testing of the Mannville coals with an additional
$20 million budgeted in 2007 for gathering lines, gas
processing facilities and leasehold costs.
We began our operations in the New Albany Shale of southern
Indiana and north Kentucky in 2000 with the acquisition of 36
producing wells and an
12-inch GTG
gas pipeline that runs from southern Indiana to northern
Kentucky. Our New Albany production is transported through an
extension of our GTG gas pipeline that we constructed in 2003
and connects to the Texas Gas Pipeline in northern Kentucky. For
2006, natural gas sales from our properties in the area averaged
4.7 MMcfd.
Our Rocky Mountain properties are located in Montana and
Wyoming. Production from those properties is primarily crude oil
from well-established producing formations at depths ranging
from 1,000 feet to 17,000 feet. At December 31,
2006, our Rocky Mountain proved reserves were 2.4 MMBbls of
crude oil and 1.9 Bcfe of natural gas and NGLs for total
equivalent reserves of 16.4 Bcfe. Daily production from our
properties in the Rocky Mountain region averaged 3.3 MMcfed
for 2006.
We sell natural gas, NGLs and crude oil to a variety of
customers, including utilities, major oil and 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 a single purchaser in the areas in which we sell our
products would not materially affect our sales. During 2006, the
largest purchaser of our products was DTE Energy Trading Inc.,
which accounted for approximately 10% of our total natural gas,
NGL and crude oil sales.
We encounter substantial competition in acquiring oil and gas
leases and properties, marketing natural gas and crude oil,
securing personnel and conducting our drilling and field
operations. Our competitors in development, exploitation,
exploration, acquisitions and production include the major oil
and gas companies as well as numerous independents and
individual proprietors. See Item 1A. Risk
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 crude 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. Although we
believe we are in substantial compliance with all applicable
laws and regulations, such laws and regulations are frequently
amended or reinterpreted so we are unable to predict the future
cost or impact of complying with such laws and regulations.
Our natural exploration, development, production and pipeline
gathering operations for natural gas and crude oil are subject
to stringent U.S. and Canadian federal, state, provincial and
local laws governing the discharge of
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materials into the environment or otherwise relating to
environmental protection. Numerous governmental agencies, such
as the U.S. Environmental Protection Agency
(EPA), issue regulations to implement and enforce
such laws, and compliance is often difficult and costly. Failure
to comply may result in substantial costs and expenses,
including possible civil and criminal penalties. These laws and
regulations may:
In addition, these laws, rules and regulations may restrict the
rate of natural gas and crude oil production below the rate that
would otherwise exist. The regulatory burden on the industry
increases the cost of doing business and consequently affects
our profitability. Changes in environmental laws and regulations
occur frequently, and any changes that result in more stringent
and costly waste handling, disposal or
requirements could adversely affect our financial position,
results of operations and cash flows. While we believe that we
are in substantial compliance with current applicable
environmental laws and regulations, and we have not experienced
any materially adverse effect from compliance with these
environmental requirements, we cannot assure you that this will
continue in the future.
The U.S. Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA), also known as the
Superfund law, imposes liability, without regard to
fault or the legality of the original conduct, on certain
classes of persons who are considered to be responsible for the
release of a hazardous substance into the
environment. These persons include the present or past owners or
operators of the disposal site or sites where the release
occurred and the companies that transported or arranged for the
disposal of the hazardous substances at the site where the
release occurred. Under CERCLA, such persons may be subject to
joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the
environment, for damages to natural resources and for the costs
of certain health studies. It is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damages allegedly caused by the release of
hazardous substances or other pollutants into the environment.
Furthermore, although petroleum, including natural gas and crude
oil, is exempt from CERCLA, at least two courts have ruled that
certain wastes associated with the production of crude oil may
be classified as hazardous substances under CERCLA
and thus such wastes may become subject to liability and
regulation under CERCLA. State initiatives to further regulate
the disposal of crude oil and natural gas wastes are also
pending in certain states, and these various initiatives could
have adverse impacts on us.
Stricter standards in environmental legislation may be imposed
on the industry in the future. For instance, legislation has
been proposed in the U.S. Congress from time to time that
would reclassify certain exploration and production wastes as
hazardous wastes and make the reclassified wastes
subject to more stringent handling, disposal and
restrictions. Compliance with environmental requirements
generally could have a materially adverse effect upon our
financial position, results of operations and cash flows.
Although we have not experienced any materially adverse effect
from compliance with environmental requirements, we cannot
assure you that this will continue in the future.
The U.S. Federal Water Pollution Control Act
(FWPCA) imposes restrictions and strict controls
regarding the discharge of produced waters and other petroleum
wastes into navigable waters. Permits must be obtained to
discharge pollutants into state and federal waters. The FWPCA
and analogous state laws provide for civil, criminal and
administrative penalties for any unauthorized discharges of
crude oil and other hazardous substances in reportable
quantities and may impose substantial potential liability for
the costs of removal, remediation and damages. Federal effluent
limitation guidelines prohibit the discharge of produced water
and sand, and some other substances related to the natural gas
and crude oil industry, into coastal waters. Although the costs
to comply with zero discharge mandated under federal or state
law may be significant, the entire industry will experience
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costs and we believe that these costs will not have a materially
adverse impact on our financial condition and results of
operations. Some oil and gas exploration and production
facilities are required to obtain permits for their storm water
discharges. Costs may be incurred in connection with treatment
of wastewater or developing storm water pollution prevention
The U.S. Resource Conservation and Recovery Act
(RCRA), generally does not regulate most wastes
generated by the exploration and production of natural gas and
crude oil. RCRA specifically excludes from the definition of
hazardous waste drilling fluids, produced waters, and
other wastes associated with the exploration, development, or
production of crude oil, natural gas or geothermal energy.
However, these wastes may be regulated by the EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes,
such as paint wastes, waste solvents, laboratory wastes and
waste compressor oils, are regulated as hazardous wastes.
Although the costs of managing solid hazardous waste may be
significant, we do not expect to experience more burdensome
costs than would be borne by similarly situated companies in the
In addition, the U.S. Oil Pollution Act (OPA)
requires owners and operators of facilities that could be the
source of an oil spill into waters of the United
States, a term defined to include rivers, creeks, wetlands
and coastal waters, to adopt and implement plans and procedures
to prevent any spill of oil into any waters of the United
States. OPA also requires affected facility owners and operators
to demonstrate that they have at least $35 million in
financial resources to pay for the costs of cleaning up an oil
spill and compensating any parties damaged by an oil spill.
Substantial civil and criminal fines and penalties can be
imposed for violations of OPA and other environmental statutes.
In Canada, the oil and gas industry is currently subject to
environmental regulation pursuant to provincial and federal
legislation. Environmental legislation provides for restrictions
and prohibitions on releases or emissions of various substances
produced or utilized in association with certain oil and gas
industry operations. In addition, legislation requires that well
and facility sites be constructed, abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such
legislation may result in substantial cash expenses, including
possible fines and penalties.
In Alberta, environmental compliance has been governed by the
Alberta Environmental Protection and Enhancement Act
(AEPEA) since September 1, 1993. AEPEA imposes
environmental responsibilities on oil and gas operators in
Alberta and also imposes penalties for violations.
We file annual, quarterly and current reports, proxy statements
and other information with the Securities and Exchange
Commission, or SEC. Our SEC filings are available to the public
over the Internet at the SECs website at www.sec.gov
or from our website at www.qrinc.com. You may also
read and copy any document we file at the SECs public
reference room located at 100 F Street, N.E.,
Washington, D.C. 20549. Please call the SEC at
for further information on the operations of the public
reference room. In addition, we make available free of charge
through our Internet website at http://www.qrinc.com, our annual
report 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 Exchange Act as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the SEC.
Additionally, charters for the committees of our Board of
Directors and our Corporate Governance Guidelines and Code of
Business Conduct and Ethics can be found on our Internet website
at http://www.qrinc.com under the heading Corporate
Governance. Stockholders may request copies of these
documents by writing to the Investor Relations Department at
777 West Rosedale Street, Suite 300, Fort Worth,
Texas 76104.
As of February 15, 2007, we had 488 full time employees and
6 part time employees. There are no collective bargaining
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The following information is provided with respect to our
executive officers as of February 15, 2007.
Executive 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. The following biographies
describe the business experience of our executive officers.
THOMAS F. DARDEN has served on our Board of Directors
since December 1997. He also served at that time as President of
Mercury Exploration Company (Mercury). During his
term as President of Mercury, Mercury developed and acquired
interests in over 1,200 producing wells in Michigan, Indiana,
Kentucky, Wyoming, Montana, New Mexico and Texas. Prior to
joining us, Mr. Darden was employed by Mercury or its
parent corporation, Mercury Production Company, for
22 years. He became a director and the President of
Mountain States Resources, Inc. (MSR) on
March 7, 1997. On January 1, 1998, he was named
Chairman of the Board and Chief Executive Officer of MSR. He was
elected our President when we were formed and then Chairman of
the Board and Chief Executive Officer on March 4, 1999, the
date of our acquisition of MSR. He served as our Chief Executive
Officer until December 1999.
GLENN DARDEN has served on our Board of Directors since
December 1997. Prior to that time, he served with Mercury for
18 years, and for the last five of those 18 years was
the Executive Vice President of Mercury. Prior to working for
Mercury, Mr. Darden worked as a geologist for Mitchell
Energy Company LP (subsequently merged with Devon Energy).
Mr. Darden became a director and Vice President of MSR on
March 7, 1997, and was named President and Chief Operating
Officer of MSR on January 1, 1998. He served as our Vice
President until he was elected President and Chief Operating
Officer on March 4, 1999. Mr. Darden then became our
Chief Executive Officer in December 1999.
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 with Banc PLUS Savings Association in Houston, Texas. She
was employed as Marketing Director and then spent three years 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 Superintendent for Mercury and became Vice President
of Operations in 1991 and Executive Vice President in 1998 of
Mercury before joining us.
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. He was employed by Union Pacific Resources 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 was promoted to the position of
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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.
PHILIP COOK became our Senior Vice President
Chief Financial Officer in October 2005. From October 2004 until
October 2005, Mr. Cook served as President, Chief Financial
Officer and Director of EcoProduct Solutions, a Houston-based
chemical company. From August 2001 until September 2004, he
served as Vice President and Chief Financial Officer of PPI
Technology Services, an 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), an
independent oil and gas company engaged in exploration,
development, production and marketing.
D. WAYNE BLAIR became our Vice President, Controller
and Chief Accounting Officer in 2002, after serving as our Vice
President Controller since July 2000. He is a
Certified Public Accountant with over 25 years of
experience in the oil and gas industry. He was employed by
Sabine Corporation from 1980 through 1988 where he held the
position of Assistant Controller. From 1988 through 1994, he
served as Controller for a group of private businesses involved
in the oil and gas industry. Prior to joining us in April 2000
as Vice President Controller, he served as
Controller for Mercury since 1996.
WILLIAM S. BUCKLER became our Vice President
U.S. Operations in August 2005. He joined us in September
2003 as an Engineering Manager. Prior to that, he was an
Operations/Engineering Supervisor with Mitchell Energy Company
LP (subsequently merged with Devon Energy) from January 2002
until August 2003, and held various other positions with
Mitchell Energy, including Region Engineer, from July 1997 until
January 2002.
ROBERT N. WAGNER became our Vice President
Reservoir Engineering in December 2002. He had served 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. for over eight
years and served as both drilling engineer and production
MARLU HILLER became our Vice President
Treasurer in January 2007. Since May 2000, she had served as our
Treasurer. She is a Certified Public Accountant with over
20 years of experience in public and oil and gas
accounting. Prior to joining us in August of 1999 as Director of
Financial Reporting and Planning, she was employed at Union
Pacific Resources serving in various capacities, including
Manager of Accounting for Union Pacific Fuels, which was Union
Pacific Resources marketing company.
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. In evaluating us, you should consider carefully, among
other things, the factors and the specific risks set forth
below, and in documents we incorporate by reference. This annual
report contains forward-looking statements that involve risks
and uncertainties.
We may not maintain the current level of revenues, natural gas
and crude oil reserves or production we now attribute to the
properties contributed to us when we were formed and those
developed and acquired since our formation. Any future growth of
our natural gas and crude oil reserves, production and
operations could place significant demands on our financial,
operational and administrative resources. Our failure to sustain
profitability in the future could adversely affect the market
price of our common stock.
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Our revenues, profitability and future growth depend in part on
prevailing natural gas and crude oil prices. Prices also affect
the amount of cash flow available for capital expenditures and
our ability to borrow and raise additional capital. The amount
we can borrow under our senior secured credit facilities is
subject to periodic redetermination based in part on changing
expectations of future prices. Lower prices may also reduce the
amount of natural gas and crude oil that we can economically
While prices for natural gas and crude oil may be favorable at
any point in time, they fluctuate widely. For example, the
closing New York Mercantile Exchange (NYMEX)
wholesale price of natural gas was at a six-year low of
approximately $2.98 per Mcf for August of 2002 and reached
an all-time high of approximately $13.91 per Mcf for
October of 2005. During 2006, the closing NYMEX wholesale
natural gas price ranged from $11.45 per Mcf for January of
2006 to a low of $4.20 per Mcf for October of 2006. Among
the factors that can cause these fluctuations are:
Due to the volatility of natural gas and crude oil prices and
our inability to control the factors that affect natural gas and
crude oil prices, we cannot predict whether prices will remain
at current levels, increase or decrease in the future.
Our financial statements are prepared in accordance with
generally accepted accounting principles. The reported financial
results and disclosures were developed using certain significant
accounting policies, practices and estimates, which are
discussed in the Managements Discussion and Analysis of
Financial Condition and Results of Operations section in this
annual report. We employ the full cost method of accounting
whereby all costs associated with acquiring, exploring for, and
developing natural gas and crude oil reserves are capitalized
and accumulated in separate country cost centers. These
capitalized costs are amortized based on production from the
reserves for each country cost center. Each capitalized cost
pool cannot exceed the net present value of the underlying
natural gas and crude oil reserves. A write down of these
capitalized costs could be required if natural gas
and/or crude
oil prices were to drop precipitously at a reporting period end.
Future price declines or increased operating and capitalized
costs without incremental increases in natural gas and crude oil
reserves could also require us to record a write down.
The process of estimating natural gas and crude oil reserves is
complex. It requires interpretations of available technical data
and various assumptions, including assumptions relating to
economic factors. Any significant inaccuracies in these
interpretations or assumptions could materially affect the
estimated quantities and present value of reserves disclosed in
this annual report.
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In order to prepare these estimates, we and independent reserve
engineers engaged by us must project production rates and timing
of development expenditures. We and the engineers must also
analyze available geological, geophysical, production and
engineering data, and the extent, quality and reliability of
this data can vary. The process also requires economic
assumptions with respect to natural gas and crude oil prices,
drilling and operating expenses, capital expenditures, taxes and
availability of funds. Therefore, estimates of natural gas and
crude oil reserves are inherently imprecise.
Actual future production, natural gas and crude oil prices and
revenues, taxes, development expenditures, operating expenses
and quantities of recoverable natural gas and crude oil reserves
most likely will vary from our estimates. Any significant
variance could materially affect the estimated quantities and
present value of reserves disclosed in this annual report. In
addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development,
prevailing natural gas and crude oil prices and other factors,
many of which are beyond our control.
At December 31, 2006, approximately 37% of our estimated
proved reserves were undeveloped. Undeveloped reserves, by their
nature, are less certain. Recovery of undeveloped reserves
requires significant capital expenditures and successful
drilling operations. Our reserve data assumes that we will make
significant capital expenditures to develop our reserves.
Although we have prepared estimates of our natural gas and crude
oil reserves and the costs associated with these reserves in
accordance with industry standards and SEC requirements, we
cannot assure you that the estimated costs are accurate, that
development will occur as scheduled or that actual results will
be as estimated.
You should not assume that the present value of future net
revenues disclosed in this annual report is the current market
value of our estimated natural gas and crude oil reserves. In
accordance with SEC requirements, the estimated discounted
future net cash flows from proved reserves are generally based
on prices and costs as of the date of the estimate. Actual
future prices and costs may be materially higher or lower than
the prices and costs as of the date of the estimate. Any changes
in consumption by natural gas and crude oil purchasers or in
governmental regulations or taxation will also affect actual
future net cash flows. The timing of both the production and the
expenses from the development and production of natural gas and
crude oil properties will affect the timing of actual future net
cash flows from proved reserves and their present value. In
addition, the 10% discount factor, which is required by the SEC
to be used in calculating discounted future net cash flows for
reporting purposes, is not necessarily the most accurate
discount factor. The effective interest rate at various times
and the risks associated with our business or the oil and gas
industry in general will affect the accuracy of the 10% discount
Approximately 45% of our 2006 production was from Michigan,
approximately 30% was from Alberta, Canada and approximately 21%
was from Texas. Because of our concentration in these geographic
areas, any regional events that increase costs, reduce
availability of equipment or supplies, reduce demand or limit
production, including weather and natural disasters, may impact
us more than if our operations were more geographically
If our production levels were significantly reduced to levels
below those for which we have entered into contractual delivery
commitments, we would be required to purchase natural gas at
market prices to fulfill our obligation under certain long-term
contracts. This could adversely affect our cash flow to the
extent any such shortfall related to our sales contracts with
floor pricing.
We conduct our Canadian operations through Quicksilver Resources
Canada Inc. At December 31, 2006, our proved Canadian
reserves were estimated to be 308 Bcf. Capital expenditures
relating to QRCIs operations are budgeted to be
approximately $74 million in 2007, constituting
approximately 12% of our total 2007 budgeted capital
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We expect that our 2007 Canadian capital budget will be funded
from Canadian operating cash flow. If our revenues decrease as a
result of lower natural gas or crude oil prices or otherwise, we
may be unable to fund our entire 2007 Canadian capital budget,
or may opt to increase our Canadian debt levels to
fund 2007 capital expenditures. While our results to date
indicate that net recoverable reserves on CBM lands could be
substantial, we can offer you no assurance that development will
occur as scheduled or that actual results will be in accordance
with estimates.
Other risks of our operations in Canada include, among other
things, increases in taxes and governmental royalties, changes
in laws and policies governing operations of foreign-based
companies, currency restrictions and exchange rate fluctuations.
Laws and policies of the United States affecting foreign trade
and taxation may also adversely affect our Canadian operations.
We have experienced and expect to continue to experience
substantial capital expenditure and working capital needs,
particularly as a result of increases in our property
acquisition and drilling activities. In the future, we will
likely require additional financing in addition to cash
generated from our operations to fund our planned growth. If
revenues decrease as a result of lower natural gas or crude oil
prices or otherwise, our ability to expend the capital necessary
to replace our reserves or to maintain production of current
levels may be limited, resulting in a decrease in production
over time. If our cash flow from operations is not sufficient to
satisfy our capital expenditure requirements, we cannot be
certain that additional financing will be available to us on
acceptable terms or at all. In the event additional capital
resources are unavailable, we may curtail our acquisition,
development drilling and other activities or be forced to sell
some of our assets on an untimely or unfavorable basis.
The oil and gas business involves operating hazards such as well
blowouts, explosions, uncontrollable flows of crude oil, natural
gas or well fluids, fires, formations with abnormal pressures,
treatment plant downtime, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental
hazards and risks, any of which could cause us to experience
substantial losses. Also, the availability of a ready market for
our natural gas and crude oil production depends on the
proximity of reserves to, and the capacity of, natural gas and
crude oil gathering systems, treatment plants, pipelines and
trucking or terminal facilities.
U.S. and Canadian federal, state and provincial regulation of
oil and 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 and crude oil. In addition, we may be
liable for environmental damage caused by previous owners of
properties purchased or leased by us.
As a result of operating hazards, regulatory risks and other
uninsured risks, we could incur substantial liabilities to third
parties or governmental entities, the payment of which could
reduce or eliminate funds available for exploration, development
or acquisitions. We maintain insurance against some, but not
all, of such risks and losses in accordance with customary
industry practice. Generally, environmental risks are not fully
insurable. The occurrence of an event that is not covered, or
not fully covered, by insurance could have a material adverse
effect on our business, financial condition and results of
A portion of our growth in recent years has been due to
acquisitions of producing properties. We expect to continue to
evaluate and, where appropriate, pursue acquisition
opportunities on terms our management considers to be favorable
to us. We cannot assure you that we will be able to identify
suitable acquisitions in the future, or that we will be able to
finance these acquisitions on favorable terms or at all. In
addition, we compete against other companies for acquisitions,
and we cannot assure you that we will be successful in the
acquisition of any material producing property interests.
Further, we cannot assure you that any future acquisitions that
we make will be integrated successfully into our operations or
will achieve desired profitability objectives.
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The successful acquisition of producing properties requires an
assessment of recoverable reserves, exploration potential,
future natural gas and crude oil prices, operating costs,
potential environmental and other liabilities and other factors
beyond our control. These assessments are inexact and their
accuracy inherently uncertain, and such a review may not reveal
all existing or potential problems, nor will it necessarily
permit us to become sufficiently familiar with the properties to
fully assess their merits and deficiencies. Inspections may not
always be performed on every well, and structural and
environmental problems are not necessarily observable even when
an inspection is undertaken.
In addition, significant acquisitions can change the nature of
our operations and business depending upon the character of the
acquired properties, which may be substantially different in
operating and geological characteristics or geographic location
than existing properties. While our current operations are
located primarily in Michigan, Alberta, Canada, Texas, Indiana,
Kentucky and Montana, we cannot assure you that we will not
pursue acquisitions of properties in other locations.
Our future success depends upon our ability to find, develop or
acquire additional natural gas and crude oil reserves that are
economically recoverable. Our proved reserves, a majority of
which are in the mature Michigan Basin, will generally decline
as reserves are depleted, except to the extent that we conduct
successful exploration or development activities or acquire
properties containing proved reserves, or both. In order to
increase reserves and production, we must continue our
development drilling and recompletion programs or undertake
other replacement activities. Our current strategy is to
maintain our focus on low-cost operations while increasing our
reserve base, production and cash flow through development and
exploration of our existing properties and acquisitions of
producing properties. We cannot assure you, however, that our
planned exploration and development projects and acquisition
activities will result in significant additional reserves or
that we will have continuing success drilling productive wells.
Furthermore, while our revenues may increase if prevailing
natural gas and crude oil prices increase significantly, our
finding costs for additional reserves also could increase.
As of December 31, 2006, other companies operated
properties that included approximately 22% of our proved
reserves. As a result, we have a limited ability to exercise
influence over operations for these properties or their
associated costs. Our dependence on the operator and other
working interest owners for these projects and our limited
ability to influence operations and associated costs could
materially adversely affect the realization of our targeted
returns on capital in drilling or acquisition activities. As a
result, the success and timing of our drilling and development
activities on properties operated by others depend upon a number
of factors that are outside of our control, including:
At December 31, 2006, other companies owned processing
plants and pipelines that delivered approximately 64% of our
natural gas production to market in Michigan. Our Canadian
production is delivered to market primarily by either the
TransCanada or ATCO systems. We have no influence over the
operation of these facilities and must depend upon the owners of
these facilities to minimize any loss of processing and
transportation capacity.
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Our operations are dependent on a relatively small group of key
management personnel, including our Chairman, our Chief
Executive Officer and our other executive officers and key
technical personnel. We cannot assure you that the services of
these individuals will be available to us in the future. Because
competition for experienced personnel in the oil and gas
industry is intense, we cannot assure you that we would be able
to find acceptable replacements with comparable skills and
experience in the oil and gas industry. Accordingly, the loss of
the services of one or more of these individuals could have a
detrimental effect on us.
We compete with major and independent oil and gas companies for
property acquisitions. We also compete for the equipment and
labor required to develop and operate these properties. Many of
our competitors have substantially greater financial and other
resources than we do. In addition, larger competitors may be
able to absorb the burden of any changes in federal, state,
provincial and local laws and regulations more easily than we
can, which would adversely affect our competitive position.
These competitors may be able to pay more for exploratory
prospects and productive natural gas and crude oil properties
and may be able to define, evaluate, bid for and purchase a
greater number of properties and prospects than we can. Our
ability to explore for natural gas and crude oil prospects and
to acquire additional properties in the future will depend on
our ability to conduct operations, to evaluate and select
suitable properties and to complete transactions in this highly
competitive environment. Furthermore, the oil and gas industry
competes with other industries in supplying the energy and fuel
needs of industrial, commercial, and other consumers.
Our long-term natural gas contracts, which extend through March
2009, accounted for the sale of approximately 27% of our natural
gas production and for a significant portion of our total
revenues in 2006. We cannot assure you that the other parties to
these contracts will continue to perform under the contracts. If
the other parties were to default after taking delivery of our
natural gas, it could have a material adverse effect on our cash
flows for the period in which the default occurred. A default by
the other parties prior to taking delivery of our natural gas
could also have a material adverse effect on our cash flows for
the period in which the default occurred depending on the
prevailing market prices of natural gas at the time compared to
the contractual prices.
To reduce our exposure to fluctuations in the prices of natural
gas and crude oil, we have entered into natural gas and crude
oil hedging arrangements. These hedging arrangements tend to
limit the benefit we would receive from increases in the prices
of natural gas and crude oil. These hedging arrangements also
expose us to risk of financial losses in some circumstances,
including the following:
The result of natural gas and crude oil market prices exceeding
our swap prices requires us to make payment for the settlement
of our hedge derivatives on the fifth day of the production
month for natural gas hedges and the fifth day after the
production month for crude oil hedges. We do not receive market
price cash payments from our customers until 25 to 60 days
after the end of the production month. This could have a
material adverse effect on our cash flows for the period between
hedge settlement and payment for revenues earned.
If we choose not to engage in hedging arrangements in the
future, we may be more adversely affected by changes in natural
gas and crude oil prices than our competitors who engage in
hedging arrangements.
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There is currently a high demand for and a general shortage of
drilling equipment and supplies. Higher oil and natural gas
prices generally stimulate increased demand and result in
increased prices for drilling equipment, crews and associated
supplies, equipment and services. We believe that these
shortages could continue. Accordingly, we cannot assure you that
we will be able to obtain necessary drilling equipment and
supplies in a timely manner or on satisfactory terms, and we may
experience shortages of, or material increases in the cost of,
drilling equipment, crews and associated supplies, equipment and
services in the future. Any such delays and price increases
could adversely affect our ability to pursue our drilling
program and our results of operations.
Natural gas and crude oil operations are subject to various U.S.
and Canadian federal, state, provincial and local government
laws and regulations that may be changed from time to time in
response to economic or political conditions. Matters that are
typically regulated include:
From time to time, regulatory agencies have imposed price
controls and limitations on production by restricting the rate
of flow of natural gas and crude oil wells below actual
production capacity to conserve supplies of natural gas and
crude oil. We also are subject to changing and extensive tax
laws, the effects of which cannot be predicted.
The development, production, handling, storage, transportation
and disposal of natural gas and crude oil, by-products and other
substances and materials produced or used in connection with
natural gas and crude oil operations are also subject to laws
and regulations primarily relating to protection of human health
and the environment. The discharge of natural gas, crude oil or
pollutants into the air, soil or water may give rise to
significant liabilities on our part to the government and third
parties and may result in the assessment of civil or criminal
penalties or require us to incur substantial costs of
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 have a substantial amount of indebtedness. At
December 31, 2006, we had total consolidated debt of
$919.5 million. Subject to the limits contained in the loan
agreements governing our senior secured revolving credit
facilities and the indenture governing our senior subordinated
notes, we may incur additional debt. Our ability to borrow under
our senior secured revolving credit facilities is subject to the
quantity of proved reserves attributable to our natural gas and
crude oil properties. One of our senior secured revolving credit
facilities enables us to borrow significant amounts in Canadian
dollars to fund and support our operations in Canada. Such
indebtedness exposes us to currency exchange risk associated
with the Canadian dollar. If we incur additional indebtedness or
fail to
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increase the quantity of proved reserves attributable to our
natural gas and crude oil properties, 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 on our indebtedness, including, among others, operating
expenses and principal payments under our senior secured
revolving credit facilities, our senior subordinated notes and
our convertible subordinated debentures. Our level of
indebtedness relative to our proved reserves and these
significant demands on our cash resources could have important
effects on our business and on your investment in Quicksilver.
For example, they could:
Our ability to pay principal and interest on our long-term debt
and to satisfy our other liabilities will depend upon our future
performance and our ability to refinance our debt as it becomes
due. Our future operating performance and ability to refinance
will be affected by economic and capital markets conditions, our
financial condition, results of operations and prospects and
other factors, many of which are beyond our control.
If we are unable to service our indebtedness and fund our
operating costs, we will be forced to adopt alternative
strategies that may include:
There can be no assurance that any such strategies could be
implemented on satisfactory terms, if at all.
The loan agreements governing our senior secured revolving
credit facilities and the indenture governing our senior
subordinated notes restrict our ability to, among other things:
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The loan agreements for our senior secured revolving credit
facilities and the indentures governing our senior subordinated
notes contain certain covenants, which, among other things,
require the maintenance of a minimum current ratio, a minimum
collateral coverage ratio, a minimum earnings (before interest,
taxes, depreciation, depletion and amortization, non-cash income
and expense, and exploration costs) to interest expense ratio,
and a minimum earnings (before interest, taxes, depreciation,
depletion, accretion and amortization, non-cash income and
expense and exploration costs) to fixed charges ratio. Our
ability to borrow under our senior secured revolving credit
facilities is dependent upon the quantity of proved reserves
attributable to our natural gas and crude oil properties. Our
ability to meet these covenants or requirements may be affected
by events beyond our control, and we cannot assure you that we
will satisfy such covenants and requirements.
The covenants contained in the agreements governing our debt may
affect our flexibility in planning for, and reacting to, changes
in business conditions. In addition, a breach of the restrictive
covenants in our loan agreements or the indenture governing our
senior subordinated notes, or any instrument governing our
future indebtedness, or our inability to maintain the financial
ratios described above could result in an event of default under
the applicable instrument. Upon the occurrence of such an event
of default, the applicable creditors could, subject to the terms
and conditions of the applicable instrument, elect to declare
the outstanding principal of that debt, together with accrued
interest, to be immediately due and payable. Moreover, any of
our debt agreements that contain a cross-default or
cross-acceleration provision that would be triggered by such
default or acceleration would also be subject to acceleration
upon the occurrence of such default or acceleration. If we were
unable to repay amounts due under our senior secured revolving
credit facilities, the creditors could proceed against the
collateral granted to them to secure such indebtedness. If the
payment of our indebtedness is accelerated, there can be no
assurance that our assets would be sufficient to repay in full
such indebtedness and our other indebtedness that would become
due as a result of any acceleration. The above restrictions
could limit our ability to obtain future financing and may
prevent us from taking advantage of attractive business
Members of the Darden family, together with Quicksilver Energy,
L.P., which is primarily owned by members of the Darden family,
beneficially own on the date of this annual report approximately
34% of our common stock. As a result, these entities and
individuals will generally be able to control 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.
Our shares that are eligible for future sale may have an adverse
effect on the price of our common stock. There were
77,601,922 shares of our common stock outstanding at
December 31, 2006. Approximately 49,821,419 of these shares
are freely tradable without substantial restriction or the
requirement of future registration under the Securities Act. In
addition, our contingently convertible debentures are
convertible upon the satisfaction of certain conditions. Based
on the conversion rate in effect at December 31, 2006, if
the conditions permitting the conversion of all of our
outstanding contingently convertible debentures are satisfied
and all of the outstanding debentures are
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converted, an aggregate of 4,908,135 shares of our common
stock would be issued. At December 31, 2006 we had the
following options outstanding to purchase shares of our common
Sales of substantial amounts of common stock, or a perception
that such sales could occur, and the existence of options to
purchase 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
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, such as:
In addition, we have adopted a stockholder rights plan. The
provisions described above and the stockholder rights plan could
impede a merger, consolidation, takeover or other business
combination involving us or discourage a potential acquirer from
making a tender offer or otherwise attempting to take control of
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.
A portion of the information called for by this Item is
incorporated herein by reference to the information in
Item 1 of this report under the heading
Properties. U.S. borrowings under our senior secured
credit facility are secured by our and certain of our domestic
subsidiaries oil and gas properties, and Canadian
borrowings under our senior secured credit facility are secured
by QRCIs, our and certain of our domestic
subsidiaries oil and gas properties.
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The following reserve quantity and future net cash flow
information concerns our proved reserves that are located in the
United States and Canada. Independent petroleum engineers with
Schlumberger Data and Consulting Services and LaRoche Petroleum
Consultants, Ltd. prepared our reserve estimates for our United
States and Canadian properties, respectively. Proved oil and gas
reserves, as defined by SEC
Regulation S-X
Rule 4-10(a)
2(i), 2(ii), 2(iii), (3) and (4), are the estimated
quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions (i.e., prices and costs as of the date the estimate
is made). Prices include consideration of changes in existing
prices provided by contractual arrangements, but not of
escalations based upon expected future conditions. Prices
include the effect of our derivative instruments. Future
production and development costs include production and property
Proved developed oil and gas reserves are reserves that are
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as proved
developed reserves only after testing by a pilot project or
after the operation of an installed program has confirmed
through production response that increased recovery will be
Proved undeveloped oil and gas reserves are reserves that 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. Reserves on undrilled acreage are
limited to those drilling units offsetting productive units that
are reasonably certain of production when drilled. Proved
reserves for other undrilled units are claimed only where it can
be demonstrated with certainty that there is continuity of
production from the existing productive formation.
The reserve data set forth in this document represents only
estimates and is subject to inherent uncertainties. The
determination of oil and gas reserves is based on estimates that
are highly complex and interpretive. Reserve engineering is a
subjective process that is dependent on the quality of available
data and on engineering and geological interpretation and
judgment. Although we believe the reserve estimates contained in
this document are reasonable, reserve estimates are imprecise
and are expected to change as additional information becomes
The following table summarizes our proved reserves and the
standardized measure of discounted future net cash flows
attributable to them at December 31, 2006, 2005 and 2004.
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The following table sets forth certain information regarding
production, average unit prices and costs for the periods
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During the periods indicated, the Company drilled or
participated in the drilling of the following exploratory and
development wells:
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The following table summarizes productive oil and gas wells
attributable to our direct interests as of December 31,
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Our principal natural gas and crude oil properties consist of
non-producing and producing natural gas and crude oil leases,
including reserves of natural gas and crude oil in place. The
table found below indicates our interest in developed and
undeveloped acreage held directly by us. Developed acres are
defined as acreage spaced or 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 quantities of
crude oil, condensate or natural gas, regardless of whether or
not 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
The following table lists the total number of net undeveloped
acres as of December 31, 2006, and, with respect to those
acres for 2007, 2008 and 2009, the number of net acres expiring,
and, where applicable, the number of net acres expiring that are
subject to options to extend. The option to extend varies from
lease to lease and covers periods from one to five years;
however, the majority of the options to extend are for two years.
All of the acreage scheduled to expire can be held through
drilling operations. We believe that we have the ability to hold
all of the expiring acreage that we feel is prospective of
economic production through the drilling of wells and, where
applicable, through the exercise of extension options to be
followed by drilling prior to final expiration.
In August 2001, a group of royalty owners, Athel E. Williams
et al., brought suit against the Company and three of its
subsidiaries in the Circuit Court of Otsego County, Michigan.
The suit alleges that Terra Energy Ltd., one of
Quicksilvers subsidiaries, underpaid royalties or
overriding royalties to the 13 named plaintiffs and to a class
of plaintiffs who have yet to be determined. The pleadings of
the plaintiffs seek damages in an unspecified amount and
injunctive relief against future underpayments. On
January 21, 2005, the Circuit Court issued an order
certifying certain claims to proceed on behalf of a class. On
July 25, 2006, the Michigan Court of Appeals reversed the
certification of all claims on appeal and remanded the case to
the trial court for further proceedings. Based on information
currently available to us, we believe that the final resolution
of this matter will not have a material effect on our financial
position, results of operations, or cash flows.
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On October 13, 2006, we filed suit in the
342nd Judicial
District Court in Tarrant County, Texas against Eagle Drilling,
LLC and Eagle Domestic Drilling Operations, LLC (successor in
interest to Eagle Drilling, together Eagle)
regarding three contracts for drilling rigs in which we allege
that the first rig furnished by Eagle exhibited operating
deficiencies and safety defects. We seek a declaratory judgment
that (i) the contracts are void and (ii) that Eagle is
not entitled to early termination compensation provided for in
the contracts. We also seek rescission of the contracts and
claim we are entitled to recover damages incurred due to
Eagles failure to perform. On October 23, 2006, Eagle
Domestic Drilling sued us in District Court of Cleveland County,
Oklahoma for (i) breach of contract as to each of the three
drilling contracts alleging damages of $29 million plus
punitive damages and interest and (ii) tortious breach of
contract alleging damages in an unspecified amount in excess of
$10,000. Eagle Domestic Drilling also sought a declaratory
judgment that, among other things, the contracts are valid and
binding. Subsequently, on January 19, 2007, Eagle Domestic
Drilling and its parent, Blast Energy Services, Inc., filed for
Chapter 11 bankruptcy the United States Bankruptcy Court
for the Southern District of Texas, Houston Division. At the
date of this filing, the suit in Tarrant County is still
pending, but is stayed. On February 21, 2007, the lawsuit
in Cleveland County was dismissed. Based upon information
currently available, we believe that the final resolution of
this matter will not have a material effect on our financial
condition, results of operations, or cash flows.
There were no matters submitted to a stockholder vote during the
fourth quarter of 2006.
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.
As of February 15, 2007, there were approximately 561
common stockholders of record.
We have not paid 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, our senior secured
credit facility prohibits payments of dividends on our common
stock and purchases of common stock. The indenture for our
senior subordinated notes prohibits payments on our common stock.
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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) and the Dow Jones U.S. Exploration and
Production Index (formerly the Dow Jones Secondary Oils Index)
for the period from December 31, 2001 to December 31,
2006, assuming an initial investment of $100 and the
reinvestment of all dividends, if any.
of Cumulative Five Year Total Return
The following table summarizes the Companys repurchases of
its common stock during the quarter ended December 31, 2006.
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The following table sets forth, as of the dates and for the
periods indicated, our selected financial information. Our
financial information 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 document. The following information is not
necessarily indicative of our future results.
Financial Data
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The following Managements Discussion and Analysis
(MD&A) is intended to help the reader understand
our business, financial condition, results of operations,
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 on
Form 10-K,
including: Item 1. Business, Item 2.
Properties, Item 6. Selected Financial
Data, and Item 8. Financial Statements and
Supplementary Data. Our MD&A includes the following
We are a Fort Worth, Texas-based independent oil and gas
company engaged in the development, exploitation, exploration,
acquisition, and production of natural gas, NGLs, and crude oil
primarily from unconventional reservoirs where hydrocarbons are
found in challenging geological conditions such as fractured
shales, coal beds and tight sands. We generate revenue, income
and cash flows by producing and selling natural gas, NGLs, and
crude oil. We produce these products in quantities and at prices
that, in addition to generating operating income, allow us to
conduct development, exploitation, exploration and acquisition
activities to replace the reserves that have been produced.
At December 31, 2006, approximately 98% of our proved
reserves were natural gas and natural gas liquids. Approximately
33% of our proved reserves were located in Michigan. Our
activities in the Michigan Basin Antrim shale have allowed us to
develop a technical and operational expertise in the
development, exploitation, exploration, acquisition and
production of unconventional natural gas reserves. Consistent
with one of our business strategies, we have applied the
expertise gained in our Michigan activities to our Canadian
projects in Alberta, Canada and our Barnett Shale interests in
the Fort Worth Basin in Texas. Our Texas and Alberta
reserves made up about 45% and 20%, respectively of our proved
reserves at December 31, 2006. The Delaware Basin in west
Texas and the Mannville CBM in Alberta represent our most recent
opportunities to apply this expertise.
For 2007, we plan to continue our focus on the continued
development, exploitation and exploration of our properties in
Texas and Alberta. We have allocated $502 million of our
2007 capital budget of $610 million for drilling
activities. Approximately $425 million is allocated to our
Barnett Shale position in the Forth Worth Basin in Texas and
approximately $54 million is allocated to our Canadian CBM
projects. Approximately $18 million of the 2007 drilling
budget has been dedicated to our fractured shale projects in the
Michigan Basin, with the remaining $5 million planned for
our projects in Indiana/Kentucky and the Rockies.
Our Company focuses on three key value drivers:
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The Companys reserve growth is dependent upon our ability
to apply the Companys 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 relatively low-risk development and exploitation
drilling. We will also continue to identify high potential
exploratory projects with higher levels of financial risk. Both
our lower-risk development programs and higher-risk exploratory
projects are aimed at providing the Company with opportunities
to develop and exploit unconventional natural gas reservoirs to
which our technical and operational expertise is well suited.
Our principal properties are well suited for production
increases through development and exploitation drilling. We
perform workover and infrastructure projects to reduce operating
costs and increase current and future production. We regularly
review operations on operated properties to determine if steps
can be taken to profitably increase reserves and production.
As these elements are implemented, our results are measured
through the following key measurements: reserve growth;
production growth; cash flow from operating activities; and
earnings per share.
The possibility of decreasing prices received for production is
among the several risks that we face. We seek to manage this
risk by entering into natural gas sales contracts with price
floors and natural gas and crude oil financial hedges. Our use
of pricing collars and, to a lesser degree, fixed price swaps
for both natural gas and crude oil helps to ensure a predictable
base level of cash flow while allowing us to participate in a
portion of any favorable price increases. This commodity price
strategy enhances our ability to execute our development,
exploitation and exploration programs, meet debt service
requirements and pursue acquisition opportunities despite price
fluctuations. If our revenues were to decrease significantly as
a result of presently unexpected declines in natural gas prices
or otherwise, we could be forced to curtail our drilling and
acquisition activities. We might also be forced to sell some of
our assets on an untimely or unfavorable basis.
Prices for natural gas and crude oil fluctuate widely. For
example, the closing NYMEX wholesale price of natural gas was at
an all-time high of approximately $13.91 per Mcf for
October 2005 before dropping to approximately $4.20 per Mcf
for October 2006. For February 2007 natural gas production, the
wholesale price of natural gas was approximately $6.92 Mcf.
Assuming natural gas prices remain at relatively favorable
levels, we expect to fund more of our capital expenditures with
cash flow from operating activities; however, we do not expect
our cash flow from operating activities to be sufficient to
satisfy our total budgeted capital expenditures. We plan to use
cash flows from operations, credit facility utilization,
possible sales of assets and issuance of debt or equity
securities to fund our total budgeted capital expenditures in
Our wholly-owned subsidiary that will hold Cowtown Plant and the
Cowtown Pipeline has filed a registration statement on
Form S-1
relating to the offering of approximately 19% of its limited
partner interests to the public. Numerous factors, such as
general market conditions and market conditions in the oil and
gas industry in particular, could result in this offering not
being completed.
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We have established policies and procedures for managing risk
within our organization, including internal controls. The level
of risk assumed by us is based on our objectives and capacity to
manage risk.
Our primary risk exposure is related to natural gas and crude
oil commodity prices. We have mitigated the downside risk of
adverse price movements through the use of long-term sales
contracts, swaps and collars; however, in doing so, we have also
limited future gains from favorable price movements.
Price Risk
We enter into long-term natural gas sales contracts and
financial derivative contracts to hedge our exposure to
commodity price risk associated with anticipated future natural
gas production. We sell approximately 10 MMcfd and
25 MMcfd of natural gas under long-term contracts with
floor prices of $2.47 per Mcf and $2.49 per Mcf,
respectively, through March 2009. Approximately 31.2 MMcfd
of our natural gas production was sold under these contracts in
2006 and the remainder were third-party volumes controlled by
us. We also enter into financial derivative contracts that
include price floors, no-cost collars and fixed price swaps to
hedge our exposure to commodity price risk associated with
anticipated future production of natural gas, crude oil and
condensate and NGLs.
Currently, natural gas price collars have been put in place to
hedge 2007 anticipated production of approximately
123 MMcfd. Additionally, we have used price collar
agreements to hedge approximately 1,250 Bbld of its crude
oil, condensate and NGL anticipated production for 2007.
Anticipated 2008 natural gas production of approximately
35 MMcfd has also been hedged using price collars and an
additional 40 MMcfd of natural gas production has been
hedged using fixed price swaps. We believe we will have more
predictability of our natural gas and crude oil revenues as a
result of these long-term sales and financial derivative
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The following table summarizes our open financial derivative
positions as of December 31, 2006 related to natural gas
and crude oil production.
Utilization of our financial hedging program may result in
natural gas and crude oil realized prices varying from market
prices that we receive from the sale of natural gas and crude
oil. Our revenue from natural gas and crude oil production was
$15.5 million higher, $41.8 million lower and
$43.9 million lower for 2006, 2005 and 2004, respectively.
We have also entered into financial derivative contracts to
hedge exposure to commodity price risk associated with future
contractual natural gas sales at fixed prices to third parties.
As a result of our firm sale commitments, the associated
financial derivative contracts qualified as fair value hedges
for accounting purposes. Marketing revenues were
$0.2 million lower and $0.1 million and
$0.5 million higher as a result of our hedging activities
in 2006, 2005 and 2004, respectively.
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The following table summarizes our open financial swap positions
and hedged firm commitments as of December 31, 2006 related
to natural gas marketing.
Hedge ineffectiveness resulted in $0.1 million of net
losses, $0.1 million of net gains and $0.1 million of
net losses recorded to other revenue for 2006, 2005 and 2004,
Our remaining anticipated production for 2007 and beyond is
subject to commodity price fluctuations. Under long-term sales
contracts, natural gas volumes of 16.5 MMcfd are committed
at market price through September 2008. During 2006,
approximately 8.9 MMcfd of our natural gas production was
sold under these contracts. The remaining contractual volumes
were third-party volumes controlled by us.
Based on our 2006 average production and long-term natural gas
sales contracts with floor prices of $2.47 per Mcf and
$2.49 per Mcf, each $1.00 per Mcf increase/decrease in
the price of natural gas would increase/decrease our revenue by
approximately $42.0 million.
At December 31, 2006, we had no interest rate derivatives
in effect. On September 10, 2003, we entered into an
interest rate swap to hedge the $40.0 million of fixed-rate
second lien notes issued on June 27, 2003. The swap
converted the debts 7.5% fixed-rate debt to a floating
six-month LIBOR base. In January 2004, the swap position was
cancelled, and we received a cash settlement of
$0.3 million that was recognized over the original term for
the swap until the associated debt was retired in March 2006. At
that time, the remaining deferred gain was recognized.
Interest expense for the years ended December 31, 2006,
2005 and 2004 was $0.1 million lower, $0.3 million
lower and $0.8 million higher, respectively, as a result of
the interest rate swaps.
If interest rates on our variable interest-rate debt of
$421.1 million, as of December 31, 2006, increase or
decrease by one percentage point, our annual pretax income will
decrease or increase by $4.2 million.
Credit risk is the risk of loss as a result of non-performance
by counterparties of their contractual obligations. We sell a
portion of our natural gas production directly under long-term
contracts with the remainder of our natural gas and crude oil
production sold at spot or short-term contract prices. All our
natural gas and crude oil production is sold to large trading
companies and energy marketing companies, refineries and other
users of petroleum products. We also enter into hedge
derivatives with financial counterparties. We monitor exposure
to counterparties by reviewing credit ratings, financial
statements and credit service reports. Exposure levels are
limited and parental guarantees and collateral to support the
obligations of our counterparty are required according to our
established policy. Each customer
counterparty is reviewed as to credit worthiness prior to the
extension of credit and on a regular basis thereafter. In this
manner, we reduce credit risk.
While we follow our credit policies at the time we enter into
sales contracts, the credit-worthiness of counterparties could
change over time. The credit ratings of the parent companies of
the two counterparties to our long-term gas contracts were
downgraded in early 2003 and remain below the credit ratings
required for the extension of credit to new customers. Please
see Item 1A. Risk Factors.
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Performance risk results when a financial counterparty fails to
fulfill its contractual obligations such as commodity pricing or
volume commitments. Typically, such risk obligations are defined
within the trading agreements. We manage performance risk
through management of credit risk. Each customer
counterparty is reviewed as to credit-worthiness prior to the
extension of credit and on a regular basis thereafter.
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. In 2005, foreign
currency transaction losses of $0.1 million were recorded
as a result of losses in the Canadian-$ value of
U.S.-$ bank
balances in 2005. During October and November 2004, Quicksilver
loaned QRCI approximately $11.4 million. To reduce its
exposure to exchange rate risk, QRCI entered into a forward
contract that fixed the
exchange rate. The balance of the loan was repaid at the end of
November 2004 and upon settlement of the forward contract, a
gain of $0.2 million was recognized.
While cross-currency transactions are minimized, the result of a
ten percent change in the Canadian-U.S. exchange rate would
increase or decrease stockholders equity by approximately
$15.8 million at December 31, 2006.
Management discusses with our Audit Committee the development,
selection and disclosure of our critical accounting policies and
estimates and the application of these policies and estimates.
Our consolidated financial statements are prepared in accordance
with accounting principles generally accepted in the United
States. We believe our accounting policies are appropriately
selected and applied.
In preparing the financial statements, our management makes
informed judgments and estimates that affect the reported
amounts of assets and liabilities as of the date of the
financial statements and affect the reported amounts of revenues
and expenses during the reporting period. On an ongoing basis,
management reviews its estimates, including asset retirement
obligations, litigation, income taxes and determination of
proved reserves. Changes in facts and circumstances may result
in revised estimates and actual results may differ from these
We use the full cost method of accounting 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
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. Effective with the adoption of
SFAS No. 143 in 2003, the carrying amount of oil and
gas properties also includes estimated asset retirement costs
recorded based on the fair value of the asset retirement
obligation when incurred. Gain or loss on the sale or other
disposition of oil and gas properties is not recognized, unless
the gain or loss would significantly alter the relationship
between capitalized costs and proved reserves of oil and natural
gas attributable to a country. The application of the full cost
method of accounting for oil and gas properties generally
results in higher capitalized costs and higher depletion rates
compared to the successful efforts method of accounting for oil
and gas properties. The sum of net capitalized costs and
estimated future development and dismantlement costs for each
cost center is depleted on the equivalent
basis using proved oil and gas reserves as determined by
independent petroleum engineers.
We are required to perform the ceiling test each quarter because
we use the full cost method of accounting for oil and gas
properties. Pursuant to SEC
Regulation S-X
Rule 4-10,
the ceiling test is an impairment test performed
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on a
basis. The test determines a full cost limitation, or ceiling,
on the book value of oil and gas properties, which is generally
the after-tax value of the future net cash flows from proved
natural gas and crude oil reserves, including the effect of cash
flow hedges, discounted at ten percent per annum. Applying the
test, we compare the full cost ceiling limitation to the net
book value of our oil and gas properties reduced by the related
net deferred income tax liability and asset retirement
obligations. If the net book value reduced by the related net
deferred income tax liability and asset retirement obligations
exceeds the full cost ceiling limitation, an impairment or
noncash write down is required. A charge to income for
impairment can give us a significant loss for a particular
period; however, future depletion expense would be reduced.
The ceiling test is affected by a decrease in net cash flow from
reserves due to higher operating or capital costs or reduction
in market prices for natural gas and crude oil. These changes
can reduce the amount of economically producible reserves. At
December 31, 2006, our net capitalized exploration and
production fixed asset costs, inclusive of future development
costs, for U.S. and Canadian reserves were $1.07 per Mcfe
and $1.53 per Mcfe, respectively.
Proved oil and gas reserves, as defined by SEC
Regulation S-X
Rule 4-10(a)
2(i), 2(ii), 2(iii), (3) and (4), are the estimated
quantities of crude oil, natural gas, and NGLs that geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions (i.e., prices and costs as of
the date the estimate is made). Prices include consideration of
changes in existing prices provided only by contractual
arrangements, which do not include financial derivatives that
hedge our oil and gas revenue.
Our estimates of proved reserves are made using available
geological and reservoir data as well as production performance
data. These estimates, made by our engineers, are reviewed
annually and revised, either upward or downward, as warranted by
additional data. Revisions are necessary due to changes in,
among other things, reservoir performance, prices, economic
conditions and governmental restrictions. Decreases in prices,
for example, may cause a reduction in some proved reserves due
to reaching economic limits sooner. A material change in the
estimated volumes of reserves could have an impact on the
depletion rate calculation and the financial statements.
We enter into financial derivative instruments to hedge risk
associated with the prices received from natural gas, crude oil
and condensate and NGL production. We also utilize financial
derivative instruments to hedge the risk associated with
interest rates on our debt outstanding. We account for our
derivative instruments under the provisions of Statement of
Financial Accounts Standard (SFAS) No. 133,
Accounting for Derivative Instruments and Hedging Activities.
Under this statement, derivative instruments, other than
those meeting the normal purchases and sales exception, are
recorded on our balance sheet as either assets or liabilities
measured at fair value determined by reference to published
future market prices and interest rates. The cash settlement of
all derivative instruments is recognized as income or 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 income
or expense in the period in which the hedged transaction is
recognized. The ineffective portion of hedges is recognized
currently in earnings.
The fair value of our natural gas and crude oil derivatives and
associated firm sales commitments as of December 31, 2006
was estimated based on published market prices of natural gas
and crude oil for the periods covered by the contracts. The net
differential between the prices in each derivative and
commitment and market prices for future periods, as adjusted for
estimated basis, has been applied to the volumes stipulated in
each contract to arrive at an estimated future value. This
estimated future value was discounted on each contract at rates
commensurate with federal treasury instruments with similar
contractual lives. As a result, the fair value of our
derivatives and commitments does not necessarily represent the
value a third party would pay or require payment of to assume
our contract positions.
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At December 31, 2006, portions of our hedge derivatives
were classified as current based upon the maturity of the
derivative instruments. Based upon the estimated fair values of
those hedge derivatives as of December 31, 2006, our
revenues for 2007 will increase approximately
$64.1 million. Net income, after income taxes, will be
approximately $42.7 million. These amounts will be
reclassified from accumulated other comprehensive income in 2007.
We have significant obligations to remove equipment and restore
land at the end of oil and gas production operations. Our
removal and restoration obligations are primarily associated
with plugging and abandoning wells and associated production
facilities. We adopted SFAS No. 143, Accounting for
Asset Retirement Obligations, effective January 1,
2003. Under SFAS No. 143, the estimated fair value of
a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets is recorded in the
periods in which it is incurred. When the liability is recorded,
we increase the carrying amount of the related long-lived asset.
The liability is accreted to the fair value at the time of the
settlement over the useful life of the asset, and the
capitalized cost is depleted or depreciated over the useful life
of the related asset.
The fair value of the liability associated with these retirement
obligations is determined using significant assumptions,
including current estimates of the plugging and abandonment or
retirement, annual inflation of these costs, the productive life
of the asset and our risk adjusted costs to settle such
obligations discounted using our risk- adjusted interest rate.
Changes in any of these assumptions can result in significant
revisions to the estimated asset retirement obligation.
Revisions to the asset obligation are recorded with an
offsetting change to the carrying amount of the related
long-lived asset, resulting in prospective changes to
depreciation, depletion and amortization expense and accretion
of discount. Because of the subjectivity of assumptions and the
relatively long life of most of our oil and gas assets, the
costs to ultimately retire these assets may vary significantly
from previous estimates.
We adopted SFAS 123(R) on January 1, 2006. We
previously accounted for stock awards under the recognition and
measurement principles of APB No. 25, Accounting for
Stock Issued to Employees, and related Interpretations.
Prior to January 1, 2006, stock-based employee compensation
expense for restricted stock and stock unit grants was reflected
in net income, but no compensation expense was recognized for
options granted with an exercise price equal to the market value
of the underlying common stock on the date of grant. This
statement requires the cost resulting from all share-based
payment transactions be recognized in the financial statements
at their fair value on the grant date.
We adopted SFAS 123(R) using the modified prospective
application method described in the statement. Under the
modified prospective application method, we have applied the
standard to new awards. Additionally, compensation cost for the
unvested portion of stock awards outstanding as of
January 1, 2006 has been recognized as compensation expense
as the requisite service is rendered after January 1, 2006.
The compensation cost for unvested stock awards granted before
adoption of SFAS 123(R) shall be attributed to periods
beginning January 1, 2006 using the attribution method that
was used under SFAS 123. At January 1, 2006, we had
total compensation cost of $1.1 million related to unvested
stock options with a weighted average remaining vesting period
of 1.5 years. We recorded expense of $0.7 million for
stock option grants during 2006.
Prior to the adoption of SFAS 123(R), we presented any tax
benefits of deductions resulting from the exercise of stock
options within operating cash flows in the condensed
consolidated statements of cash flow. SFAS 123(R) requires
tax benefits resulting from tax deductions in excess of the
compensation cost recognized for those options (excess tax
benefits) to be classified and reported as both an
operating cash outflow and a financing cash inflow upon adoption
of SFAS 123(R). As a result of our net operating losses,
the excess tax benefits that would otherwise be available to
reduce income taxes payable have the effect of increasing our
net operating loss carry forwards. Accordingly, because we are
unable to realize these excess tax benefits, such benefits have
not been recognized in the condensed consolidated statement of
cash flows for the year ended December 31, 2006.
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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 will be in effect in years in which
the temporary differences are expected to reverse. QRCI computes
taxes at rates in effect in Canada. U.S. deferred tax
liabilities are not recognized on profits that are expected to
be permanently reinvested by QRCI and thus are not considered
available for distribution to us.
Included in our net deferred tax liability are
$117.8 million of future tax benefits from prior unused tax
losses. Realization of these tax assets depends on sufficient
future taxable income before the benefits expire. We believe we
will have sufficient future taxable income to utilize the loss
carry forward benefits before they expire; however, if not, we
could be required to recognize a loss for some or all of these
tax assets. Net operating loss carry forwards and other deferred
tax assets are reviewed annually for recoverability and are
recorded net of a valuation allowance, if necessary.
We have no off-balance sheet arrangements within the meaning of
Item 303(a)(4) of SEC
Regulation S-K.
Financial Data
Years Ended December 31, 2006, 2005 and 2004
Net income for the years ending December 31, 2006, 2005 and
2004 was $93.7 million ($1.15 per diluted share),
$87.4 million ($1.08 per diluted share), and
$31.3 million ($0.41 per diluted share), respectively.
Net income for 2005 included a gain of $0.2 million from
discontinued operation relating to the sale of drilling rigs
purchased and sold during the year.
Our 2006 revenues were $390.4 million as compared to
$310.4 million for 2005, primarily as a result of
additional revenue originating from our expanded operations in
the Fort Worth Basin of northern Texas and Alberta, Canada.
The additional revenue from our Texas and Canadian operations
was the result of a net increase in sales volumes of
8.8 Bcfe and 3.7 Bcfe, respectively, and an increase
in our realized prices, on a consolidated basis, of
$0.36 per Mcfe.
Total revenues for 2005 were $310.4 million, a
$130.7 million increase from the $179.7 million
reported in 2004. Higher realized prices and additional sales
volumes increased revenue $129.0 million. The increase was
primarily the result of sales volumes added from new wells
placed into production in our Canadian CBM and Texas Barnett
Shale development projects and a 49% increase in realized sales
Gas, Oil
and NGL Sales
Our sales volumes, revenues and average prices for the years
ended December 31, 2006, 2005 and 2004 are as follows:
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Our natural gas sales for 2006 were $322.4 million and
increased 20%, or $52.8 million, from 2005 natural gas
sales of $269.5 million. Realized prices in 2006 (including
hedge settlements and our sales contracts with $2.48 per
Mcf floors) increased 5% and were responsible for
$13.5 million of the increase in natural gas revenue from
the prior year. The remaining increase in 2006 natural gas
revenue as compared to 2005 was due to a 14% increase in sales
volumes. Natural gas sales in the U.S. increased
6.8 Bcf as a result of new Fort Worth Basin wells
placed into production throughout 2006 and 0.7 Bcf from new
Antrim wells in Michigan placed into production during 2006.
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Drilling on our Canadian interests increased production
5.1 Bcf from the 2005 period. These increases were
partially offset by natural production rate declines for
existing wells.
Crude oil and condensate revenue for 2006 was $35.2 million
and $7.3 million higher than crude oil and condensate sales
of $27.9 million for 2005. A realized $9.49 per Bbl
increase in prices contributed almost $5.3 million of the
$7.3 million increase. Production in 2006 from our
Fort Worth Basin interests increased 61.2 MBbl as a
result of additional wells placed into production during the
year. The increase was partially offset by natural production
rate declines for existing wells.
Sales of NGLs for 2006 were $29.0 million. As compared to
2005, 2006 sales were $20.3 million higher than 2005 NGL
sales of $8.7 million. The increase was the result of an
incremental 509.7 MBbl of NGL production resultant from
Texas natural gas production and processing during 2006.
Natural gas sales for 2005 were $269.5 million and
increased $118.8 million from 2004 natural gas revenue of
$150.7 million. Higher natural gas prices in 2005 increased
revenue $76.1 million. Realized natural gas prices
(including contracts with price floors of $2.48 and settlements
for natural gas price hedges) rose 54% and 32%, respectively,
for U.S. and Canadian natural gas. Our natural gas production in
2005 increased nearly 7.4 Bcf from 2004 to almost
46.8 Bcf. Continued drilling on our Horseshoe Canyon and
other Canadian interests increased production 8.8 Bcf,
partially offset by natural declines in production rates for
existing Canadian wells. U.S. sales volumes for 2005 were
approximately 5% higher than 2004. Our drilling program in the
Barnett Shale of the Fort Worth Basin resulted in a
production increase of over 3.0 Bcf from Barnett Shale
wells drilled and placed into production in the latter half of
2004 and all of 2005. Wells placed into production in the Antrim
and New Albany Shales increased production approximately
0.6 Bcf and 0.8 Bcf for 2005. Wells placed into
production on our Michigan non-Antrim interests, as well as
other work performed on existing wells, increased production
approximately 0.3 Bcf for 2005. Natural production rate
declines partially offset these increases.
Revenue from crude oil and condensate in 2005 increased
$5.1 million despite a decrease of 150 MBbl resulting
primarily from the sale of Wyoming crude oil properties in the
third quarter of 2004 to Meritage Partners LLC. Price increases
of approximately 53% from 2004 realized prices resulted in an
average 2005 realized price of $50.50 and increased revenue
approximately $12.0 million.
NGL revenue for 2005 was $8.7 million as compared to
$3.7 million for 2004. NGL volumes for 2005 increased
approximately 94 MBbl primarily as a result of natural gas
processing in the Barnett Shale that began in the second quarter
of 2005. These additional volumes increased revenue
approximately $3.7 million from 2004 while a 37% increase
in realized prices provided $1.3 million of additional
revenue in 2005.
Other revenue, consisting primarily of revenue from the
processing, gathering and marketing of natural gas, was
$4.2 million for 2005. The $1.6 million increase from
2004 was primarily the result of revenue earned from the sale of
NGLs earned from gas processed through our interim processing
facility in the Barnett Shale. This revenue was not earned for
2006 as the final gas processing agreements entered into in
October 2005 do not provide for the facility to earn a portion
of the NGLs produced from the plant.
Operating expenses for 2006 were $216.7 million, or
$54.5 million higher than operating expenses for 2005.
Production expenses in 2006 were $24.0 million higher than
2005 production expense due primarily to higher sales volumes
from new wells placed into production in Texas and Canada.
Depletion and depreciation expense for 2006 increased
$23.6 million as a result of higher sales volumes and
depletion rates as well as additional depreciation associated
with new gas processing and gathering assets in Texas and
Canada. General and administrative expense for 2006 also
increased $6.0 million compared to 2005.
Operating expenses for 2005 were $162.2 million, a
$41.9 million increase from 2004 operating expense. Nearly
half of the increase was due to higher sales volumes and new
wells placed into production in Canada and Texas as well as an
increase in maintenance and repairs for our Michigan properties.
Depletion expense for 2005 increased as a result of higher sales
volumes and depletion rates. Depreciation also increased as a
result of gathering
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and processing facilities added in Canada and Texas during 2005.
There was also a $6.0 million increase in general and
administrative costs for 2005 when compared to 2004.
Expense for oil and gas production for 2006 was
$95.2 million and $24.0 million higher than 2005
production expense of $71.2 million. Canadian production
expense was $21.9 million in 2006. The $6.6 million
increase from 2005 Canadian production expense was primarily the
result of a $3.7 million increase in compensation and
benefits expense and an increase of $1.7 million for gas
processing expense. The increase in compensation costs was made
up of additional stock compensation expense of $0.8 million
due to 2006 grants of restricted stock, an increase of
$0.5 million for matching contributions to employees
retirement savings accounts and a 20% increase in the number of
Canadian employees as compared to 2006. Operation of gas
processing facilities built in 2005 and 2006 increased expense
$1.7 million in 2006 compared to 2005.
Production expense for the U.S. increased
$17.4 million in 2006 to $73.3 million as compared to
2005. Production expense for Texas increased $16.3 million
for 2006 compared to 2005.
Start-up of
our Cowtown Plant and expansion of our Cowtown Pipeline System
increased expense $8.4 million due in part to a net
8.8 Bcfe increase in production volumes. Remaining Texas
production expense increased $7.9 million for 2006 when
compared to 2005 as a result of larger operations including an
increase in production and drilling operations that have
required additional employees in our Texas field office.
Production overhead expense for Texas in 2006 increased
approximately $1.8 million, net of overhead recoveries, as
a result of compensation for additional employees and an
increase in office-related expenses, including rent. Lease
operating expense increases of $4.9 million, net of
approximately $1.0 million for
clean-up of
a saltwater spill that occurred in the second quarter, made up
the remaining increase for 2006 Texas production expense when
compared to 2005. Additional producing wells and increases in
rates charged by third-parties were the primary causes of the
$4.9 million increase in 2006 lease operating expense. The
remaining expense increases included higher stock compensation
expense for field employees of $0.6 million in 2006 as
compared to 2005 and additional workover expense of
approximately $0.4 million in our Michigan operating area.
Oil and gas production expense for 2005 was $71.2 million
and $18.6 million higher than 2004 production expense.
U.S. production expense increased $12.3 million,
excluding expense for stock-based compensation expense, when
compared to 2004 production expense. U.S. production
expense for 2005 is also net of a $2.4 million reduction in
Wyoming production expense as a result of the sale of most of
our Wyoming properties in the third quarter of 2004. Operating
expense for our Barnett Shale projects in the Fort Worth
Basin increased nearly $7.9 million from 2004 to 2005. We
had 36.6 net operated wells in operation at the end of 2005
compared to 3 net operated wells at the end of 2004. The
growth of our operations increased lease operating expenses
$4.7 million, which included $2.9 million for contract
labor, equipment rentals and salt water disposal. Initial
operating expenses for these items are typically greater when
production begins as initial production includes high water
production from the fracture stimulations. Operating costs for
each well tends to decrease following the period of initial
production; however, these expenses remained high for 2006 due
to our drilling program in the Fort Worth Basin. Expense
for the gathering and processing of our Barnett Shale natural
gas production increased $3.2 million.
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Production expense for our Michigan projects increased
$5.4 million from 2004 production expense. Approximately
$3.2 million of the increase for 2005 resulted from efforts
to perform preventive equipment maintenance and repairs.
Michigan environmental compliance and remediation expense
increased almost $1.4 million for 2005. Salary and wages
expense increased almost $0.6 million for personnel in
Michigan, Indiana and Kentucky as a result of annual raises, the
hiring of additional personnel and a small increase in 2005
bonuses compared to 2004.
Canadian production expense for 2005 increased $6.3 million
from 2004 production expense, exclusive of stock-based
compensation expense. We drilled 483 (259.1 net) wells
during 2005 and net natural gas production increased
6.1 Bcf. Canadian production expense on a Mcfe-basis
The decrease reflected additional improvement in the economies
of scale for our Canadian operations.
Production and ad valorem tax expense for 2006 was relatively
flat when compared to 2005 as a $1.9 million increase in ad
valorem tax expense was mostly offset by a decrease in
production taxes. Ad valorem tax expense increased primarily as
a result of the growth in our Texas property values while
production tax expense decreased as a result of lower prices in
2006 compared to 2005.
Production and ad valorem tax expense increased
$2.5 million from 2004 to 2005 due primarily to higher
prices for natural gas, crude oil and condensate as well as an
increase in U.S. sales volumes. Canadian expense for
production and ad valorem taxes was virtually unchanged from
2004 to 2005.
Our 2006 depletion expense increased $19.1 million from
2005 depletion expense. Our 2006 consolidated depletion rate
increased $0.16 per Mcfe, and our production increased
9.8 Bcfe. The increase in our consolidated depletion rate
was a result of increased future development costs due in part
to a higher percentage of undeveloped proved reserves for
2006 year-end as compared to 2005. Depreciation expense for
2006 was $11.8 million and $4.2 million higher than
2005 depreciation expense of $7.6 million. The increase in
depreciation is primarily the result of our new Cowtown Gas
Plant, additions to our Cowtown Pipeline and new Canadian gas
processing facilities.
Higher production volumes and an increase in our depletion rate
for 2005 increased depletion expense $12.1 million from
2004 depletion expense. The $0.13 per Mcfe increase in our
consolidated depletion rate was the result of a higher
percentage increase for estimated future development costs as
compared to proved reserve increases for 2005 as compared to
2004. Depreciation expense for 2005 increased $2.4 million
when compared to 2004 expense. The increase is primarily the
result of additional gas processing facilities in Canada and the
U.S. as well as a full years operation of the Cowtown
Pipeline in the Barnett Shale.
General and administrative expense for 2006 was
$24.9 million and an increase of $5.9 million from
2005 general and administrative expense of $19.0 million.
Expense for compensation and benefits grew $5.3 million
when compared to 2005. The increase included $3.4 million
for stock compensation expense associated with 2006 grants of
restricted stock, $1.5 million resulting from additional
employees and annual raises and an increase of $0.4 million
for additional matching of employees retirement plan
contributions. The remaining increase was
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primarily the result of a $0.9 million increase in 2006
office-related expenses, primarily rent for additional office
space, partially offset by decreases in several expense
For 2005, general and administrative expense was
$19.0 million. The total was $6.0 million higher than
2004 general and administrative expense. During 2005, employee
compensation expense increased approximately $5.6 million
including nearly $1.0 million of expense for restricted
stock granted to executives and employees during 2005.
Additional management and administrative personnel increased
compensation expense approximately $1.7 million. Bonuses
paid to employees for 2005 were $1.9 million higher than
2004 and included $0.6 million for retention and hiring of
key personnel. Annual raises and other compensation expenses,
including the our contribution to employees retirement
accounts for 2005, increased general and administrative expense
approximately $1.0 million while outside directors
compensation increased over $0.2 million including almost
$0.1 million for vesting of restricted stock granted during
2005. Legal fees were $0.9 million higher due largely to
work performed by outside attorneys on various corporate matters
and litigation. These increases were partially offset by a
$0.4 million decrease in contract labor expense and small
decreases in various other expenses from 2004.
For 2006, interest expense was $44.1 million after interest
capitalization of $1.9 million, an increase of
$22.3 million from 2005 interest expense and primarily the
result of higher debt balances including the issuance of our
$350 million in principal amount senior subordinated notes
in March of 2006. Interest expense for 2006 included a
prepayment penalty of $0.8 as a result of the early retirement
of $70.0 million in principal amount of our second lien
mortgage notes payable with a portion of the proceeds from the
issuance of $350 million in principal amount of our senior
subordinated notes. Recurring interest expense increased
$14.0 million as a result of higher debt levels throughout
2006. Higher interest rates, including the Canadian prime rates
paid on the Canadian debt outstanding under the senior credit
facility, during 2006 contributed approximately
$8.4 million to increased interest expense. These increases
in 2006 interest expense were partially offset by an additional
$0.8 million of interest capitalization relating to gas
processing facilities in Texas and Canada.
Interest expense for 2005 was $21.7 million after interest
capitalization of $1.1 million. The $6.1 million
increase from 2004 was the result of higher debt balances that
resulted from capital expenditures for our 2005 development,
exploitation and exploration programs in Canada and Texas and
was partially offset by a decrease in the average interest paid
on our total debt balance. The decrease in our average interest
rate was primarily the result of the 1.875% interest rate borne
by our $150.0 million contingently convertible debentures
issued in November 2004. Capitalized interest recorded in 2005
was associated with the construction of gathering and processing
facilities in the Fort Worth Basin of Texas and in Canada.
Our income tax provision for 2006 was $38.1 million. Our
U.S. deferred federal income tax provision of
$27.5 million was established using the statutory
U.S. federal rate of 35%. Expense for the 2006 period
included the reversal of a deferred federal income tax liability
of $0.9 million as a result of the completion of IRS audits
of a wholly-owned subsidiary for years prior to its acquisition
by us. We also recognized a deferred state income tax provision
of $1.6 million as a result of the Texas Margin Tax that
was enacted in May 2006. The Canadian tax provision was
approximately $9.0 million for 2006 which included a
reduction of $3.8 million for the effect of federal and
provincial tax rate reductions that were enacted in the second
quarter of 2006.
For 2005, our income tax provision was $40.7 million. Our
U.S. income tax provision of $26.3 million was
established using the statutory U.S. federal rate of 35%.
The Canadian tax provision of approximately $14.3 million
was accrued at a Canadian combined federal and provincial
statutory rate of 33.6% and included a current tax provision of
$0.5 million.
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Our statements of cash flows are summarized as follows:
Cash flows provided by operating activities in 2006 were
$220.6 million and a $76.1 million increase from
operating cash flow for 2005. The 53% increase in operating cash
flow was primarily the result of a 19% increase in production, a
6% increase in realized product prices and more aggressive cash
Operating activities in 2005 generated $144.5 million of
cash flows, or a 70% increase from 2004 operating cash flows.
The primary factor in our increased operating cash flow was a
$56.2 million increase in 2005 net income that
reflected a 49% increase in our realized product prices and a
16% increase in 2005 production volumes.
Purchases of property, plant and equipment accounted for the
most significant cash outlays for investing activities in each
of the three years ended December 31, 2006, 2005 and 2004.
We currently estimate that our spending for property, plant and
equipment in 2007 will be approximately $610 million, of
which we have allocated $502 million for drilling
activities, $88 million for gathering and processing
facilities, $18 million for acquisition of additional
leasehold interests and $2 million for other property and
equipment. Total property, plant and equipment
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costs incurred (purchases of property, plant and equipment plus
net working capital changes related to acquisition of property,
plant and equipment) by geographic segment for 2006, 2005 and
2004 are as follows:
and Equipment Costs Incurred
Capital costs incurred for 2006 development, exploitation and
exploration activities in 2006 were $544.7 million. Those
expenditures reflect our focus in two operating areas, the Fort
Worth Basin in northern Texas and our Canadian projects in the
Western Sedimentary Basin in Alberta, Canada. In 2006, we
drilled 123 (111.3 net) wells in northern Texas and an
additional 400 (215.2 net) wells in Canada. Additionally,
we invested $82.3 million and $7.6 million for
Fort Worth Basin and Canadian gas processing and gathering
Capital expenditures for our 2005 development, exploitation and
exploration activities were focused in two areas. Canadian
development and exploration costs were $97.6 million. Our
2005 expenditures in Canada were focused on the development and
exploitation of our ongoing CBM projects as well as exploration
of additional CBM acreage. Canadian expenditures for gas
processing facilities were $20.4 million. Our
U.S. capital expenditures were primarily spent on
development, exploitation and development of the Barnett Shale
in the Fort Worth Basin. Total expenditures for our Texas
projects were $153.6 million, including approximately
$51.7 million for acreage in the Fort Worth and
Delaware Basins. Expenditures for completion of the first phase
of our Cowtown Pipeline and construction of our Cowtown Plant in
the Fort Worth Basin were over $49.2 million.
Our 2004 capital expenditures for development, exploitation and
exploration activities were focused in four areas. Expenditures
for Canadian development, exploitation and exploration projects
were approximately $104.6 million. Those expenditures
continued exploration and development of our initial CBM
projects as well as exploration of several additional CBM
projects. Included in the $104.6 million of Canadian
expenditures was $7.1 million for acquisition of additional
acreage in several areas of Alberta. Expenditures for Texas
development, exploitation and exploration activities were
approximately $55.1 million, including approximately
$29.3 million
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for additional acreage in north Texas. An additional
$6.0 million was expended for the first phase of the
Cowtown Pipeline. We spent approximately $31.5 million for
continued development of our Michigan properties and an
additional $2.1 million was spent on gathering and
processing infrastructure. New wells and associated
infrastructure in southern Indiana and northern Kentucky
accounted for approximately $20.6 million of our
expenditures for exploration and development activities. An
additional $1.1 million was expended for the construction
of plant and pipeline infrastructure in the Indiana/Kentucky
Net cash provided by financing activities in 2006 was
$361.3 million. On March 16, 2006, we issued
$350 million in principal amount of Senior Subordinated
Notes due in 2016. The Senior Subordinated Notes are unsecured,
senior subordinated obligations and bear interest at an annual
rate of 7.125% payable semiannually on April 1 and
October 1 of each year. The terms and conditions of the
Senior Subordinated Notes require us to comply with certain
covenants, which primarily limit certain activities, including,
among other things, levels of indebtedness, restricted payments,
payments of dividends, capital stock repurchases, investments,
liens, restrictions on restricted subsidiaries to make
distributions, affiliate transactions, transfers or sales of
assets and mergers and consolidations. Based upon our
2006 year-end reserves, the indenture agreement limits us
to $750 million of borrowing under our senior secured
credit facility. At December 31, 2006, we were in
compliance with such restrictions.
We used $70 million of the proceeds of the Senior
Subordinated Notes to retire our second lien mortgage notes in
March 2006. As a result of the early retirement, we were
required to pay a premium of $0.8 million for early
repayment of the notes. We also used approximately
$192.5 million of the proceeds to repay the borrowings then
outstanding under the U.S. portion of our senior secured
credit facility. For 2006, we have increased our borrowings
under our U.S. and Canadian senior secured credit facilities
approximately $133.1 million.
As of December 31, 2006, our borrowing base under our
senior secured credit facility was $600 million, of which
approximately $178 million was available for borrowing. The
loan agreements for the senior credit facility prohibit the
declaration or payment of dividends by us and contain certain
financial covenants, which, among other things, require the
maintenance of a minimum current ratio and a minimum earnings
(before interest, taxes, depreciation, depletion, amortization,
non-cash income and expense and exploration costs) to interest
ratio. We were in compliance with all such covenants at
December 31, 2006.
On February 9, 2007, we extended the senior secured credit
facility to February 9, 2012 and to provide for revolving
loans, swingline loans and letters of credit from time to time
in an aggregate amount not to exceed the lesser of the borrowing
base which is calculated based on several factors and is
initially equal to $850 million. The borrowing base is
subject to annual redeterminations and certain other
redeterminations. The lenders have agreed to initial revolving
credit commitments in an aggregate amount equal to
$1.2 billion, and we have an option to increase the
facility to $1.45 billion with the consent of the lenders.
The lenders commitments under the facility are allocated
between U.S. and Canadian funds, with the U.S. funds
available for borrowing by the Company and Canadian funds being
available for borrowing by the Companys Canadian
subsidiary, QRCI in U.S. or Canadian funds. The facility
offers the option to extend the maturity up to two additional
years with requisite lender consent. U.S. borrowings under
the facility are guaranteed by most of our domestic subsidiaries
and are secured by, among
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other things, certain of our domestic subsidiaries oil and
gas properties. Canadian borrowings under the facility are
secured by, among other things, QRCIs, our and certain of
our domestic subsidiaries oil and gas properties. The loan
agreements for the credit facility prohibit the declaration or
payment of dividends by us and contain certain financial
covenants, which, among other things, require the maintenance of
a minimum current ratio and a minimum earnings (before interest,
taxes, depreciation, depletion and amortization, non-cash income
and expense, and exploration costs) to interest expense ratio.
As of December 31, 2006, 2005 and 2004, our total
capitalization was as follows:
We believe that our capital resources are adequate to meet the
requirements of our existing business. We anticipate that our
2007 capital expenditure budget of approximately
$610 million will be funded by cash flow from operations,
credit facility utilization and proceeds we expect to receive in
connection with the anticipated sale to the public of
approximately 19% of the limited partner interests of
Quicksilver Gas Services LP (QGSLP), our subsidiary
that will hold Cowtown Plant and the Cowtown Pipeline. Although
QGSLP has filed a registration on
Form S-1
relating to this offering, numerous factors, such as general
market conditions and market conditions in the oil and gas
industry in particular, could result in the offering not being
completed. We may also consider the possible sale of assets and
the possible issuance of debt or equity securities to fund our
2007 capital expenditure budget.
Depending upon conditions in the capital markets and other
factors, we will from time to time consider the issuance of debt
or other securities, or other possible capital markets
transactions, 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 assets and businesses. 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 two or more of those sources.
The following impacted our balance sheet as of December 31,
2006, as compared to our balance sheet as of December 31,
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Information regarding our contractual obligations (within the
scope of Item 303(a)(5) of Regulations S-K), as well as
scheduled interest obligations, at December 31, 2006 is set
forth in the following table.
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We have the following commercial commitments as of
December 31, 2006.
Certain statements contained in this 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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All forward-looking statements are expressly qualified in their
entirety by the foregoing cautionary statements.
The Financial Accounting Standards Board (FASB)
issued SFAS No. 155, Accounting for Certain Hybrid
Financial Instruments an amendment of FASB
Statements No. 133 and 140, in February 2006.
SFAS No. 155 addresses accounting for beneficial
interests in securitized financial instruments. The guidance
allows fair value remeasurement for any hybrid financial
instrument containing an embedded derivative that would
otherwise require bifurcation and clarifies which interest-only
and principal-only strips are not subject to
SFAS No. 133. SFAS No. 155 also established
a requirement to evaluate interests in securitized financial
assets to identify any interests that are either freestanding
derivatives or contain an embedded derivative requiring
bifurcation. The statement is effective for all financial
instruments issued or acquired after the beginning of the first
fiscal year that begins after September 15, 2006.
Management does not believe application of this statement will
have a material impact on our financial position, results of
operations or cash flows.
SFAS No. 157, Fair Value Measurements, was
issued by the FASB in September 2006. SFAS No. 157
defines fair value, establishes a framework for measuring fair
value in generally accepted accounting principles
(GAAP) and expands disclosures about fair value
measurements. The statement applies under other accounting
pronouncements that require or permit fair value measurement. No
new requirements are included in SFAS No. 157, but
application of the statement will change current practice.
SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007.
Management does not expect adoption of SFAS No. 157
will have a material impact on our financial position, results
of operations or cash flows.
The FASB issued FASB Interpretation No. 48
(FIN 48), Accounting for Uncertainty in
Income Taxes, an interpretation of FASB Statement
No. 109, in June 2006. FIN 48 clarifies the
accounting for uncertainty in income taxes recognized in an
enterprises financial statements in accordance with FASB
Statement No. 109, Accounting for Income Taxes.
FIN 48 defines a criterion that an individual tax position
must meet for any part of the benefit of that position to be
recognized in an enterprises financial statements.
FIN 48 also provides guidance on measurement,
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition. We
estimate that in the first quarter of 2007, we will recognize an
adjustment to retained earnings of approximately
$0.4 million to provide for additional deferred income tax
On February 15, 2007, the FASB issued
SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities Including an
amendment of FASB Statement No. 115.
SFAS No. 159 permits entities to choose to measure
many financial instruments and certain other items at fair
value. The FASB believes the statement will improve financial
reporting by providing companies the opportunity to mitigate
volatility in reported earnings by measuring related assets and
liabilities differently without having to apply complex hedge
accounting provisions. Use of the statement will expand the use
of fair value measurements for accounting for financial
instruments. We do not believe SFAS No. 159 did not
have a material impact on our financial position or results of
In September 2006, the SEC issued Staff Accounting
Bulletin No. 108 (SAB 108). Due to
diversity in practice among registrants, SAB 108 expresses
the SEC staffs views regarding the process by which
misstatements in financial statements are evaluated to determine
whether financial statement restatement is necessary.
SAB 108 is effective for fiscal years ending after
November 15, 2006. SAB 108 did not have a material
impact on our financial position or results from operations.
The information called for by this Item is incorporated herein
by reference to the information in Item 7 of this report
under the heading Financial Risk Management.
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To the Stockholders of
Quicksilver Resources Inc.:
Management of Quicksilver Resources Inc. is responsible for the
preparation, integrity and fair presentation of its published
consolidated financial statements. The financial statements have
been prepared in accordance with U.S. generally accepted
accounting principles and, as such, include amounts based on
judgments and estimates made by management. The Company also
prepared the other information included in the annual report and
is responsible for its accuracy and consistency with the
consolidated financial statements.
Management is also responsible for establishing and maintaining
effective internal control over financial reporting. The
Companys internal control over financial reporting
includes those policies and procedures that pertain to the
Companys ability to record, process, summarize and report
reliable financial data. The Company maintains a system of
internal control over financial reporting, which is designed to
provide reasonable assurance to the Companys management
and board of directors regarding the preparation of reliable
published financial statements and safeguarding of the
Companys assets. The system includes a documented
organizational structure and division of responsibility,
established policies and procedures, including a code of conduct
to foster a strong ethical climate, which are communicated
throughout the Company, and the careful selection, training and
development of our people.
The Board of Directors, acting through its Audit Committee, is
responsible for the oversight of the Companys accounting
policies, financial reporting and internal control. The Audit
Committee of the Board of Directors is comprised entirely of
outside directors who are independent of management. The Audit
Committee is responsible for the appointment and compensation of
the independent registered public accounting firm. It meets
periodically with management, the independent registered public
accounting firm and the internal auditors to ensure that they
are carrying out their responsibilities. The Audit Committee is
also responsible for performing an oversight role by reviewing
and monitoring the financial, accounting and auditing procedures
of the Company in addition to reviewing the Companys
financial reports. Internal auditors monitor the operation of
the internal control system and report findings and
recommendations to management and the Audit Committee.
Corrective actions are taken to address control deficiencies and
other opportunities for improving the system as they are
identified. The independent registered public accounting firm
and the internal auditors have full and unlimited access to the
Audit Committee, with or without management, to discuss the
adequacy of internal control over financial reporting, and any
other matters which they believe should be brought to the
attention of the Audit Committee.
Management recognizes that there are inherent limitations in the
effectiveness of any system of internal control over financial
reporting, including the possibility of human error and the
circumvention or overriding of internal control. Accordingly,
even effective internal control over financial reporting can
provide only reasonable assurance with respect to financial
statement preparation and may not prevent or detect
misstatements. Further, because of changes in conditions, the
effectiveness of internal control over financial reporting may
vary over time.
Management assessed the Companys internal control system
as of December 31, 2006 in relation to criteria for
effective internal control over financial reporting described in
Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on its assessment, the Company has
determined that, as of December 31, 2006, the
Companys system of internal control over financial
reporting was effective.
The consolidated financial statements have been audited by the
independent registered public accounting firm,
Deloitte & Touche LLP, which was given unrestricted
access to all financial records and related data, including
minutes of all meetings of stockholders, the Board of Directors
and committees of the Board. Reports of the independent
registered public accounting firm, which includes the
independent registered public accounting firms attestation
of managements assessment of internal controls, are also
presented within this document.
Fort Worth, Texas
February 28, 2007
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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, 2006 and 2005 and
the related consolidated statements of income and comprehensive
income, stockholders equity and cash flows for each of the
three years in the period ended December 31, 2006. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the
Quicksilver Resources Inc. and subsidiaries as of
December 31, 2006 and 2005, and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 2006, in conformity with
accounting principles generally accepted in the United States of
As discussed in Note 2 to the consolidated financial
statements, effective January 1, 2006, the Company adopted
Statement of Financial Accounting Standards No. 123
(Revised 2004), Share-Based Payment.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of the Companys internal control over
financial reporting as of December 31, 2006, based on the
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated
February 28, 2007 expressed an unqualified opinion on
managements assessment of the effectiveness of the
Companys internal control over financial reporting and an
unqualified opinion on the effectiveness of the Companys
internal control over financial reporting.
/s/ Deloitte &
Touche LLP
Fort Worth, Texas
February 28, 2007
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CONSOLIDATED BALANCE SHEETS As of December 31, 2006 and 2005 In thousands, except for share data
The accompanying notes are an integral part of these
consolidated financial statements.
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