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10K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________.
Commission file number: 001-14837
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QUICKSILVER RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware 75-2756163
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
777 West Rosedale, Suite 300,
Fort Worth, Texas 76104
(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code: (817) 665-5000
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Securities registered pursuant to Section 12 (b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock, par value New York Stock Exchange
$0.01 per share
Securities registered pursuant to Section 12 (g) of the Act: None
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 [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
Documents incorporated by reference: Proxy statement of Quicksilver
Resources Inc. relating to the annual meeting of stockholders to be held on
June 4, 2002, which is incorporated into Part III of this Form 10-K.
As of March 1, 2002, 19,170,151 shares of common stock of Quicksilver
Resources Inc. were outstanding, and the aggregate market value of the voting
stock held by non-affiliates of Quicksilver Resources Inc. was approximately
$173,080,605 based on the New York Stock Exchange composite trading closing
price of $20.17 on March 1, 2002, and using the definition of beneficial
ownership contained in Rule 16a-1(a) (2) promulgated pursuant to the Securities
Exchange Act of 1934.
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INDEX TO ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2001
Page
----
Part I
Item 1 Business of Quicksilver.............................................................. 3
Item 2. Description of Properties............................................................ 8
Item 3. Legal Proceedings.................................................................... 14
Item 4. Submission of Matters to a Vote of Security Holders.................................. 14
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................ 15
Item 6. Selected Financial Data.............................................................. 15
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 17
Item 7A. Quantitative and Qualitative Disclosures about Market Risk........................... 28
Item 8. Financial Statements and Supplementary Data.......................................... 31
Item 9 Change in and Disagreements with Accountants on Accounting and Financial Disclosure.. 62
Part III
Item 10 Directors and Executive Officers of the Registrant................................... 62
Item 11. Executive Compensation............................................................... 64
Item 12. Security Ownership Of Certain Beneficial Owners And Management....................... 64
Item 13. Certain Relationships and Related Transactions....................................... 64
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................... 64
SIGNATURES........................................................................... 65
In this report, the terms "Quicksilver", "we", "our" and "us" refer to
Quicksilver Resources Inc. and, where appropriate, to our predecessors Mercury
Exploration Company; Quicksilver Energy L.C.; Michigan Gas Partners Limited
Partnership; and MSR Exploration Ltd.
Quantities of natural gas are expressed in this report in terms of thousand
cubic feet ("Mcf"), million cubic feet ("MMcf") or billion cubic feet ("Bcf").
Oil and natural gas liquids are quantified in terms of barrels ("Bbl") or
thousands of barrels ("MBbl"). 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 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 oil and gas
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" oil and gas 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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PART I
ITEM 1. Business of Quicksilver
We are an independent oil and gas company engaged in the acquisition,
development, exploration, production and sale of natural gas, crude oil and
natural gas liquids. We also engage in the gathering, processing and
transmission of natural gas. We pursue our business through the acquisition and
development of oil and gas mineral leases, gas gathering systems and producing
natural gas and crude oil properties. Based upon the specifics of each mineral
lease, as well as geological and engineering interpretations, we develop our
inventory of leases by drilling wells, redrilling wells or recompleting
existing wells located on those leases for the recovery of the oil and gas
reserves located there. We currently have an interest in natural gas and crude
oil mineral leases, a pipeline transmission system, gas gathering and
processing facilities and wells producing hydrocarbons that are located
principally in the states of Michigan, Wyoming, Montana, and Indiana as well as
Canada. We evaluate other opportunities for the development of oil and gas
reserves and related assets as they become available and, under certain
circumstances, may explore opportunities in regions other than those in which
we are currently involved.
We market our own product through our wholly owned subsidiary, Cinnabar
Energy Services & Trading, LLC, which also buys and markets third party gas. We
own a 65% interest in Voyager Compression Services, LLC, which sells and
services compressors, primarily in Michigan. We are a major customer of Voyager.
We are not a user or refiner of the natural gas or crude oil we produce,
except when related to the operation of wells that produce natural gas. Once
extracted from the ground, we either deliver the production to a pipeline
gathering system, in the case of natural gas and natural gas liquids, or store
the crude oil in storage tanks located close to the producing field for
collection by oil purchasers.
We own or hold interests in over 5,100 producing wells and are operator of
41% of those wells. We also hold interests in properties that contain proved
undeveloped natural gas and crude oil reserves that require additional
drilling, workovers, water flooding or other forms of enhancement in order to
become productive.
On properties we operate, we control capital expenditures and the timing of
all field activities and strive to manage producing properties to maximize
economic production over the life of the properties through a combination of
development well drilling, existing well recompletions and workovers and
enhanced recovery operations. We use advanced drilling technologies to minimize
costs and perform regular operational reviews to minimize operating expenses.
We continually evaluate producing property acquisition opportunities and may
increase our total annual capital expenditures depending upon our success in
identifying and completing attractive acquisitions. No major acquisitions were
made during 2001.
Business Strategy
Our business strategy focuses on achieving growth in value per share through
profitability. We accomplish this by (i) pursuing low-cost development projects
within our existing property base, (ii) pursuing selective complementary
acquisitions of high-quality, long-lived producing properties with the
potential for operating cost reductions, (iii) focusing on our expertise
developed in production from unconventional natural gas resources, (iv)
managing exposure to commodity price volatility through a hedging program and
fixed price contracts and (v) pursuing limited low-risk exploration drilling
projects.
Low-cost Development of Existing Property Base
A principal component of our strategy is to increase production and reserves
through aggressive management of operations and low-risk development drilling.
Our principal properties possess geological and
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reservoir characteristics that make them well suited for production increases
through exploitation activity and development drilling. We initiate projects to
reduce operating costs and increase production through the repair and upgrading
of lifting equipment; the redesign of equipment to improve production from
different zones; the modification of gathering and other surface facilities;
and the conduct of restimulations and recompletions. Through these and other
techniques, we regularly review operations and mechanical data on operated
properties to determine if actions can be taken to profitably increase reserves
and production.
Pursuit of Selective Complementary Acquisitions
We seek to acquire operated, long-lived producing properties that present
opportunities to profitably increase oil and gas reserves and production levels
through the implementation of technically advanced reservoir management
techniques and the reduction of expenses through the consolidation and active
management of field operations. We target acreage that will expose us to high
potential prospects located in areas that are geologically similar to
neighboring areas with large developed fields. We believe that we will be able
to continue this cost-effective acquisition strategy over the long term.
Focus on Unconventional Gas Reserves
Conventional or traditional reservoirs produce gas at commercial flow rates
with minimal stimulation requirements. Unconventional reservoirs, the opposite
of traditional, will not produce at commercial flow rates unless the formation
is successfully stimulated. The most successful form of stimulation is usually
hydraulic fracturing. Unconventional gas resources play an important role in
the production of natural gas and are the largest remaining natural gas
resources in North America. Natural gas produced from shale, coal beds and
tight sands are included in the unconventional gas resource category. The
majority of our Michigan production is from the Antrim shale where we or our
predecessors have been an active driller and producer for over ten years. Our
Antrim shale activity has allowed us to develop a technical and operational
expertise in the acquisition, development and production of unconventional
natural gas reserves. We will continue to focus on unconventional natural gas
resources in order to use our developed expertise.
Management of Product Price Risk
We are focused on growing our oil and gas operations while minimizing the
effect of commodity price swings on net income and cash flow from operations.
To help ensure a level of predictability in the prices received for our natural
gas and crude oil production and, therefore, the resulting cash flow, we have
entered into natural gas sales contracts with up to seven years remaining as
well as financial hedges that cover approximately 74% of our natural gas
production, or 60% of our total production. The commodity risk management
strategy helps to ensure a predictable, base level of cash flow which allows us
to execute drilling and exploitation programs, meet debt service requirements
and pursue acquisition opportunities even in times of weakness in the prices of
natural gas and crude oil.
Participation in Exploratory Drilling Projects
We will continue to focus the bulk of our activities on lower risk
exploitation activity and development drilling. We may, however, allocate
future capital expenditures to target high potential exploratory projects with
low financial risk. In particular, we anticipate pursuing exploratory and
follow-on development and exploitation drilling in areas which are believed to
be attractive prospects for unconventional gas projects including shales, coal
bed methane and tight sands gas, to which our technical and operational
expertise is well suited. Whenever possible, we will seek to fund the initial
higher-risk portion of capital expenditures associated with the exploration
phase of these projects through farm outs to larger, better capitalized
industry participants while maintaining the ability to participate in any
subsequent lower risk development and exploitation activities.
4
Acquisitions
CMS Acquisition
On March 31, 2000, we acquired from CMS Oil and Gas Company, a subsidiary of
CMS Energy Corporation, oil and gas properties located primarily in Michigan
("CMS Properties" or "CMS Acquisition") for $164 million. The CMS Properties
consist of interests in approximately 3,050 (650 net) producing oil and gas
wells. Proved reserves attributed to the CMS Properties include 315.1 Bcf of
natural gas, 747.8 Mbbls of crude oil and condensate and 143.9 Mbbls of natural
gas liquids, or a total of 320.4 Bcfe. Approximately 80% of the proved reserve
volumes were classified as proved developed. This acquisition doubled our
revenues, and was financed through additional borrowings and a monetization of
tax credits.
Mercury Acquisition
Effective July 31, 2000, we purchased substantially all of the oil and
gas-related assets of, and 65% of a gas compression company from, Mercury
Exploration Company ("Mercury"), a related party. The assets purchased included
all the capital stock of Mercury Michigan, Inc. ("MMI"), 65% of the capital
stock of Voyager Compression Services, LLC ("Voyager") and gas and oil
properties located in Indiana and Kentucky (See Dominion Indiana Acquisition
below). MMI is a gas processing company, which gathers and processes
approximately 75 million cubic feet of natural gas per day, and which owns
fifty percent each of Beaver Creek Pipeline, LLC ("Beaver Creek") and Cinnabar
Energy Services & Trading, LLC ("Cinnabar"). We now own 100% of Beaver Creek
and Cinnabar. Voyager sells, installs, repairs, and maintains compression
equipment for the natural gas industry.
Dominion Indiana Acquisition
On September 26, 2000, we purchased substantially all of the interests in
producing gas wells, related gathering systems and fifty percent in undeveloped
leasehold acres owned by Dominion Reserves-Indiana, Inc. for $2.2 million. We
acquired the remaining interests in these properties located in Indiana and
Kentucky from Mercury effective July 1, 2000.
MGV Energy Inc.
In December 2000, MGV Energy Inc. ("MGV"), our Canadian subsidiary,
announced the formation of a joint venture with PanCanadian Energy Corporation,
formerly PanCanadian Petroleum Limited, ("PanCanadian") to explore for and
develop coal bed methane reserves on over 1 million acres of PanCanadian lands.
The exploration project, which initially focuses on PanCanadian's Palliser
block in southern Alberta, began in December of 2000. During 2001, MGV also
entered into a joint venture agreement with Conoco, Inc. to explore for and
develop natural gas lands in central Alberta. On December 22, 2000, we acquired
the remaining minority interest in MGV we did not own for the equivalent of
283,669 shares of our common stock in the form of MGV exchangeable shares.
Marketing
The natural gas produced from our domestic properties is marketed for us by
Cinnabar under existing long-term sales contracts and short-term wholesale spot
market sales. Oil production is sold at local prices to the principal
purchasers of crude oil in the respective areas of operations. Cinnabar also
buys gas from and provides marketing services for third party producers.
Cinnabar sells the oil and gas to creditworthy counter parties, such as
utilities, major oil companies (or their affiliates), industrial customers,
large trading companies or energy marketing companies, refineries and other
users of petroleum products. Cinnabar is not confined to or dependent upon one
purchaser or a small group of
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purchasers. Accordingly, the loss of a single purchaser in areas in which
Cinnabar sells its production would not materially affect our product values.
During 2001, four purchasers accounted for approximately 16.7%, 16.4%, 16.1%
and 12.8%, respectively, of our total consolidated oil and gas sales.
Competition
We encounter substantial competition in acquiring oil and gas leases and
properties, marketing oil and gas, securing personnel and conducting our
drilling and field operations. Many competitors have financial and other
resources, which substantially exceed ours. The competitors in development,
exploration, acquisitions and production include the major oil companies as
well as numerous independents, individual proprietors and others. Resources of
our competitors may enable them to pay more for desirable leases and to
evaluate, bid for and purchase a greater number of properties or prospects. Our
ability to replace and expand our reserve base in the future through
acquisition will be dependent upon our ability to select and acquire suitable
producing properties and prospects for future drilling.
Our acquisitions have been financed through debt and internally generated
cash flow. There is competition for capital to finance oil and gas acquisitions
and drilling. Our ability to obtain such financing is uncertain and can be
affected by numerous factors beyond our control. The inability to raise capital
in the future could have an adverse effect on our business.
Governmental Regulation
Our operations are affected from time to time in varying degrees by
political developments and federal, state 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.
Environmental Matters
Our oil and natural gas exploration, development, production and pipeline
gathering operations are subject to stringent federal, state and local laws
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Numerous governmental agencies, such as the
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 civil and criminal penalties. These laws and
regulations may require the acquisition of a permit before drilling commences;
restrict the types, quantities and concentrations of various substances that
can be released into the environment in connection with drilling, production
and pipeline gathering activities; limit or prohibit drilling activities on
certain lands lying within wilderness, wetlands, frontier and other protected
areas; require some form of remedial action to prevent pollution from former
operations such as plugging abandoned wells; and impose substantial liabilities
for pollution resulting from our operations. 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 clean-up requirements could adversely affect our operations and
financial position, as well as the industry in general. 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, there is no assurance that
this will continue in the future.
The 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
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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 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 clean-up restrictions. If such legislation
were to be enacted, it could have a significant impact on our operating costs,
as well as on the industry in general. Compliance with environmental
requirements generally could have a materially adverse effect upon our capital
expenditures, earnings or competitive position. Although we have not
experienced any materially adverse effect from compliance with environmental
requirements, no assurance may be given that this will continue in the future.
The 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 limitations 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 similar 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 plans.
The Resource Conservation and Recovery Act ("RCRA"), as amended, 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 industry.
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.
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In Canada, the oil and natural 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 abandoned and reclaimed to the satisfaction of
provincial authorities. A breach of such legislation may result in the
imposition of fines and penalties.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act (AEPEA) since September 1, 1993.
In addition to replacing a variety of older statutes, which related to
environmental matters, AEPEA also imposes certain environmental
responsibilities on oil and natural gas operators in Alberta and in certain
instances also imposes greater penalties for violations.
Employees
As of March 1, 2002, we had 253 full time employees and 5 part time
employees, including officers.
ITEM 2. Description of Properties
Location and Characteristics
We own significant oil and gas production interests in the following
geographic areas:
Michigan
Reserve Data as of December 31, 2001 Average Daily Production for 2001
------------------------------------- ---------------------------------
Gas Oil NGL Total Gas Oil NGL Total
(Bcf) (Mbbl) (Mbbl) (Bcfe) (Mmcf) (Bbls) (Bbls) (Mmcfe)
----- ------ ------ ------ ------ ------ ------ -------
Producing Formation:
Antrim Shale............... 464.4 -- -- 464.4 58.0 -- -- 58.0
Prairie du Chien and Other. 54.9 3.7 1.4 85.6 25.8 1,410 346 36.3
----- --- --- ----- ---- ----- --- ----
Total.................. 519.3 3.7 1.4 550.0 83.8 1,410 346 94.3
===== === === ===== ==== ===== === ====
Michigan has very favorable natural gas supply/demand characteristics as
Michigan has been importing an increasing percentage of its natural gas, and
currently imports approximately 75% of its demand. This supply/demand situation
generally allows Michigan producers to sell their natural gas at a slight
premium to typical industry benchmark prices. It also provides opportunities
for long-term contracts at favorable terms with end users who value such supply
arrangements.
The Antrim Shale
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. While subsurface fracturing can
increase reserves and production attributable to any particular well, the over
7,100 wells drilled in the trend and the approximately 683 wells we have
drilled suggest typical per well reserves of 600 Mmcf to 800 Mmcf and 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 production level of 150 Mcf to 200
Mcf per day in six to 12 months, remaining at these levels for one to two
years, then declining at 8% to 10% per year thereafter. The total cost to drill
and complete an Antrim well is approximately $225,000, including all acreage,
production facilities and flowlines, and 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
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minimizing per unit production costs through a sizeable well-engineered
drilling program are the keys to profitable Antrim development.
At December 31, 2001, we owned interests in 2,716 Antrim wells and operated
1,329 of these wells, or 49% of our total Antrim wells. During 2001, average
net production was 58.0 Mmcfd. Since 1996, we have drilled 318 Antrim wells and
successfully completed 316 for a success rate of 99%. We have 140 net
identified Antrim drilling locations of which 103.6 (net) are currently
classified as proved undeveloped locations. In 2001, we drilled 96.1 (net)
Antrim wells, all of which were successfully completed. For 2002, we have
budgeted for the drilling of 73 (net) Antrim wells at a cost of approximately
$16.1 million.
The Prairie du Chien
Our Prairie du Chien ("PdC") wells produce from several Ordovician age
reservoirs with the majority being in the 1,000 feet to 1,200 feet thick
Prairie du Chien Group that has three major sands: the Lower PdC, Middle PdC
and Upper PdC. Many of these wells also can produce from the St. Peter
sandstone and the Glenwood formations, both of which lie directly above the
PdC. Some of the wells are producing from two or more of these zones. Depending
upon the area and the particular zone, the PdC will produce dry gas, gas and
condensate or oil with associated gas. The average depths of these wells range
from 7,000 feet to 12,000 feet.
We own an average net revenue interest of 57%, on a Bcfe basis, in the wells
comprising our PdC reserves. We operate over 98% of these reserves. Our PdC
production is well established, and four development wells have been drilled in
recent years to increase production from existing fields. 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. We fracture
stimulated six PdC wells in 2001 with an average incremental rate increase of
524 Mcfd per well. As of December 31, 2001, we had 33 gross (25.0 net) PdC
wells producing 22.9 Mmcfd. For 2002, we have budgeted $478,000 for various
workovers and recompletions on our PdC wells.
Richfield/Detroit River
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. Additional potential
exists in the Garfield Richfield either by secondary waterflood and/or improved
oil recovery ("IOR") with CO2 injection. The potential upside is under
evaluation and has not been included in our booked reserves.
The Beaver Creek Richfield is currently being waterflooded, with 110
producing wells and 59 water injection wells. The Richfield zone consists of
seven dolomite reservoirs spread over a 200-foot interval. We have drilled two
wells of a five well stepout program on the eastern flank of the structure,
with drilling operations ongoing. Once drilling operations have ceased, the
five will be completed. Pending a testing/production monitoring period of this
five well program, an additional five well drilling and completion program is
planned for late 2002.
The Detroit River Zone III ("DRZ3") at Beaver Creek also produces from three
wells. Lying approximately 200 feet above the Richfield, the DRZ3 is a six-foot
dolomite zone that covers approximately 10,000 acres on the Beaver Creek
structure. We recompleted 4 wells into the DRZ3 zone in early 2001 to further
evaluate reserve potential. Average production rates on the four wells were 20
barrels of oil per day. Two of the four wells were fracture stimulated and
produced at rates in excess of 40 barrels of oil per day each. We received
approval on a 9,600-acre unit from the state in October 2001 to develop the
DRZ3. We will be installing a central production facility to process production
from this unit, and expect to start on a 80-plus well drilling program to
develop the DRZ3 unit in early 2003. In addition to booked primary proved
developed non-producing and proved undeveloped reserves in the DRZ3, upside
potential exists for additional primary recovery through stepouts as well as
for IOR with CO2 injection.
Our average daily production from the Richfield and Detroit River formations
totals approximately 4.3 Mmcfe.
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Niagaran
Our Niagaran wells produce from numerous Silurian-age Niagaran
(dolomite/limestone) pinnacle reefs located in nine counties in Northern
Michigan. The depth of these wells range from 3,400 feet to 7,800 feet with
reservoir thickness from 300 feet to 600 feet. 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.
As of December 31, 2001, we had 64 gross (28 net) Niagaran wells producing
6.9 Mmcfe per day. We operate, on a Bcfe basis, approximately 50% of the
reserves associated with these wells.
Indiana
We acquired a 95% working interest in 33 New Albany Shale producing wells
from Dominion Reserves-Indiana effective April 1, 2000 and also acquired the
remaining 5% working interest from our predecessor, Mercury Exploration Company
effective July 1, 2000. With these two acquisitions, we also purchased the
eight-mile 12-inch GTG gas pipeline that runs from Southern Indiana to Northern
Kentucky. Current production is approximately 2.4 Mmcfd. The New Albany Shale
is similar to the Michigan Antrim, as it has to be dewatered in order to
produce desorbed methane gas. Typical reserves per well are estimated to be
approximately 250 Mmcf. We initiated a five well drilling program in December
2000 with the wells commencing production in February 2001. We subsequently
drilled an additional 10 wells that commenced production in the third and
fourth quarters of 2001. In addition, we anticipate drilling 20 to 30
additional wells in the New Albany Shale in 2002. Only 15 of these wells are
currently classified as proved, with the remaining being classified as probable.
Rocky Mountain Region
Our Rocky Mountain properties are located in Montana and Wyoming, and
production, which is primarily crude oil, is from well-established producing
formations at depths ranging from 1,000 feet to 17,000 feet. These properties
typically have multiple producing zones, some of which include the Phosphoria
at 750 feet to 1,000 feet, the Tensleep at 1,000 feet to 3,000 feet and the
Muddy/Mowry at 8,400 feet to 9,000 feet. Our Rocky Mountain producing
properties possess significant development drilling, secondary recovery and
other exploitation opportunities. As of December 31, 2001, our Rocky Mountain
proved reserves were 9.6 Mmbbls of crude oil and 4.2 Bcf of natural gas and
NGLs, for total equivalent reserves of 61.7 Bcfe. In 2001, daily production
averaged 9.9 Mmcfe. During 2001, we spent approximately $500,000 on various
exploitation activities relative to our Rocky Mountain properties.
South Casper Creek Steamflood Project
In October 1995, our predecessor acquired the South Casper Creek steamflood
project in Natrona County, Wyoming as part of a larger acquisition from Unocal.
In the 1970s and 1980s, Unocal had conducted several steamflood evaluations of
the Tensleep formation, a producing horizon that contains 14 degree gravity
crude oil which is relatively heavy and is more effectively recovered when
heated with steam, allowing the oil to flow toward the well bore at a faster
rate. In the late 1980s, Unocal attempted several additional redesigned pilot
steamfloods and had encouraging results. Based on these results, Unocal
undertook full development of the project, drilling additional steam injection
wells and installing four 50 Mmbtu per hour generators providing 13,000 barrels
of steam per day through eleven injection wells. The post-steamflood production
peaked in 1992 at 1,500 barrels per day, an 88% increase from the
pre-steamflood production of 800 barrels per day, exceeding Unocal's original
expectations. Despite this success, Unocal decided to cut the project's budget,
resulting in a decrease in steam injection, a decrease in production and the
eventual discontinuation of the project. Our predecessor's acquisition of this
project included all of the associated steam generating equipment in place that
had been installed by Unocal. This equipment is in good condition and could be
restarted at an estimated cost of under $2.4 million. While the project is
economically viable at current crude oil prices, we have excluded this
10
project from our reserve report and are studying options in light of the
project's sensitivity to long-term oil prices.
Texas
In late 2001, we upgraded compression on the Cinco Ranch #1 well in Fort
Bend County, Texas. The well is completed in the Watson sand with gross
cumulative production of 3.3 Bcf and 42,000 Bbls of condensate. The well is
currently producing at a gross rate of 2.5 Mmcfd, resulting in an incremental
increase of 1.1 Mmcfd gross (600 Mcfd net) with the compression upgrade.
Average production for 2001 was 1.3 Mmcfd.
Canada
We believe that a number of producing areas in Canada offer excellent
opportunities for acquisition and exploitation. The strengths of MGV, our
wholly-owned subsidiary, lie in its unconventional gas resource expertise and
its ability to conduct detailed reservoir engineering studies over producing
fields to identify remaining reserves not currently being exploited by the
current operator. MGV's technical staff has developed proprietary reservoir
software designed to integrate large amounts of engineering and geological data
to identify such opportunities. MGV has a joint venture with PanCanadian where
MGV identifies opportunities in a 36,000 square mile area of mutual interest.
This area of mutual interest is located primarily in southern Alberta, which
has historically produced and continues to produce significant amounts of
hydrocarbons. When MGV identifies a prospect, it has the right to acquire up to
a 20% interest if PanCanadian participates and a 100% interest if PanCanadian
declines.
MGV also has a large Coal Bed Methane ("CBM") joint venture with PanCanadian
to explore for and develop natural gas from coal beds situated on a large area
of PanCanadian lands in southern Alberta. As part of this joint venture we
drilled 8 wells in late 2000 and an additional 85 wells in 2001. Total capital
expended for the CBM project at the end of 2001 was $8.2 million and includes
costs for drilling, completions and studies performed. Planning has begun for a
proposed 250 well CBM development program that is expected to be completed
later in 2002.
MGV has also entered into a joint venture agreement with Conoco to explore
for and develop natural gas from coal beds situated on Conoco lands in central
Alberta. MGV has budgeted to drill 10 exploration wells during 2002.
During 2001, 40 infill wells were drilled on property held by the Monogram
Unit, which MGV does not operate. MGV drilled an additional 10 wells at the
Bindloss property, which they operate and own 100%. At the end of 2001, MGV
held interests in 441 non-operated wells and 92 operated wells that are 100%
owned and operated. All of the properties are located in southern Alberta.
Year-end proved reserves at December 31, 2001 were estimated to be 16.1 Bcf.
Net daily production at year-end was 2.5 Mmcf. MGV has budgeted in 2002 for the
drilling of 57 gross (7.1 net) non-CBM infill wells on non-operated lands.
Oil and Gas Reserves
The following reserve quantity and future net cash flow information concerns
our proved reserves that are primarily located in the United States. Reserve
estimates were prepared by Holditch-Reservoir Technologies Consulting Services,
independent petroleum engineers and a subsidiary of Schlumberger. The
determination of oil and gas reserves is based on estimates that are highly
complex and interpretive. The estimates are subject to continuing change, as
additional information becomes available. Under the guidelines set forth by the
SEC, the calculation is performed using year-end prices held constant (unless a
contract provides otherwise) and is based on a 10% discount rate. Future
production and development costs are based on year-end costs and include
production taxes. This standardized measure of discounted future net cash flows
is not necessarily representative of the market value of our properties.
11
The reserve data set forth in this document represents only estimates.
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 available.
The following table summarizes our proved reserves, the estimated future net
revenues from such proved reserves and the standardized measure of discounted
future net cash flows attributable to them at December 31, 2001, 2000 and 1999.
At each year-end, Canadian amounts are immaterial and therefore not shown
separately.
Year ended December 31,
----------------------------
2001 2000 1999
-------- ---------- --------
Proved reserves:
Natural gas (Mmcf).................................... 551,522 570,814 192,963
Oil (Mbbl)............................................ 13,344 14,856 15,281
Natural Gas Liquids ("NGL") (Mbbl).................... 1,538 1,535 845
Total (Mmcfe)..................................... 640,814 669,160 289,719
($ in thousands)
Estimated future net cash flows, before income tax....... $780,409 $4,026,537 $450,663
Standardized measure of discounted future net cash flows,
before income tax $358,950 $1,592,761 $253,506
Proved developed reserves:
Natural gas (Mmcf).................................... 464,964 444,865 135,326
Oil (Mbbl)............................................ 8,543 9,391 9,954
NGL (Mbbl)............................................ 1,023 813 838
Total (Mmcfe)..................................... 522,360 506,089 200,078
Volumes, Sales Prices and Oil and Gas Production Expense
The following table sets forth certain information regarding the production
and sales volumes and average sales prices and production costs associated with
our producing properties for the periods indicated.
Year Ended December 31,
-----------------------
2001 2000 1999
------- ------- -------
Production:
Natural gas (Mmcf)..................................... 32,689 26,655 15,926
Oil (Mbbl)............................................. 1,059 1,035 724
NGL (Mbbl)............................................. 195 161 129
Total (Mmcfe)...................................... 40,212 33,831 21,044
Weighted average sales price (including impact of hedges):
Natural gas (per Mmcf)................................. $ 3.03 $ 3.04 $ 2.25
Oil (per Mbbl)......................................... 21.03 22.87 14.55
NGL (per Mbbl)......................................... 19.97 25.25 9.93
Production cost (per Mcfe)(1)............................. 1.33 1.11 0.90
- --------
(1) Includes production taxes.
12
Development, Exploration and Acquisition Capital Expenditures
The following table sets forth certain information regarding the approximate
costs incurred by us in our development and exploration activities and purchase
of natural gas and oil in place (in thousands):
Year Ended December 31,
------------------------
2001 2000 1999
------- -------- -------
Acquisition of properties $ 5,749 $167,855 $40,272
Development costs........ 50,202 20,078 9,486
Exploration costs........ 10,103 360 --
------- -------- -------
Total................. $66,054 $188,293 $49,758
======= ======== =======
Productive Oil and Gas Wells
The following table summarizes the productive oil and gas wells as of
December 31, 2001, attributable to our direct interests.
Gross Net
----- -------
Natural Gas 4,419 1,273.9
Oil........ 597 538.8
----- -------
Total... 5,016 1,812.7
===== =======
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold
acreage held directly by us. Developed acres are defined as acreage spaced or
able to be assigned to productive wells. 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 oil or 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 acres. States in which we hold
undeveloped acreage include Michigan, Montana, Indiana and Wyoming.
2001 2000 1999
----------------- ----------------- ---------------
Gross Net Gross Net Gross Net
--------- ------- --------- ------- ------- -------
Developed acreage.. 801,461 270,735 594,033 272,484 268,412 132,458
Undeveloped acreage 417,193 333,812 687,472 251,034 368,438 203,825
--------- ------- --------- ------- ------- -------
Total........... 1,218,654 604,547 1,281,505 523,518 636,850 336,283
========= ======= ========= ======= ======= =======
Drilling Activity
The following table sets forth the number of wells attributable to our
direct interests drilled.
Years Ended December 31,
---------------------------------
2001 2000 1999
----------- ---------- ----------
Gross Net Gross Net Gross Net
----- ----- ----- ---- ----- ----
Development Wells:
Productive........ 198.0 122.6 55.0 35.5 25.0 24.8
Dry............... 1.0 -- -- -- 3.0 2.9
----- ----- ---- ---- ---- ----
Total.......... 199.0 122.6 55.0 35.5 28.0 27.7
===== ===== ==== ==== ==== ====
Exploratory Wells:
Productive........ 89.0 36.1 8.0 2.8 -- --
Dry............... 5.0 4.5 -- -- -- --
----- ----- ---- ---- ---- ----
Total.......... 94.0 40.6 8.0 2.8 -- --
===== ===== ==== ==== ==== ====
13
ITEM 3. Legal Proceedings
In August 2001, a group of royalty owners (Athel E. Williams et al.) brought
suit against us and three of our subsidiaries in the Circuit Court of Otsego
County, Michigan. The suit alleges that Terra Energy Ltd., one of our
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. Due to administrative oversight
an answer was not timely filed and a default was entered against us in December
2001. On March 8, 2002, the Michigan Court of Appeals vacated the trial court's
order denying our motion to set aside the default and remanded the matter to
the trial court with instructions to consider our meritorious defenses along
with our motion for reconsideration. We are taking all necessary and
appropriate legal action to have the default set aside and to defend the case.
We believe that we have meritorious defenses to the lawsuit and a legal
basis for having the default set aside. The issues in the lawsuit have not been
narrowed and any facts that would support a damage estimate have not been
gathered and analyzed. Therefore, it is not possible to estimate the damages
that could arise from the suit if the proposed class is certified. Based on
information currently available to us, we believe that the final resolution of
this matter will not have a material effect on our operations, equity or cash
flows.
ITEM 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a stockholder vote during the fourth
quarter of 2001.
14
PART II.
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters
Comparative Market Data
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 closing sales
prices of our common stock for the periods indicated below.
High Low
------ ------
2001
First Quarter. $13.20 $ 9.25
Second Quarter 20.40 11.45
Third Quarter. 18.90 10.40
Fourth Quarter 19.30 11.99
2000
First Quarter. $6.125 $3.625
Second Quarter 7.250 5.620
Third Quarter. 9.750 7.000
Fourth Quarter 9.750 7.775
As of March 1, 2002, there were approximately 488 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 primary credit facility restricts payments of dividends on our
common stock.
Sales of Unregistered Securities
Directors receive no cash remuneration for serving on the Board of Directors
but are reimbursed for reasonable expenses incurred by them. On May 2, 2001,
the Company issued 3,019 unregistered shares of its common stock to each of
Messrs. Frank Darden, Steven M. Morris, D. Randall Kent, W. Yandell Rogers, III
and Mark Warner as compensation for their services as non-employee directors
during 2000. The issuance of these securities was exempt from registration
under the Securities Act of 1933 in reliance on Section 4(2) of such act.
ITEM 6. Selected Financial Data
The following tables set forth, as of the dates and for the periods
indicated, selected financial information for us and our predecessors. Our
financial information and that of our predecessors for each year has been
derived from our or our predecessors audited consolidated financial statements
for such periods. The information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the consolidated financial statements and notes thereto
contained in this document. The following information is not necessarily
indicative of our future results.
15
Selected Financial Data of Quicksilver
(in thousands, except for per share data)
Years Ended December 31,
---------------------------------------
2001 2000 1999 1998
-------- --------- -------- --------
Consolidated Statements of Operations Data:
Total revenues................................... $143,088 $ 119,160 $ 49,814 $ 45,028
Income before income taxes and minority interest. 30,110 27,731 3,023 7,413
Net income....................................... 19,310 17,618 3,162 4,885
Net income--per share
Basic........................................ $ 1.03 $ 0.96 $ 0.24 $ 0.42
Diluted...................................... 1.00 0.95 0.24 0.42
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities............................. $ 57,921 $ 47,691 $ 10,220 $ 16,355
Investing activities............................. (67,227) (195,518) (42,288) (16,097)
Financing activities............................. 5,199 158,103 34,330 (607)
Other Consolidated Financial Data:
Capital expenditures............................. $ 67,566 $ 194,507 $ 43,452 $ 16,097
EBITDA(1)........................................ 82,504 74,410 25,762 26,476
Consolidated Balance Sheet Data:
Working capital(2)............................... $ (9,607) $ 935 $ 7,168 $ 1,291
Properties--net.................................. 412,455 374,099 170,800 134,810
Total assets..................................... 469,244 440,111 194,302 144,600
Long-term debt................................... 248,425 239,986 94,952 84,972
Stockholders' equity............................. 94,387 86,758 69,551 32,588
- --------
(1) EBITDA (as used in this financial data) is calculated by adding interest,
income taxes, minority interest and depreciation, depletion and
amortization to net income. Interest includes interest expense accrued and
amortization of deferred financing costs. EBITDA is presented here not as a
measure of operating results, but rather as a measure of our operating
performance and ability to service debt. EBITDA should not be considered as
an alternative to earnings or operating earnings, as defined by generally
accepted accounting principles, as an indicator of our financial
performance, as an alternative to cash flow, as a measure of liquidity or
as being comparable to other similarly titled measures of other companies.
(2) Excluding current hedge assets and liabilities.
Selected Historical Financial Data of Our Predecessors
MSR Exploration, Ltd.
For the Period from Inception, March 7, 1997, to December 31, 1997
(In thousands)
Statements of Operations Data:
Revenues................... $ 854
Net income................. 30
Other Information:
Capital expenditures....... $ 592
Balance Sheet Data:
Working capital............ $ 42
Total assets............... 25,963
Long-term debt............. 10,560
Stockholders' equity....... 13,070
16
Mercury Exploration Company
(Includes Quicksilver Energy, LC)
(In thousands, except for per share data)
Three Months Ended Year Ended
December 31, 1997 September 30, 1997
------------------ ------------------
Statements of Operations Data:
Revenues............................ $ 11,049 $ 41,328
Net income.......................... 2,354 5,115
Net income per common share......... 9.38 20.38
Weighted average shares outstanding. 251 251
Other Information:
Capital expenditures................ $ 27,750 $ 54,231
Balance Sheet Data:
Working capital (deficit)........... $ (9,324) $(13,133)
Total assets........................ 126,506 102,880
Long-term debt...................... 65,275 47,174
Stockholders' equity................ 17,670 15,316
Michigan Gas Partners Limited Partnership
(In thousands)
Year Ended,
December 31,
1997
------------
Statements of Operations Data:
Revenues................... $3,021
Net income................. 19
Other Information:
Capital expenditures....... $ 13
Balance Sheet Data:
Working capital............ $ 343
Total assets............... 9,835
Long-term debt............. --
Partners' equity........... 9,453
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Forward-Looking Information
Certain statements contained in this Annual Report on Form 10-K and other
materials we file with the Securities and Exchange Commission (as well as
information included in oral statements or other written statements made or to
be made by us), other than statements of historical fact, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Forward-looking statements may relate to a variety of matters not currently
ascertainable, such as future capital expenditures, drilling activity,
acquisitions and dispositions, development or exploratory activities, cost
savings efforts, production activities and volumes, hydrocarbon reserves,
hydrocarbon prices, hedging activities and the results thereof, financing
plans, liquidity, regulatory matters, competition and our ability to realize
efficiencies related to certain transactions or organizational changes.
Forward-looking statements generally are accompanied by words such as
"anticipate," "believe," "expect," "intend," "plan," "project," "potential," or
similar statements. Although we believe that the expectations reflected in such
forward-looking statements are reasonable, no assurance can be given that such
expectations will prove correct. Factors
17
that could cause our results to differ materially from the results discussed in
such forward-looking statements include: fluctuations in crude oil and natural
gas prices; failure or delays in achieving expected production from oil and gas
development projects; uncertainties inherent in predicting oil and gas reserves
and oil and gas reservoir performance; the effects of existing and future laws
and governmental regulations; liability resulting from litigation; world
economic and political conditions; changes in tax and other laws applicable to
our business and certain factors discussed elsewhere in this Annual Report on
Form 10-K. All forward-looking statements are expressly qualified in their
entirety by the cautionary statements in this section. The following discussion
and analysis should be read in conjunction with "Selected Financial Data" and
the consolidated financial statements and notes thereto, appearing elsewhere in
this annual report.
Critical Accounting Policies and Other
Our financial statements are prepared in accordance with accounting
principles generally accepted in the United States of America. The reported
financial results and disclosures were determined using significant accounting
policies, practices and estimates described below. We believe the reported
financial results are reliable and that the ultimate actual results will not
differ significantly from those reported.
Oil and Gas Properties
We employ the full cost method of accounting for our oil and gas production
assets. Under the full cost method all costs associated with the acquisition,
exploration and development of oil and gas properties are capitalized and
accumulated in cost centers on a country-by-country basis. The sum of net
capitalized costs and estimated future development and dismantlement costs is
depleted on the unit-of-production basis using proved oil and gas reserves as
determined by independent petroleum engineers.
Net capitalized costs are limited to the lower of unamortized cost net of
related deferred tax or the cost center ceiling. The cost center ceiling is
defined as the sum of (i) estimated future net revenues, discounted at 10% per
annum, from proved reserves, based on unescalated year-end prices and costs;
(ii) the cost of properties not being amortized; (iii) the lower of cost or
market value of unproved properties included in the costs being amortized; less
(iv) income tax effects related to differences between the book and tax basis
of the oil and gas properties. Future price declines, higher operating costs or
additional capitalized costs without incremental increases in oil and gas
reserves could result in the write down of net capitalized costs to the cost
center ceiling.
Reserve engineering is a subjective process that is dependent on the quality
of available data and on engineering and geological interpretation and
judgment. Reserve estimates are subject to change over time as additional
information becomes available.
Revenue Recognition
Revenues are recognized when title to the product transfers to purchasers.
We follow the "sales method" of accounting for revenue for oil and natural gas
production, so that we recognize sales revenue on all production sold to
purchasers, regardless of whether the sales are proportionate to our ownership
in the property. A receivable or liability is recognized only to the extent
that we have an imbalance on a specific property greater than the expected
remaining proved reserves. Ultimate revenues from the sales of oil and gas
production is not known with certainty until up to three months after
production and title transfer occur. Current revenues are accrued based on our
expectation of actual deliveries and actual prices received.
Hedging
We enter into financial derivative instruments to hedge risk associated with
the prices received from oil and gas production and marketing. We also utilize
financial derivative instruments to hedge the risk associated with interest on
our debt outstanding. Every derivative instrument is recorded on our balance
sheet as either an asset or liability measured at fair value determined by
reference to published future market prices and interest rates. Generally, the
cash settlement of all derivative instruments is 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.
18
Accounting and disclosure rules relating to derivative instruments accounted
for as cash flow hedges require us to increase our reported stockholders'
equity when future gas prices are forecasted to decrease relative to the strike
price in our hedges, and to decrease our reported stockholders' equity when
future gas prices increase relative to the strike price in our hedges. The
change in reported stockholders' equity relates only to our hedged production.
You should be aware that future declines in gas prices are not beneficial to us
since less than 100% of our production is hedged and even though hedge
accounting rules require us to increase our book value.
Income Taxes
Included in our net deferred tax liability is $13,650,000 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.
Internal Revenue Code Section 29 income tax benefits are due to expire at
the end of 2002. Unless new legislation extends the benefits, our income will
be lower starting in 2003. During 2001 and 2000, we recorded revenue of
$10,895,000 and $8,273,000, respectively, from Section 29 benefits and
anticipate recording $10,100,000 in 2002 from these credits.
Off Balance Sheet Arrangements
We have no off balance sheet arrangements, special purpose entities,
financing partnerships or guarantees. The companies that we have an equity
investment in do not have any significant debts.
Other
Our hedging activity coupled with our long-term gas sales contracts has
resulted in gas revenue that reflects approximately 74% of our gas sales
volumes realized at fixed prices. The remainder of our hydrocarbon volumes are
sold at market prices. Future commodity price declines will negatively impact
future income and cash flow to the extent of any production sold at market
prices. These declines could ultimately affect the quantity of proved oil and
gas reserves and cost center ceiling values. These results, individually or
collectively, could result in bank debt default and/or debt acceleration,
restrict our ability to attract qualified personnel or cause further industry
consolidation.
Geographic and product concentration may negatively impact our operations.
We are concentrated in Michigan, which is a mature basin, and sell primarily
natural gas. Regulations promulgated by the State of Michigan may put us at a
competitive disadvantage relative to gas producers in other locations. In
addition, we produce 13% of our natural gas from the Garfield Field in
Michigan. Due to the significance of this one field, disruptions could reduce
our financial results.
Our stock price may be negatively impacted by large block sales by major
shareholders. Members of the Darden family own over 50% of our common stock
outstanding, however, the Dardens have indicated they have no current intention
of disposing of any of their holdings.
Acquisitions
CMS Acquisition
On March 31, 2000, we acquired from CMS Oil and Gas Company, a subsidiary of
CMS Energy Corporation, oil and gas properties located primarily in Michigan
("CMS Properties" or "CMS Acquisition"). The purchase price, which was
finalized in November 2000, was $164 million. The CMS Properties consist of
interests in approximately 3,050 (650 net) producing oil and gas wells.
Estimated proved reserves attributed to the CMS Properties included 315.1 Bcf
of natural gas, 747.8 Mbbls of crude oil and condensate and 143.9 Mbbls of
natural gas liquids, or a total of 320.4 Bcfe. Approximately 80% of the proved
reserve volumes were classified as proved developed.
19
The CMS Acquisition was financed through restructuring of our senior bank
facility, the sale of $53 million in subordinated notes, and the monetization,
through a major financial institution, of a portion of the accompanying
Internal Revenue Code Section 29 income tax credits related to the CMS
Properties.
The CMS Acquisition was accounted for under the purchase accounting method,
and consisted of both CMS oil and gas properties and 100% of the common stock
of Terra Energy Ltd.
Mercury Acquisition
Effective July 31, 2000, we purchased substantially all of the oil and
gas-related assets of, and 65% of a gas compression company, from Mercury
Exploration Company ("Mercury"), a related party, for approximately $18
million. An independent appraiser determined the fairness, from a financial
point of view, of the $18 million purchase price, and the non-related party
members of the Board of Directors approved the purchase. The acquisition was
financed through assumption of existing debt of $6.1 million, application of an
account receivable of $7.3 million, a note payable to Mercury of $3.2 million
and accounts payable of $1.4 million.
Dominion Indiana Acquisition
Effective April 1, 2000, we purchased substantially all of the interests in
producing gas wells, related gathering systems and fifty percent in undeveloped
leasehold acres owned by Dominion Reserves-Indiana, Inc. ("Dominion") for $2.2
million. We acquired the remaining interests in these properties located in
Indiana and Kentucky from Mercury effective July 1, 2000.
MGV Energy Inc. Minority Interest Acquisition
On December 22, 2000, we acquired the remaining minority interest in our
Canadian subsidiary, MGV Energy Inc., ("MGV") headquartered in Calgary,
Alberta. Our initial 89.5% interest in MGV was acquired on August 26, 1999. In
exchange for their 10.5% interest, the minority shareholders of MGV received
the equivalent of 283,669 shares of our common stock in the form of MGV
exchangeable shares valued at $2,309,000, which was allocated to assets
acquired and liabilities assumed based upon their fair value.
Results of Operations
Summary Financial Data
Year Ended December 31, 2001 Compared with December 31, 2000
Years Ended
December 31,
-----------------
2001 2000
-------- --------
(in thousands)
Total operating revenues $143,088 $119,160
Total operating expenses 89,988 69,772
Operating income........ 53,100 49,388
Net income.............. 19,310 17,618
Net income of $19,310,000 ($1.00 per diluted share) was recorded for 2001,
an increase of 10% over 2000 net income of $17,618,000 ($0.95 per diluted
share). The increase was largely the result of a full year's operating results
from the CMS Acquisition as compared to the three quarters of results reflected
for 2000.
Operating Revenues
Total revenues for 2001 were $143,088,000, an increase of 20% from the
$119,160,000 reported in 2000. Additional volumes, resulting primarily from
properties acquired from CMS, increased hydrocarbon sales revenue by
$19,491,000 over the 2000 period while an overall decrease in prices reduced
revenue by $2,918,000.
20
Gas, Oil and Related Product Sales
Our sales volumes, revenues and average prices for the years ended December
31, 2001 and 2000 are as follows:
Years Ended
December 31,
-----------------
2001 2000
-------- --------
Average daily sales volume
Gas--Mcfd............................ 89,559 72,829
Oil--Bbld............................ 2,902 2,829
Natural gas liquids ("NGL")--Bbld.... 533 439
Total--Mcfed..................... 110,170 92,432
Product sale revenues (in thousands)
Gas sales............................ $ 99,183 $ 81,044
Oil sales............................ 22,275 23,674
NGL sales............................ 3,887 4,054
-------- --------
Total gas, oil and NGL sales..... $125,345 $108,772
======== ========
Unit prices-including impact of hedges
Gas price per Mcf.................... $ 3.03 $ 3.04
Oil price per Bbl.................... 21.03 22.87
NGL price per Bbl.................... 19.97 25.25
Gas sales of $99,183,000 for 2001 were 22% higher than the $81,044,000 for
2000 as gas volumes increased 23% to 32,689,000 Mcf in 2001. Additional gas
sales volumes of 6,000,000 Mcf contributed $18,306,000 of additional revenue
over 2000. Higher gas volumes were primarily the result of approximately
3,994,000 Mcf in the first quarter from properties acquired from CMS and
approximately 371,000 Mcf from Indiana properties acquired from Mercury and
Dominion in the fourth quarter of 2000. Approximately 163,000 Mcf were added
from the Bindloss area acquired in early 2001 by MGV. An additional 540,000 Mcf
were attributable to prior year production payouts identified during 2001.
Capital expenditures for drilling, recompletions and workovers in 2001 resulted
in a 2,400,000 Mcf increase in sales volumes. These increases were offset by
natural production declines on existing production. In 2001, we drilled 127 net
productive wells excluding Canadian exploratory wells. Additionally, we
successfully worked over or recompleted 86 net wells during 2001. Average
prices were virtually unchanged from 2000.
Oil sales declined to $22,275,000 for 2001 compared to $23,674,000 in 2000.
Average oil sales prices in 2001 were $21.03 per barrel compared to $22.87 per
barrel in 2000. Lower prices decreased revenue $1,903,000 over the prior year.
Additional oil production contributed $504,000 of revenue as compared to 2000.
Crude oil production increased 24,000 barrels from 2000 as a result of 58,000
barrels in the first quarter from CMS properties and 116,000 barrels from 2001
capital expenditures partially offset by production declines on existing
production.
NGL sales for 2001 were essentially unchanged from 2000. Revenue of
$3,887,000 resulted from NGL production of 195,000 barrels as compared to
$4,054,000 in revenue from 160,000 barrels in 2000. Capital expenditures
increased 2001 sales volumes by 47,000 barrels that were partially offset by
production declines on existing production.
Other Revenues
Other revenue in both 2001 and 2000 primarily consisted of income associated
with Section 29 tax credits and income associated with marketing,
transportation and processing of natural gas. Deferred income of $9,396,000 was
recognized from the 2000 Section 29 tax credit monetization compared to
$6,842,000 in 2000. Revenue from prior Section 29 tax credit monetizations was
$1,499,000, an increase of $68,000 over 2000. Natural gas marketing,
transportation and processing income for 2001 was $5,143,000 as compared to
21
$1,049,000 in 2000 due primarily to increased third party marketing activity in
2001 and inclusion of a full year's results in 2001, for the operations
acquired from Mercury effective July 1, 2000. Income from equity subsidiaries
increased $358,000 to $1,125,000 primarily as a result of a full year's
activity from partnership interests also acquired from Mercury in 2000. During
the year, $1,651,000 was received from a customer in bankruptcy of which
$580,000 was recorded in other revenue and $1,071,000 was recorded as reversal
of bad debt expense.
Operating Expenses
Operating expenses of $89,988,000 in 2001 were 29% higher than the
$69,772,000 incurred in 2000. The increase was the result of additional volumes
from acquisition properties, prior period payout expenses and a full year's
expenses associated with the marketing, transportation and processing
operations acquired from Mercury in 2000. Also included is a recovery of a
$1,071,000 provision for doubtful accounts associated in with the 1999
bankruptcy of one of our natural gas purchasers.
Oil and Gas Production Costs
Oil and gas production costs for 2001 were $53,550,000 and 43% higher than
the $37,574,000 incurred in 2000. Increased sales volumes from 2000
acquisitions, prior year payouts and other production increases resulted in
approximately $6,981,000 of additional production expense. Higher levels of
compressor maintenance and well workovers, increased well counts and additional
field and production office personnel accounted for the remaining $7,789,000
increase. Production taxes increased $1,206,000 to $7,945,000 in 2001 as a
result of increased sales volumes partially offset by lower average sales
prices for 2001.
Other Operating Costs
Other operating costs of $1,196,000 are associated with the marketing,
transportation and processing operations acquired from Mercury. The increase of
$532,000 over 2000 reflects a full year's activity for 2001.
Depletion and Depreciation
Years Ended
December 31,
------------------------
2001 2000
----------- ------------
(in thousands, except
per unit amounts)
Depletion......................... $26,162 $22,985
Depreciation of other fixed assets 2,481 1,570
------- -------
Total depletion and depreciation.. $28,643 $24,555
======= =======
Average depletion cost per Mcfe... $ 0.65 $ 0.68
Depletion increased to $26,162,000 in 2001 from $22,985,000 in 2000.
Depletion increased $4,152,000 as a result of increased sales volumes,
partially offset by a $975,000 decrease due to a lower depletion rate that
resulted from increased reserve volumes as compared to the prior year.
Depreciation increased $911,000 to $2,481,000 in 2001 primarily as a result of
the gas processing and transportation assets acquired in the Mercury
acquisition as well as gas compression facilities added in 2001.
General and Administrative Expenses
General and administrative costs incurred during 2001 were $7,670,000 and
$412,000 higher than 2000. The increase was primarily the result of additional
contract labor expense of $469,000 and additional stock exchange fees of
approximately $124,000 relating to our listing on the New York Stock Exchange,
offset by reductions in various other categories.
22
Interest Expense and Other Income/ Expense
Interest expense of $23,751,000 in 2001 increased $1,627,000 from 2000. The
increase reflects an additional quarter of interest for debt incurred for the
acquisition of the CMS Properties partially offset by lower effective interest
rates in 2001.
Other income increased $294,000 primarily as a result of additional interest
income earned on invested operating cash balances.
Income Taxes
Years Ended
December 31,
----------------
2001 2000
------- -------
Income tax provision (in thousands) $10,800 $10,113
Effective tax rate................. 35.9% 36.5%
The income tax provision of $10,800,000 was established using an effective
U.S. federal tax rate of 35%. The 2001 current portion of $463,000 consists of
federal alternative minimum tax of $178,000 and Canadian and state income tax
expense of $285,000. Income tax expense increased $687,000 as a result of
additional pretax income in 2001 partially offset by a decrease in the 2001
effective tax rate.
The deferred income tax liability at December 31, 2001 was $51,113,000. The
increase in the deferred tax liability over the December 31, 2000 balance is
the result of deferred income tax expense of $10,337,000. The increase is
partially offset by the $7,252,000 deferred tax benefit related to deferred
losses associated with hedge derivatives.
Summary Financial Data
Year Ended December 31, 2000 Compared with December 31, 1999
Years Ended
December 31,
----------------
2000 1999
-------- -------
(in thousands)
Total operating revenues $119,160 $49,814
Total operating expenses 69,772 38,182
Operating income........ 49,388 11,632
Net income.............. 17,618 3,162
We recorded net income of $17,618,000 ($0.95 per diluted share) in 2000,
compared to net income of $3,162,000 ($0.24 per diluted share) in 1999. The
improvement was largely due to the increase in production resulting from the
CMS Properties acquired March 31, 2000 and higher product prices.
Operating Revenues
Total revenues for the year ended December 31, 2000 were $119,160,000; an
increase of 139% from the $49,814,000 reported for the year ended December 31,
1999. Higher volumes contributed $40,540,000 of the revenue increase while
increased prices added $20,616,000 to revenue. Volume increases were primarily
the result of production from properties acquired from CMS on March 31, 2000.
Other revenue increased $8,190,000 from the prior year primarily as a result of
deferred revenue recognition from the 2000 Section 29 tax credit monetization.
23
Gas, Oil and Related Product Sales
Our revenues for the year ended December 31, 2000 increased significantly
over 1999 as further shown below:
Years Ended
December 31,
----------------
2000 1999
- -------- -------
Average daily sales volume
Gas--Mcfd............................ 72,829 43,633
Oil--Bbld............................ 2,829 1,984
NGL--Bbld............................ 439 353
Total--Mcfed..................... 92,432 57,655
Product sale revenues (in thousands)
Gas sales............................ $ 81,044 $35,799
Oil sales............................ 23,674 10,540
NGL sales............................ 4,054 1,277
-------- -------
Total gas, oil and NGL sales..... $108,772 $47,616
======== =======
Unit prices-including impact of hedges
Gas price per Mcf.................... $ 3.04 $ 2.25
Oil price per Bbl.................... 22.87 14.55
NGL price per Bbl.................... 25.25 9.93
Gas sales of $81,044,000 for 2000 were 126% higher than the $35,799,000 for
1999. Gas volumes increased 67% over 1999 primarily as a result of volumes sold
from properties acquired from CMS. Additional volumes of 10,729,000 Mcf
contributed $32,622,000 of additional revenue over 1999. Average gas prices
were $3.04 per Mcf for 2000, $0.79 per Mcf higher than the average price
received in 1999. Increased prices added $12,623,000 of revenue as compared to
1999.
Oil sales grew 125% to $23,674,000 for 2000 compared to $10,540,000 in 1999.
Crude oil production for 2000 was 1,035,000 barrels compared to 724,000 barrels
in 1999. Additional volumes were primarily the result of production from the
CMS Properties. The additional 311,000 barrels contributed increased revenue of
$7,113,000 over 1999. Average 2000 oil sales prices were $22.87 per barrel
compared to $14.55 per barrel in 1999 and resulted in higher revenues of
$6,021,000.
NGL sales of $4,054,000 for 2000 increased significantly over sales for
1999. NGL prices increased from $9.93 to $25.25 per Bbl and added revenue of
$1,972,000. The additional NGL volumes, primarily from the CMS Properties,
added $804,000 of revenue.
Other Revenue
Other revenue increased by $8,190,000 to $10,388,000 in 2000 compared to
$2,198,000 in 1999. Deferred revenue recognition from the 2000 Section 29 tax
credit monetization was $6,842,000. Revenue from our marketing, transportation
and gas processing subsidiaries was $1,049,000 and income from equity
affiliates increased $867,000, both as a result of the acquisition of assets
from Mercury effective July 1, 2000.
Operating Expenses
Operating expenses of $69,772,000 in 2000 were 83% higher than the
$38,182,000 incurred in 1999 reflecting the addition of the CMS Properties,
Mercury assets and additional activity associated with MGV during 2000.
Oil and Gas Production Costs
Oil and gas production expenses for 2000 were $37,574,000, an increase of
$18,708,000, or 99%, from 1999 expense of $18,866,000. Lease operating expenses
increased 88%, or $14,403,000, to $30,835,000, reflecting an
24
increase of 61% in sales volumes from 1999 and increases in production overhead
as a result of additional operated wells associated with the CMS Acquisition.
Increased sales volumes and higher prices resulted in an increase of
$4,305,000, or 177%, in severance tax expense to $6,739,000.
Other Operating Costs
Other operating costs of $664,000 were the result of expenses incurred
during the last half of 2000 for the marketing, transportation and processing
operations acquired from Mercury in 2000.
Depletion and Depreciation
Year Ended
December 31,
---------------------
2000 1999
------- -------
(in thousands, except
per unit amounts)
Depletion......................... $22,985 $13,315
Depreciation of other fixed assets 1,570 721
------- -------
Total depletion and depreciation.. $24,555 $14,036
======= =======
Average depletion cost per Mcfe... $ 0.68 $ 0.63
Depletion and depreciation increased to $24,555,000 in 2000 from $14,036,000
in 1999. Depletion increased $9,670,000 to $22,985,000 primarily as a result of
production volumes associated with the CMS Properties and higher depletion
rates. Depreciation increased primarily as a result of the gas processing and
transportation assets acquired from Mercury.
General and Administrative Expenses
General and administrative costs incurred during 2000 were $7,258,000, 85%
higher than in 1999, reflecting higher salaries and related payroll expenses
($1,486,000), office and building rent expense ($718,000), professional fees
($572,000), and franchise taxes ($282,000). These increases were related to our
growth through the CMS Acquisition and the purchase of Mercury assets.
Interest Expense and Other Income/ Expenses
Interest expense of $22,124,000 for 2000 increased $13,421,000 from 1999
interest expense reflecting higher debt levels due primarily to the CMS
Acquisition and higher effective interest rates in 2000.
The $373,000 increase in other income for 2000 was the result of additional
interest income earned on cash balances.
Income Taxes
Years Ended
December 31,
-------------
2000 1999
------- ----
Income tax provision (in thousands) $10,113 $ 2
Effective tax rate................. 36.5% --
The income tax provision of $10,113,000 includes taxes on pre-tax earnings
at the statutory rate of 35% and adjustment of prior deferred taxes. The prior
deferred tax balance was recorded at 34% since it was previously estimated that
the timing differences would reverse at the lower rate. The increase in our
profitability from the CMS Acquisition and record high prices will result in
future taxable income at the 35% rate. In 1999, $1,026,000 of income taxes that
would otherwise have been due were eliminated because of the utilization of net
operating losses available from prior years.
25
As of December 31, 2000, we had a deferred tax liability of $47,748,000. The
increase in the deferred tax liability over the December 31, 1999 balance
includes $24,497,000 as a result of the CMS Acquisition and a $2,628,000
reduction in the liability that resulted from the acquisition of the Mercury
assets effective July 31, 2000. The remainder of the increase is the result of
year 2000 deferred tax expense.
Liquidity and Capital Resources
General
The following discussion compares our financial condition at December 31,
2001 and 2000. For the years ended December 31, 2001 and 2000, $67,566,000 and
$194,507,000, respectively, were spent on acquisition, development and
exploration activities. The capital program was financed from operations,
additional borrowings, and proceeds from the exercise of stock options and
warrants.
Internal Revenue Code Section 29 income tax benefits are due to expire at
the end of 2002, and, unless new legislation extends the benefits, our income
will be lower starting in 2003. During 2001 and 2000, we recorded revenue of
$10,895,000 and $8,273,000 respectively from Section 29 benefits and anticipate
recording revenue of $10,100,000 in 2002. Of these amounts, $1,499,000,
$1,431,000 and $1,300,000 represent cash payments for 2001, 2000 and estimated
2002, respectively.
Cash Flow
We believe that our capital resources are adequate to meet the requirements
of our business. We anticipate our 2002 capital expenditure budget of
approximately $61,000,000 will be funded by cash flow from operations, stock
warrants exercised and credit facility utilization. However, future cash flows
are subject to a number of variables including the level of production and oil
and gas prices, and there can be no assurance that operations and other capital
resources will provide cash in sufficient amounts to maintain planned levels of
capital expenditures.
We have a credit facility, which is a three-year revolving facility that
matures on March 31, 2003 and permits us to obtain revolving credit loans and
to issue letters of credit for our account from time to time in an aggregate
amount not to exceed $225,000,000. The current borrowing base is $210,000,000
and is subject to semi-annual determination and certain other redeterminations
based upon a variety of factors, including the discounted present value of
estimated future net cash flow from our natural gas and crude oil production.
The next scheduled re-determination date will be as of May 1, 2002, based on
December 31, 2001 assets and proved reserves. At our option, loans may be
prepaid, and revolving credit commitments may be reduced in whole or in part at
any time in minimum amounts. As of year-end, we can designate the interest rate
on amounts outstanding at either the London Interbank Offered Rate
(LIBOR)+2.25% or bank prime rate. At December 31, 2001, our interest rate was
4.850% through April 2, 2002 on $177 million. The collateral for the Credit
Facility consists of substantially all of our existing assets and any future
reserves acquired. The loan agreements prohibit the declaration or payment of
dividends by us and contain other restrictive covenants, which, among other
things, require the maintenance of a minimum current ratio. We currently are in
compliance with all such restrictions. At December 31, 2001, we had $19,431,000
available under the credit facility.
Our principal operating sources of cash include sales of natural gas and
crude oil and revenues from transportation and processing. We sell
approximately 74% of our natural gas production under long-term, fixed price
contracts and swap agreements. As a result, we benefit from significant
predictability of our natural gas revenues. Commodity market prices affect cash
flow for that portion of natural gas not under contract as well as our crude
oil sales.
Net cash provided by operations for the year ended December 31, 2001 was
$57,921,000 compared to $47,691,000 for the same period last year. The increase
resulted from higher earnings and increased working capital from operations.
26
Net cash used in investing for the year ended December 31, 2001 was
$67,227,000. Investing activities were comprised primarily of additions to oil
and gas properties through development expenditures of $50,202,000, exploration
expenditures of $10,103,000 and property acquisitions of $5,749,000. Included
in exploratory expenditures were $8,022,000 for our share of the PanCanadian
and Conoco coal bed methane projects.
Net cash from financing activities for the year ended December 31, 2001 was
$5,199,000. Cash of $1,895,000 was received from the exercise of warrants and
employee stock options. Borrowings under our credit facility increased by
$10,000,000 and were partially offset by various other note and loan repayments
of $6,618,000 resulting in net additional borrowings of $3,382,000.
Contractual Obligations and Commercial Commitments
We have the following contractual obligations as of December 31, 2001.
Payments Due by Period
-----------------------------------------
Less
than 1 4-5 After 5
Contractual Obligations Total Year 1-3 Years Years Years
----------------------- -------- ------ --------- ------- -------
(in thousands)
Long-Term Debt......... $249,370 $ 945 $192,835 $22,905 $32,685
Operating Leases....... 5,304 1,049 2,214 1,020 1,021
Gas Purchase Obligation 5,225 5,225 -- -- --
Other.................. 205 32 96 64 13
-------- ------ -------- ------- -------
Total Obligation.... $260,104 $7,251 $195,145 $23,989 $33,719
Long-Term Debt--We have a credit facility, which is a three-year revolving
facility that matures on March 31, 2003. This facility permits us to obtain
revolving credit loans and to issue letters of credit for our account from time
to time, in an aggregate amount not to exceed $225,000,000. We had $190,000,000
outstanding as of December 31, 2001 under the credit facility. The remaining
long-term debt consists of Subordinated Notes of $54,853,000 and various other
notes of $4,500,000.
Operating Leases--We lease office buildings and other property under
operating leases.
Gas Purchase Obligation--Cinnabar Energy Services and Trading LLC, our
wholly owned subsidiary, has an index-based contract to purchase 21,500 Mcf/day
from November 2001 through March 2002. Cinnabar also has index-based sales
contracts for these volumes through March 2002 that yield a net margin for the
product purchased.
We have the following commercial commitments as of December 31, 2001.
Amounts of Commitments Expiration per Period
--------------------------------------------
Less
Total than 1 1-3 4-5 After 5
Commercial Commitments Committed Year Years Years Years
---------------------- --------- ------ ----- ----- -------
(in thousands)
Canadian Coal Bed Methane Development $4,000 $4,000 $ -- $ -- $ --
Standby Letters of Credit............ 799 799 -- -- --
------ ------ ----- ---- ----
Total Commitments................. $4,799 $4,799 $ -- $ -- $ --
Canadian Coal Bed Methane Development--We have minimum drilling commitments
under operating agreements with joint venture partners.
27
Standby Letters Of Credit--Our letters of credit have been issued due to
federal and state regulatory requirements. The majority of these letters are
against the credit facility. All letters have an annual renewal option.
Recently Issued Accounting Standards
The Financial Accounting Standards Board ("FASB") recently issued Statement
of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations",
which applies to all business combinations for which the date of acquisition is
July 1, 2001, or later. SFAS No. 141 supersedes Accounting Principles Board
Opinion No. 16, "Business Combinations" and requires all business combinations
to be accounted for using the purchase method. Adoption of this statement has
had no impact on our financial statements.
The FASB also issued SFAS No. 142, "Goodwill and Other Intangible Assets,"
which is effective for fiscal years beginning after December 15, 2001. SFAS No.
142 gives direction for accounting for goodwill and intangible assets. We
believe the adoption of this statement will have no impact on our financial
statements.
The FASB also issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which is effective for fiscal years beginning after June 15,
2002. SFAS No. 143 gives guidance for accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. We are in the process of evaluating the impact of the
provisions of SFAS No. 143.
The FASB also issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," which is effective for fiscal years beginning
after December 15, 2001. SFAS No. 144 supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of." SFAS No. 144 provides a single method of accounting for long-lived assets
to be disposed of and retains requirements found in SFAS No. 121 with regards
to the impairment of long-lived assets. We are in the process of evaluating the
impact of the provisions of SFAS No. 144.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
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 commodity prices. We
have mitigated the downside risk of adverse price movements through the use of
swaps, futures and forward contracts; however, we have also limited future
gains from favorable movements.
Commodity Price Risk
We enter into various sales and financial contracts to hedge our exposure to
commodity price risk associated with anticipated future natural gas production.
These contracts have included physical sales contracts and financial contracts
including price ceilings and floors, no-cost collars and fixed price swaps. As
of December 31, 2001, we sell approximately 25,000 Mcfd and 10,000 Mcfd of
natural gas under long-term fixed price contracts at $2.49/Mcf and $2.47/Mcf,
respectively, through March 2009. Approximately 27,600 Mcfd of our natural gas
production was sold under these contracts during 2001. The remaining 7,400 Mcfd
sold under these contracts were third-party volumes controlled by us.
Additionally, we have hedged approximately 38,100 Mcfd of our natural gas
production using fixed price swap agreements at prices averaging $2.70 per Mcf.
These agreements expire from April 2004 to April 2005. As a result of these
various contracts, we benefit from significant predictability of our natural
gas revenues.
28
The following table summarizes our open financial derivative positions as of
December 31, 2001 related to natural gas production.
Weighted Avg
Product Type Contract Period Volume Price Per Mcf Fair Value
- ------- ----------- ----------------- ----------- ------------------- --------------
(in thousands)
Gas Fixed Price Jan 2002-Apr 2004 7,500 Mcfd $ 2.40 $ (4,085)
Gas Fixed Price Jan 2002-Dec 2004 559 Mcfd 1.94 (486)
Gas Fixed Price Jan 2002-Apr 2005 10,000 Mcfd 2.79 (4,131)
Gas Fixed Price Jan 2002-Apr 2005 10,000 Mcfd 2.79 (4,216)
Gas Fixed Price Jan 2002-Apr 2005 10,000 Mcfd 2.79 (4,216)
Gas Collar Apr 2002-Oct 2002 5,000 Mcfd 2.55--3.50 255
--------
Net Open Positions $(16,879)
========
Commodity price fluctuations affect the remaining natural gas volumes as
well as our crude oil and NGL volumes. Up to 4,500 Mcfd of natural gas is
committed at market price through May 2004. Additional natural gas volumes of
16,500 Mcfd are committed at market price through September 2008. During 2001,
approximately 9,500 Mcfd of our natural gas production was sold under these
contracts. An additional 11,500 Mcfd sold under these contracts were
third-party volumes controlled by us.
Cinnabar Energy Services & Trading, LLC ("Cinnabar"), our wholly owned
marketing company, also enters into various financial contracts to hedge its
exposure to commodity price risk associated with future contractual natural gas
sales and purchases. These contracts include either fixed and floating price
sales or purchases from third parties. As a result of these firm sales and
purchase commitments and associated financial price swaps, the hedge
derivatives have qualified as either cash flow or fair value hedges. Hedge
ineffectiveness resulted in $48,000 of net gains recorded to other revenue for
2001. At December 31, 2001, we have recorded an asset of $1,476,000 for the
fair value of the firm sales commitments. Additionally, we have recorded
current assets of $121,000 and current liabilities of $1,521,000 associated
with the fair value of the financial fixed and floating price swaps.
The following table summarizes Cinnabar's open financial derivative
positions and hedged firm commitments as of December 31, 2001 related to
natural gas marketing.
Weighted Avg
Product Type Contract Period Volume Price per Mcf Fair Value
- ------- -------------- ----------------- ----------- ------------------ --------------
(in thousands)
Fixed price sales and purchase contracts
Gas Sale Jan 2002-Mar 2002 20,000 Mcfd $3.52 $ 1,444
Gas Sale May 2002-Aug 2002 691 Mcfd 3.15 32
Gas Purchase Jan 2002 1,008 Mcfd 2.56 --
-------
1,476
Financial derivatives
Gas Floating Price Jan 2002-Mar 2002 20,000 Mcfd (1,489)
Gas Floating Basis Jan 2002-Mar 2002 20,000 Mcfd 90
Gas Floating Price Jan 2002-Aug 2002 978 Mcfd (32)
Gas Floating Price Jan 2002 5,000 Mcfd 3
Gas Fixed Price Jan 2002 5,000 Mcfd $2.74 28
-------
(1,400)
-------
Net open positions $ 76
=======
29
Utilization of our hedging program may result in realization of natural gas
and crude oil prices varying from market prices that we receive from the sale
of natural gas and crude oil. As a result of the hedging programs, revenues
from production were lower than if the hedging program had not been in effect
by $22,052,000 in 2001, $22,474,000 in 2000 and $1,021,000 in 1999. Marketing
revenues were $2,957,000 lower as a result of hedging activities in 2001.
The fair value of fixed price and floating price natural gas financial
contracts and associated firm sales commitments as of December 31, 2001 was
estimated based on published market prices of natural gas for the periods
covered by the contracts. The net differential between the prices in each
contract 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 natural gas financial swap and firm sales
commitment fair value does not necessarily represent the value a third party
would pay to assume our contract positions
Based on the financial fixed price hedge positions, for each $1.00 per Mcf
increase in the price of natural gas, our annualized revenue would increase by
approximately $22,615,000 of which $13,908,000 would be reduced due to the
existing hedges.
Interest Rate Risk
We manage our exposure associated with interest rates by entering into
interest rate swaps. As of December 31, 2001, we have hedged $75,000,000 of our
variable-rate debt and $53,000,000 of our fixed-rate Second Mortgage Notes
("Subordinated Notes").
As of December 31, 2001, $75,000,000 of the variable-rate debt is hedged
with interest rate swaps converting the debt's floating LIBOR base to a 6.72%
fixed-rate resulting in a liability of $3,832,000. In November 2001, we entered
into an interest rate swap covering the $53,000,000 of fixed-rate Subordinated
Notes. The swap converts the debt's 14.75% fixed-rate debt to a floating
three-month LIBOR base resulting in an asset of $1,853,000 as of December 31,
2001. We have revalued the Subordinated Notes to offset the fair value of the
swap as required by SFAS No. 133. If interest rates on our $168,000,000
variable debt increase or decrease by one percentage point, our annual pretax
income will decrease or increase by $1,680,000.
Interest expense for the year ended December 31, 2001 was $1,528,000 higher
as a result of the interest rate swaps.
Credit Risk
Credit risk is the risk of loss as a result of non-performance by counter
parties of their contractual obligations. We sell our oil and gas production
directly under long-term contracts and through Cinnabar to creditworthy counter
parties, such as utilities, major oil companies (or their affiliates),
industrial customers, large trading companies or energy marketing companies,
refineries and other users of petroleum products. We monitor exposure to
counter parties by reviewing credit ratings, financial statements and credit
service reports. Exposure levels are limited and parental guarantees are
required according to our established policy. In this manner, we reduce credit
risk.
Performance Risk
Performance risk results when a financial counter party 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 and/or
counter party is reviewed as to credit worthiness prior to the extension of
credit and on a regular basis thereafter.
Foreign Currency Risk
Our Canadian subsidiary uses the Canadian dollar as its functional currency.
To the extent that business transactions in Canada are not denominated in
Canadian dollars, we are exposed to foreign currency exchange rate risk.
30
ITEM 8. Financial Statements and Supplementary Data
QUICKSILVER RESOURCES INC.
INDEX TO FINANCIAL STATEMENTS
Page
----
QUICKSILVER RESOURCES INC.
Independent Auditors' Report................................ 32
Consolidated Balance Sheets as of December 31, 2001 and 2000 33
Consolidated Statements of Income for the Years Ended
December 31, 2001, 2000 and 1999.......................... 34
Consolidated Statements of Stockholder's Equity for the
Years Ended December 31, 2001, 2000 and 1999.............. 35
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999.......................... 36
Notes to Consolidated Financial Statements for the Years
Ended December 31, 2001, 2000 and 1999.................... 37
31
INDEPENDENT AUDITORS' REPORT
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. (the Company) as of December 31, 2001 and December 31, 2000, and
the related consolidated statements of income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 Company as of December 31,
2001 and 2000, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States of America.
Deloitte & Touche LLP
Fort Worth, Texas
March 8, 2002
32
QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2001 AND 2000
In thousands, except for share data
2001 2000
-------- --------
ASSETS
Current Assets
Cash and cash equivalents............................................................ $ 8,726 $ 12,833
Accounts receivable.................................................................. 21,489 32,595
Inventories and other current assets................................................. 5,079 2,021
-------- --------
Total current assets............................................................. 35,294 47,449
Investments in and advances to equity affiliates........................................ 14,248 12,570
Properties, plant and equipment--net ("full cost")...................................... 412,455 374,099
Other assets............................................................................ 7,247 5,993
-------- --------
$469,244 $440,111
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current portion of long-term debt.................................................... $ 945 $ 4,149
Accounts payable..................................................................... 12,168 12,787
Accrued derivative obligations....................................................... 9,025 --
Accrued liabilities.................................................................. 29,936 29,578
-------- --------
Total current liabilities........................................................ 52,074 46,514
Long-term debt.......................................................................... 248,425 239,986
Unearned revenue........................................................................ 9,562 18,958
Deferred derivative obligations......................................................... 13,461 --
Other long-term liabilities............................................................. 222 147
Deferred income taxes................................................................... 51,113 47,748
Stockholders' equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued as of
December 31, 2001 and 2000......................................................... -- --
Common stock, $0.01 par value, 40,000,000 shares authorized, 22,534,875 and
22,332,950 shares issued as of December 31, 2001 and 2000, respectively............ 225 223
Paid in capital in excess of par value.................................................. 77,814 75,544
Treasury stock of 3,751,852 and 3,765,947 shares as of December 31, 2001and 2000,
respectively.......................................................................... (14,634) (14,675)
Accumulated other comprehensive income.................................................. (14,007) (13)
Retained earnings....................................................................... 44,989 25,679
-------- --------
94,387 86,758
-------- --------
$469,244 $440,111
======== ========
The accompanying notes are an integral part of these financial statements.
33
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
In thousands, except for per share data
2001 2000 1999
-------- -------- -------
Revenues
Oil, gas and related product sales........... $125,345 $108,772 $47,616
Other revenue................................ 17,743 10,388 2,198
-------- -------- -------
Total revenues........................... 143,088 119,160 49,814
Expenses
Oil and gas production costs................. 53,550 37,574 18,866
Other operating costs........................ 1,196 664 --
Depletion and depreciation................... 28,643 24,555 14,036
Provision for doubtful accounts.............. (1,071) (279) 1,350
General and administrative................... 7,670 7,258 3,930
-------- -------- -------
Total expenses........................... 89,988 69,772 38,182
-------- -------- -------
Operating income................................ 53,100 49,388 11,632
Other income-net................................ (761) (467) (94)
Interest expense................................ 23,751 22,124 8,703
-------- -------- -------
Income before minority interest & income taxes.. 30,110 27,731 3,023
Minority interest in net loss of MSR Exploration -- -- (141)
Income tax expense.............................. 10,800 10,113 2
-------- -------- -------
Net income...................................... $ 19,310 $ 17,618 $ 3,162
======== ======== =======
Basic earnings per share........................ $ 1.03 $ 0.96 $ 0.24
======== ======== =======
Diluted earnings per share...................... $ 1.00 $ 0.95 $ 0.24
======== ======== =======
Basic weighted average of shares outstanding.... 18,664 18,290 13,151
======== ======== =======
Diluted weighted average shares outstanding..... 19,221 18,467 13,151
======== ======== =======
The accompanying notes are an integral part of these financial statements.
34
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
In thousands, except for share and per share data
2001 2000 1999
-------- -------- -------
Preferred stock, par value $0.01, 10,000,000 shares authorized
Balance at beginning of year........................................... $ -- $ -- $ --
Issuance of 1 share special voting preferred........................... -- -- --
-------- -------- -------
Balance at end of year: 1 share issued at December 31, 2001 and 2000... -- -- --
-------- -------- -------
Common stock, par value $0.01, authorized 40,000,000 shares
Balance at beginning of year........................................... 223 180 115
Issuance of common stock............................................... 2 40 51
Common stock issued for purchase of minority interest.................. -- 3 14
-------- -------- -------
Balance at end of year: 22,534,875, 22,332,950 and 17,994,900 shares
issued at December 31, 2001, 2000 and 1999, respectively............. 225 223 180
-------- -------- -------
Paid in capital in excess of par value
Balance at beginning of year........................................... 75,544 61,383 27,574
Acquisition of minority interest....................................... (59) 2,306 10,629
Acquisition of Mercury Assets.......................................... 396 (4,883) --
Issuance of common stock............................................... 1,933 16,779 23,806
Stock registration fees................................................ -- (41) (626)
-------- -------- -------
Balance at end of year................................................. 77,814 75,544 61,383
-------- -------- -------
Treasury stock
Balance at beginning of year........................................... (14,675) (73) --
(Acquisition) reissuance of treasury stock, at cost-net................ 41 (14,602) (73)
-------- -------- -------
Balance at end of year: 3,751,852, 3,765,947 and 10,808 shares at cost
December 31, 2001, 2000, and 1999, respectively...................... (14,634) (14,675) (73)
-------- -------- -------
Retained earnings
Balance at beginning of year........................................... 25,679 8,061 4,899
Net income............................................................. 19,310 17,618 3,162
-------- -------- -------
Balance at end of year................................................. 44,989 25,679 8,061
-------- -------- -------
Accumulated other comprehensive income
Deferred foreign exchange adjustment
Balance at beginning of year....................................... (13) -- --
Foreign currency translation adjustment............................ (660) (13) --
-------- -------- -------
Balance at end of year............................................. (673) (13) --
-------- -------- -------
Deferred gains (losses) from hedge derivatives
Adoption of SFAS No. 133 at January 1, 2001........................ (60,304) -- --
Reclassification adjustment--hedge settlements..................... 15,234 -- --
Change in derivative fair value.................................... 31,736 -- --
-------- -------- -------
Balance at end of year............................................. (13,334) -- --
-------- -------- -------
Total other comprehensive income.......................................... (14,007) (13) --
-------- -------- -------
Total stockholders' equity................................................ $ 94,387 $ 86,758 $69,551
======== ======== =======
The accompanying notes are an integral part of these financial statements.
35
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS END DECEMBER 31, 2001, 2000 AND 1999
In thousands
2001 2000 1999
-------- --------- --------
Operating Activities:
Net income................................................... $ 19,310 $ 17,618 $ 3,162
Charges and credits to net income not affecting cash
Depletion and depreciation............................... 28,643 24,555 14,036
Deferred income taxes.................................... 10,337 10,143 --
Recognition of unearned revenues......................... (9,396) (6,842) (538)
(Income) loss from equity affiliates..................... (1,125) (768) 99
Amortization of deferred loan costs...................... 1,606 1,071 244
Provision for doubtful accounts.......................... -- -- 1,350
Other.................................................... (40) (166) (141)
Changes in assets and liabilities
Accounts receivable...................................... 10,833 (23,839) (9,128)
Inventory, prepaid expenses and other.................... (1,877) (530) (14)
Accounts payable......................................... (619) 4,008 1,462
Accrued liabilities...................................... 249 22,441 (311)
-------- --------- --------
Net cash from operating activities.............................. 57,921 47,691 10,221
-------- --------- --------
Investing activities:
Acquisition of properties and equipment...................... (67,409) (191,157) (40,253)
Acquisition of pipeline and facilities....................... -- (1,952) (3,199)
Acquisition of Mercury assets, net of cash balances received. (157) (1,398) --
Advances (to) from equity affiliates-net..................... 290 (1,285) --
Proceeds from sale of properties............................. 49 274 1,164
-------- --------- --------
Net cash used for investing activities.......................... (67,227) (195,518) (42,288)
-------- --------- --------
Financing activities:
Notes payable, bank proceeds................................. 18,000 250,172 35,365
Principal payments on long-term debt......................... (14,618) (112,468) (23,342)
Monetization of Section 29 tax credits....................... -- 25,000 --
Issuance of common stock..................................... 1,895 -- 23,180
Payments to acquire treasury stock........................... (78) -- (73)
Deferred financing and stock registration costs.............. -- (4,601) (800)
-------- --------- --------
Net cash from financing activities.............................. 5,199 158,103 34,330
-------- --------- --------
Net increase (decrease) in cash and equivalents................. (4,107) 10,276 2,263
Cash and equivalents at beginning of period..................... 12,833 2,557 294
-------- --------- --------
Cash and equivalents at end of period........................... $ 8,726 $ 12,833 $ 2,557
======== ========= ========
The accompanying notes are an integral part of these financial statements.
36
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. NATURE OF OPERATIONS
Quicksilver Resources Inc. ("Quicksilver" or the "Company") is an
independent oil and gas company incorporated in the state of Delaware and
headquartered in Fort Worth, Texas. On March 4, 1999, Quicksilver (including
the assets of Mercury Exploration Company and Michigan Gas Partners Limited
Partnership) completed a merger with MSR Exploration Ltd. In connection with
the merger, the Company issued shares of its common stock in exchange for all
the outstanding common stock of MSR. Quicksilver also converted all the
outstanding MSR stock options and warrants into Quicksilver stock options and
warrants (see note 15).
The Company has U.S. offices in Gaylord, Michigan, Cut Bank, Montana, and
Casper, Wyoming, and a Canadian subsidiary, MGV Energy Inc. ("MGV") located in
Calgary, Alberta. The Company engages in the acquisition, development,
exploration, production and sale of natural gas, crude oil and natural gas
liquids. Quicksilver also engages in the marketing, processing and transmission
of natural gas. A substantial portion (86%) of the Company's reserves are
located in Michigan and 72% are located in the Michigan Antrim shale gas
fairway.
The Company's results of operations are largely dependent on the difference
between the prices received for its oil and gas products and the cost to find,
develop, produce and market such resources. Oil and gas prices are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond its control. These factors include worldwide political
instability, quantity of natural gas in storage, foreign supply of crude oil
and natural gas, the price of foreign imports, the level of consumer demand and
the price of available alternative fuels. Quicksilver manages a portion of the
operating risk relating to oil and gas price volatility through hedging and
fixed price contracts.
The Company is currently expanding its presence in Canada through its
subsidiary, MGV. MGV is participating in the exploration for and development of
coal bed methane reserves in Canada through two joint ventures with major
Canadian energy companies. The first venture with PanCanadian Energy
Corporation started in late 2000 on PanCanadian's large acreage position in
Southern Alberta. Thirty-seven exploration wells and fifty-six pilot wells have
been drilled through December 31, 2001 and the joint venture plans to initiate
a proposed 250 well development program later in 2002. The second venture with
Conoco, Inc. was signed in mid-2001 and plans to drill ten exploratory wells
during 2002 on Conoco lands in Southern Alberta.
2. SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Quicksilver
Resources Inc. and subsidiaries (collectively, the "Company"). The Company
accounts for investments in entities, which it does not control, on the equity
method of accounting. The Company also consolidates its pro-rata share of oil
and gas joint ventures. All significant inter-company transactions are
eliminated.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts
of certain assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during each reporting period. Management believes its
estimates and assumptions are reasonable however, such estimates and
assumptions are subject to a number of risks and uncertainties, which may cause
actual results to differ materially from the
37
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Company's estimates. Significant estimates underlying these financial
statements include the estimated quantities of proved oil and gas reserves used
to compute depletion of oil and gas properties and the related present value of
estimated future net cash flows there from and the estimated fair value of
financial derivative instruments. (See Supplementary Information beginning on
page 56.)
Cash and Cash Equivalents
Cash equivalents consist of time deposits and liquid debt investments with
original maturities of three months or less.
Accounts Receivable
The Company's customers are large oil and natural gas purchasers. Each
customer and/or counter-party of the Company is reviewed as to credit
worthiness prior to the extension of credit and on a regular basis thereafter.
The Company does not require collateral, however, appropriate credit ratings
are required and parental guarantees are obtained. Receivables are generally
due in 30-60 days. When collections of specific amounts due are no longer
reasonably assured, an allowance for doubtful accounts is established. During
2001, four purchasers accounted for approximately 16.7%, 16.4%, 16.1% and
12.8%, respectively, of the Company's total consolidated oil and gas sales.
Hedging
The Company enters into financial derivative instruments to hedge price risk
for its oil and gas sales and interest rate risk in accordance with SFAS No.
133 (see note 3). The Company does not enter into financial derivatives for
trading or speculative purposes.
Derivatives that qualify as hedges are recorded on the balance sheet as
either an asset or liability measured at fair value and recognized in revenues
or interest expense in the period in which the hedged transaction is
recognized. Fair value is determined by reference to published future market
prices or interest rates. Ineffective portions of hedges are recognized
currently in earnings.
The Company's long term fixed price contracts for delivery of 25,000 Mcfd
and 10,000 Mcfd at $2.49 and $2.47, respectively, through March 2009 are not
considered derivatives but rather normal sales contracts under SFAS No. 133.
Approximately 7,400 Mcfd of these volumes are third-party volumes controlled by
the Company.
Inventories
Inventories consist of well equipment, spare parts and supplies carried on a
first in first out basis at the lower of cost or market.
Properties, Plant, and Equipment
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition, exploration
and development of oil and gas properties, including costs of undeveloped
leasehold, geological and geophysical expenses, dry holes, leasehold equipment
and overhead charges directly related to acquisition, exploration and
development activities, are capitalized. Proceeds received from disposals are
credited against accumulated cost except when the sale represents a significant
disposal of reserves, in which case a gain or loss is recognized.
The sum of net capitalized costs and estimated future development and
dismantlement costs is depleted on the equivalent unit-of-production method,
based on proved oil and gas reserves as determined by independent
38
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
petroleum engineers. Excluded from amounts subject to depletion are costs
associated with unevaluated properties. Oil and natural gas are converted to
equivalent units based upon the relative energy content, which is six thousand
cubic feet of natural gas to one barrel of crude oil.
Net capitalized costs are limited to the lower of unamortized cost net of
deferred tax or the cost center ceiling. The cost center ceiling is defined as
the sum of (i) estimated future net revenues, discounted at 10% per annum, from
proved reserves, based on unescalated year-end prices and costs, (ii) the cost
of properties not being amortized, (iii) the lower of cost or market value of
unproved properties included in the cost being amortized; less (iv) income tax
effects related to differences between the book and tax basis of the oil and
gas properties. Such limitations are imposed separately on a country-by-country
basis.
All other properties and equipment are stated at original cost and
depreciated using the straight-line method based on estimated useful lives from
five to forty years.
Revenue Recognition
Revenues are recognized when title to the products transfer to the
purchaser. The Company follows the "sales method" of accounting for its oil and
natural gas revenue, so that the Company recognizes sales revenue on all oil or
natural gas sold to its purchasers, regardless of whether the sales are
proportionate to the Company's ownership in the property. A receivable or
liability is recognized only to the extent that the Company has an imbalance on
a specific property greater than the expected remaining proved reserves. As of
December 31, 2001 and 2000, the Company's aggregate oil and natural gas
imbalances were not material to its consolidated financial statements.
Environmental Compliance and Remediation
Environmental compliance costs, including ongoing maintenance and
monitoring, are expensed as incurred. Environmental remediation costs, which
improve the condition of a property, are capitalized.
Income Taxes
Deferred income taxes are established for all temporary differences between
the book and the tax basis of assets and liabilities at rates that will be in
effect in years the temporary differences are expected to reverse. 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.
Disclosure of Fair Value of Financial Instruments
The Company's financial instruments include cash, time deposits, accounts
receivable, notes payable, accounts payable, and long-term debt. The fair value
of long-term debt is estimated at the present value of future cash flows
discounted at rates consistent with comparable maturities for credit risk. The
carrying amounts reflected in the balance sheet for financial assets classified
as current assets and the carrying amounts for financial liabilities classified
as current liabilities approximate fair value due to the short maturity of such
instruments.
Change in Presentation
Certain reclassifications have been made for comparative purposes for
presentations adopted in 2001.
Earnings per share
Basic net income or loss per common share is computed by dividing the net
income or loss attributable to common stockholders by the weighted average
number of shares of common stock outstanding during the period.
39
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Diluted net income or loss per common share is calculated in the same manner,
but also considers the impact to net income and common shares for the potential
dilution from stock options, stock warrants and any other outstanding
convertible securities.
The following is a reconciliation of the numerator and denominator used for
the computation of basic and diluted net income per common share.
Years Ended December 31,
------------------------
2001 2000 1999
------- ------- -------
(in thousands, except
per share data)
Net income............................. $19,310 $17,618 $ 3,162
======= ======= =======
Weighted average common shares--basic.. 18,664 18,290 13,151
Effect of dilutive securities:
Stock options....................... 488 171 --
Warrants............................ 69 6 --
------- ------- -------
Weighted average common shares--diluted 19,221 18,467 13,151
======= ======= =======
Net income--per share
Basic............................... $ 1.03 $ 0.96 $ 0.24
Diluted............................. 1.00 0.95 0.24
Warrants representing 550,000 shares of common stock were excluded from the
2001 diluted net income per share computation as the exercise price exceeded
the average market price of the Company's common stock. For the years ended
December 31, 2000 and 1999, 24,856 shares of common stock under options were
excluded from the diluted net income per share computations as the exercise
price exceeded the average market price of the Company's common stock. Warrants
representing 1,100,000 and 1,128,000 shares, respectively, of common stock were
also excluded from the 2000 and 1999 diluted net income per share computation
as the exercise price exceeded the average market price of the Company's common
stock.
Segment Information
The Company has reviewed the requirements under Financial Accounting
Standards Board ("FASB") SFAS No. 131, "Disclosure about Segments of an
Enterprise and Related Information." The Company believes it has one reportable
operating segment and its operations outside of the U.S. are not yet material.
Recently Issued Accounting Standards
The FASB recently issued SFAS No. 141, "Business Combinations", which
applies to all business combinations for which the date of acquisition is July
1, 2001, or later. SFAS No. 141 supersedes Accounting Principles Board Opinion
No. 16, "Business Combinations" and requires all business combinations to be
accounted for using the purchase method. Adoption of this statement has had no
impact on the Company's financial statements.
The FASB also issued SFAS No. 142, "Goodwill and Other Intangible Assets,"
which is effective for fiscal years beginning after December 15, 2001. SFAS No.
142 gives direction for accounting for goodwill and intangible assets. The
Company believes the adoption of this statement will have no impact on its
financial statements.
The FASB also issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which is effective for fiscal years beginning after June 15,
2002. SFAS No. 143 gives guidance for accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. The Company is in the process of evaluating the impact
of the provisions of SFAS No. 143.
40
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
The FASB also issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," which is effective for fiscal years beginning
after December 15, 2001. SFAS No. 144 supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of." SFAS No. 144 provides a single method of accounting for long-lived assets
to be disposed of and retains requirements found in SFAS No. 121 with regards
to the impairment of long-lived assets. The Company is in the process of
evaluating the impact of the provisions of SFAS No. 144.
3. CHANGE IN ACCOUNTING PRINCIPAL--HEDGING
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities". It requires that every
derivative instrument be recorded on the balance sheet as either an asset or
liability measured at fair value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If hedge criteria are met, the change in a
derivative's fair value (for a cash flow hedge) is deferred in stockholder's
equity as a component of other comprehensive income. These deferred gains and
losses are recognized in income in the period in which the hedged transaction
is recognized in revenues to the extent the hedge is effective. The ineffective
portions of hedges are recognized currently in earnings.
All existing derivatives within the Company were identified prior to January
1, 2001. The Company designated, documented and assessed the hedging
relationships. These hedges included all of the Company's existing financial
fixed price gas swaps, which extend through April 2005 and interest rate swaps,
which extend through March 2003. Adoption by the Company of the accounting
standard as of January 1, 2001 resulted in the recognition of $93.4 million of
derivative liabilities with a cumulative effect of $60.3 million after tax as a
decrease to other comprehensive income, a component of stockholders' equity.
During 2001, Cinnabar Energy Services and Trading LLC ("Cinnabar"), the
Company's wholly owned marketing subsidiary, entered into both fixed and
floating price firm gas sales and purchase commitments and associated financial
floating price swaps which extend through August 2002. The derivative
transactions qualify as either cash flow or fair value hedges. Hedge
ineffectiveness resulted in $48,000 of net gains recorded to other revenue in
2001. At December 31, 2001, the Company recorded an asset of $1,476,000,
included in other current assets, for the fair value of the firm sales
commitments. Additionally, the Company has recorded current assets of $121,000
and current liabilities of $1,521,000 associated with the fair value of the
financial fixed and floating price swaps.
The Company has interest rate swap agreements covering $75,000,000 of its
variable-rate debt through March 31, 2003 that converts the floating debt from
a London Interbank Offered Rate ("LIBOR") base rate to a 6.72% fixed rate. The
fair value of these swaps was a loss of $3,832,000 as of December 31, 2001.
On November 16, 2001, the Company entered into an interest rate swap
agreement covering its $53,000,000 of Second Mortgage Notes ("Subordinated
Notes"). The agreement converts the debt's 14.75% fixed rate to a floating
three-month LIBOR base rate. The interest rate swap has qualified as a fair
value hedge. The Company recorded an asset of $1,853,000 for the fair value of
this swap agreement at December 31, 2001. Additionally, the Company has
revalued the Subordinated Notes to offset the fair value of the swap as
required by SFAS No. 133.
The change in carrying value of the Company's financial fixed price and
floating price gas swaps and interest rate swaps in the Company's balance sheet
since January 1, 2001 resulted from a decrease in market prices for natural gas
and interest rates. This change in fair value was reflected in accumulated
other comprehensive income, net of deferred tax effects. Natural gas derivative
assets and liabilities reflected as
41
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
current in the December 31, 2001 balance sheet represent the estimated fair
value of contract settlements scheduled to occur over the subsequent
twelve-month period based on market prices for natural gas as of the balance
sheet date. Because present accounting rules do not provide for the accrual of
the future cash flow transactions the natural gas swaps were designed to hedge,
an apparent working capital deficit is created which does not, in management's
opinion, accurately depict the Company's true working capital position or its
liquidity. These settlement amounts are not due and payable until the monthly
period that the related underlying hedged gas sales transaction occurs.
Settlement of the underlying hedged transaction occurs in the following month.
The estimated fair values of all hedge derivatives and the associated fixed
price firm sales and purchase commitments as of December 31 and January 1, 2001
are provided below. The associated carrying values of these swaps are equal to
the estimated fair values for each period presented.
December 31, January 1,
2001 2001
------------ ----------
(in thousands)
Derivative assets:
Fixed price sales commitments.............. $ 1,476 $ --
Natural gas financial collars.............. 255 --
Floating price natural gas financial swaps. 93 --
Fixed price natural gas financial swaps.... 28 --
Fixed to Floating interest rate swap....... 1,853 --
------- -------
$ 3,705 $ --
======= =======
Derivative liabilities:
Fixed price natural gas financial swaps.... $17,134 $91,969
Floating price natural gas financial swaps. 1,521 --
Floating to Fixed interest rate swap....... 3,832 1,443
------- -------
$22,487 $93,412
======= =======
The fair value of natural gas financial swaps and firm sales commitments as
of December 31 and January 1, 2001 was estimated based on market prices of
natural gas for the periods covered by the swaps. The net differential between
the prices in each swap 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 swap at rates commensurate with federal treasury instruments with
similar contractual lives. As a result, the natural gas financial swap and firm
sales commitment fair values do not necessarily represent the value a third
party would pay to assume the Company's contract positions. Of the $20,966,000
of cash flow hedge liabilities, $7,504,000 has been classified as current based
on the maturity of the derivative instruments resulting in $4,864,000 of
after-tax losses to be reclassified from other comprehensive income in 2002.
The fair value of interest rate swaps was based upon counter party estimates
of the fair value of such swaps.
4. FINANCIAL INSTRUMENTS
The Company has established policies and procedures for managing risk within
its organization, including internal controls. The level of risk assumed by the
Company is based on its objectives and capacity to manage risk.
42
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Quicksilver's primary risk exposure is related to natural gas commodity
prices. The Company has mitigated the downside risk of adverse price movements
through the use of swaps, futures and forward contracts, however, it has also
limited future gains from favorable movements.
Commodity Price Risk
The Company enters into various sales and financial contracts to hedge its
exposure to commodity price risk associated with anticipated future natural gas
production. These contracts have included physical sales contracts and
financial contracts including price ceilings and floors, no-cost collars and
fixed price swaps. As of December 31, 2001, Quicksilver sells approximately
25,000 Mcfd and 10,000 Mcfd of natural gas under long-term fixed price
contracts at $2.49/Mcf and $2.47/Mcf, respectively, through March 2009.
Approximately 27,600 Mcfd of the Company's natural gas production was sold
under these contracts during 2001. The remaining 7,400 Mcfd sold under these
contracts were third-party volumes controlled by the Company. Additionally, the
Company has hedged approximately 38,100 Mcfd of its natural gas production
using fixed price swap agreements at prices averaging $2.70 Mcf. These
agreements expire from April 2004 to April 2005. As a result of these various
contracts, the Company benefits from significant predictability of its natural
gas revenues. The following table summarizes the Company's open financial
derivative positions as of December 31, 2001 related to natural gas production.
Weighted Avg
Product Type Contract Period Volume Price Per Mcf Fair Value
- ------- ----------- ----------------- ----------- ------------------- --------------
(in thousands)
Gas Fixed Price Jan 2002-Apr 2004 7,500 Mcfd $ 2.40 $ (4,085)
Gas Fixed Price Jan 2002-Dec 2004 559 Mcfd 1.94 (486)
Gas Fixed Price Jan 2002-Apr 2005 10,000 Mcfd 2.79 (4,131)
Gas Fixed Price Jan 2002-Apr 2005 10,000 Mcfd 2.79 (4,216)
Gas Fixed Price Jan 2002-Apr 2005 10,000 Mcfd 2.79 (4,216)
Gas Collar Apr 2002-Oct 2002 5,000 Mcfd 2.55--3.50 255
--------
Net Open Positions $(16,879)
========
Commodity price fluctuations affect the remaining natural gas volumes as
well as the Company's crude oil and NGL volumes. Up to 4,500 Mcfd of natural
gas is committed at market price through May 2004. Additional natural gas
volumes of 16,500 Mcfd are committed at market price through September 2008.
During 2001, approximately 9,500 Mcfd of Quicksilver's natural gas production
was sold under these contracts. An additional 11,500 Mcfd sold under these
contracts were third-party volumes controlled by the Company.
Based on the financial fixed price hedge positions, for each $1.00 per Mcf
increase in the price of natural gas, the Company's annualized revenue would
increase by approximately $22,615,000, of which $13,908,000 would be reduced
due to the existing hedges.
43
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Cinnabar also enters into various financial contracts to hedge its exposure
to commodity price risk associated with future contractual natural gas sales
and purchases with derivative instruments. The following table summarizes
Cinnabar's open financial derivative positions and hedged firm commitments as
of December 31, 2001 related to natural gas marketing.
Weighted Avg
Product Type Contracted Period Volume Price per Mcf Fair Value
- ------- -------------- ----------------- ----------- ------------------- --------------
(in thousands)
Fixed price sales and purchase contracts
Gas Sale Jan 2002-Mar 2002 20,000 Mcfd $ 3.52 $ 1,444
Gas Sale May 2002-Aug 2002 691 Mcfd 3.15 32
Gas Purchase Jan 2002 1,008 Mcfd 2.56 --
-------
1,476
Financial derivatives
Gas Floating Price Jan 2002-Mar 2002 20,000 Mcfd (1,489)
Gas Floating Basis Jan 2002-Mar 2002 20,000 Mcfd 90
Gas Floating Price Jan 2002-Aug 2002 978 Mcfd (32)
Gas Floating Price Jan 2002 5,000 Mcfd 3
Gas Fixed Price Jan 2002 5,000 Mcfd $ 2.74 28
-------
(1,400)
-------
Net open positions $ 76
=======
Utilization of the Company's hedging program may result in natural gas and
crude oil realized prices varying from market prices that the Company receives
from the sale of natural gas and crude oil. As a result of the hedging
programs, revenues from production in 2001, 2000 and 1999 were $22,052,000,
$22,474,000 and $1,021,000, respectively, lower than if the hedging program had
not been in effect. Marketing revenues for Cinnabar were $2,957,000 lower as a
result of its hedging activities in 2001.
The fair value of fixed price and floating price natural gas financial
contracts and associated firm sales commitments as of December 31, 2001 was
estimated based on market prices of natural gas for the periods covered by the
contracts. The net differential between the prices in each contract 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 natural gas financial swap and firm sales commitment fair
value does not necessarily represent the value a third party would pay to
assume the Company's contract positions.
Interest Rate Risk
The Company manages it exposure associated with interest rates by entering
into interest rate swaps. As of December 31, 2001, Quicksilver has hedged
$75,000,000 of its variable-rate debt and its $53,000,000 of fixed-rate
Subordinated Notes.
As of December 31, 2001, $75,000,000 of the variable-rate debt is hedged
with interest rate swaps converting the debt's floating LIBOR base to a 6.72%
fixed-rate and a liability of $3,832,000 as of December 31, 2001. In November
2001, the Company entered into an interest rate swap covering the $53,000,000
of fixed-rate Subordinated Notes. The swap converts the debt's 14.75%
fixed-rate debt to a floating LIBOR base resulting in an asset of $1,853,000 as
of December 31, 2001. The Company has revalued the Subordinated Notes to offset
the fair value of the swap as required by SFAS No. 133.
44
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Interest expense for the year ended December 31, 2001 was $1,528,000 higher
as a result of the interest rate swaps.
Credit Risk
Credit risk is the risk of loss as a result of non-performance by counter
parties of their contractual obligations. The Company sells its oil and gas
production directly under long-term contracts and, through Cinnabar, to
creditworthy counter parties, such as utilities, major oil companies (or their
affiliates), industrial customers, large trading companies or energy marketing
companies, refineries and other users of petroleum products. The Company
monitors exposure to counter parties by reviewing credit ratings, financial
statements and credit service reports. Exposure levels are limited and parental
guarantees are required according to Company policy. In this manner, the
Company reduces credit risk.
Performance Risk
Performance risk results when a financial counter-party fails to fulfill its
contractual obligations such as commodity pricing or volume commitments.
Typically, such risk obligations are defined within the trading agreements. The
Company manages performance risk through management of credit risk. Each
customer and/or counter party of the Company is reviewed as to credit
worthiness prior to the extension of credit and on a regular basis thereafter.
Foreign Currency Risk
The Company's Canadian subsidiary uses the Canadian dollar as its functional
currency. To the extent that business transactions in Canada are not
denominated in Canadian dollars, the Company is exposed to foreign currency
exchange rate risk.
5. ACQUISITIONS
During the year 2000, Quicksilver more than doubled its revenue base
primarily through acquisitions funded through additional borrowings.
CMS Acquisition
On March 31, 2000, the Company acquired from CMS Oil and Gas Company, a
subsidiary of CMS Energy Corporation, oil and gas properties located primarily
in Michigan ("CMS Properties" or "CMS Acquisition"). The purchase price, which
was finalized in November 2000, was $164 million. The CMS Acquisition was
financed through restructuring of Quicksilver's senior bank facility, the sale
of $53 million in subordinated notes, and the monetization, through a major
financial institution, of a portion of the accompanying Internal Revenue Code
Section 29 income tax credits related to the CMS Properties (see notes 9 and
10). The CMS Acquisition was accounted for under the purchase accounting
method, and consists of both CMS oil and gas properties and 100% of the common
stock of Terra Energy Ltd.
The following table represents the allocation of the assets acquired and
liabilities assumed, based upon their fair value on the date of the CMS
Acquisition. In accordance with SFAS No. 109, "Accounting for Income Taxes", a
deferred tax liability was recognized for the differences between the allocated
values and the tax bases of the acquired assets and liabilities.
Properties and equipment $189,080,000
Working capital......... (570,000)
Deferred taxes.......... (24,497,000)
------------
Total purchase price. $164,013,000
============
45
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
The following summary pro forma financial information (in thousands, except
per share amounts) gives the effect of the acquisition on the Company's
historical income statements as though the acquisition had occurred at the
beginning of the periods presented. Adjustments were made to reflect a combined
depletion rate, incremental general and administrative expense and interest
expense on acquisition debt. The effects of the other acquisitions in the year
2000 on the consolidated financial statements are not significant and have been
excluded from the pro forma presentation.
Years Ended
December 31,
---------------------
2000 1999
-------- --------
(in thousands, except
per share data)
Revenues........... $134,618 $104,273
Expenses........... 105,549 97,111
Net income......... 18,495 5,154
Earnings per share-
Basic........... $ 1.01 $ 0.39
Diluted......... $ 1.00 $ 0.39
Mercury Acquisition
Effective July 31, 2000, Quicksilver purchased substantially all of the oil
and gas-related assets of, and 65% of a gas compression company from, Mercury
Exploration Company ("Mercury"), a related party (see note 17), for $18 million.
An independent appraiser determined the fairness, from a financial point of
view, of the $18 million purchase price, and the non-related party members of
the Board of Directors approved the purchase. The acquisition was financed
through assumption of existing debt of $6.1 million, application of an account
receivable of $7.3 million, a note of $3.2 million and accounts payable of $1.4
million. The transaction was accounted for as an acquisition of companies under
common control. As a result, all assets and liabilities acquired were recorded
at Mercury's historical book value. The excess of purchase price over book
value was accounted for as a reduction of paid in capital.
The assets purchased included all of the capital stock of Mercury Michigan,
Inc. ("MMI"), 65% of the capital stock of Voyager Compression Services, LLC
("Voyager") and gas and oil properties located in Indiana and Kentucky. MMI is
a gas processing company, which gathers and processes approximately 75 million
cubic feet of natural gas per day, and which owns fifty percent each of Beaver
Creek Pipeline, LLC ("Beaver Creek") and Cinnabar Energy Services & Trading,
LLC ("Cinnabar"). Quicksilver now owns 100% of Beaver Creek and Cinnabar.
Voyager sells, installs, repairs, and maintains compression for the natural gas
industry.
MGV Energy Inc. Minority Interest Acquisition
On December 22, 2000, Quicksilver acquired the remaining minority interest
in its Canadian subsidiary, MGV Energy Inc., headquartered in Calgary, Alberta.
Quicksilver's initial 89.5% interest in MGV was acquired on August 26, 1999. In
exchange for their 10.5% interest, the minority shareholders of MGV received
the equivalent of 283,669 shares of Quicksilver common stock in the form of MGV
exchangeable shares valued at $2,309,000, which was allocated to the assets
acquired and liabilities assumed based upon their fair value.
46
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. ACCOUNTS RECEIVABLE
On March 10, 1999, one of the Company's natural gas purchasers filed for
protection under Chapter 11 of the Federal Bankruptcy Code. Management
determined that a portion of the approximate $2,450,000 account receivable
associated with the purchaser was uncollectable; accordingly, an allowance for
doubtful accounts of $1,350,000 was established in the first quarter of 1999.
The Company recovered $1,379,000 during 2000 and an additional $1,651,000
during 2001. As a result, $1,071,000 and $279,000 were recorded in 2001 and
2000, respectively, as recoveries of the provision for doubtful accounts. The
remaining $580,000 was recorded to other revenue in 2001.
7. PROPERTIES AND EQUIPMENT
Property and equipment includes the following:
As of December 31,
-------------------
2001 2000
--------- --------
(in thousands)
Oil and gas properties
Subject to depletion............................................... $ 480,925 $430,328
Unevaluated costs.................................................. 14,458 8,239
Accumulated depletion.............................................. (114,437) (88,079)
--------- --------
Net oil and gas properties............................................ 380,946 350,488
Other equipment
Pipeline and gathering and processing facilities................... 33,959 25,359
General properties................................................. 5,823 4,249
Accumulated depreciation........................................... (8,273) (5,997)
--------- --------
Net other property and equipment 31,509 23,611
--------- --------
Property and equipment, net of accumulated depreciation, depletion and
amortization........................................................ $ 412,455 $374,099
========= ========
Unevaluated costs incurred in 2001 include $8,022,000 for the Company's coal
bed methane exploration project in the Alberta province of Canada, which is
expected to be tested and evaluated in 2002. These costs include internal costs
of $481,000 directly related to the project. An additional $1,996,000 was
incurred in 2000 to purchase the minority interest in MGV. The remaining
unevaluated costs are primarily for leasehold acquisitions.
47
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Depletion per Mcfe was $0.65, $0.68 and $0.63 for the years ended December
31, 2001, 2000 and 1999 respectively.
8. OTHER ASSETS
Other assets consist of:
As of December 31,
-----------------
2001 2000
------- -------
(in thousands)
Deferred loan costs........... $ 6,514 $ 6,068
Less accumulated amortization. (3,080) (1,378)
------- -------
Net deferred loan costs.... 3,434 4,690
Hedge derivatives (see note 3) 1,853 --
Other......................... 1,960 1,303
------- -------
$ 7,247 $ 5,993
======= =======
Costs related to the acquisition of debt are deferred and amortized on a
straight-line basis over the term of the debt.
9. ACCRUED LIABILITIES
Accrued liabilities include the following:
As of December 31,
------------------
2001 2000
------- -------
(in thousands)
Accrued product purchases... $ 9,180 $14,417
Interest owners payable..... 5,375 4,281
Interest payable............ 3,577 3,997
Accrued operating expenses.. 6,697 3,180
Accrued capital expenditures 3,010 --
Mercury payable............. -- 1,773
Environmental liabilities... 698 845
Other....................... 1,399 1,085
------- -------
$29,936 $29,578
======= =======
48
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
10. NOTES PAYABLE AND LONG-TERM DEBT
As of December 31,
------------------
2001 2000
-------- --------
(in thousands)
Long-term debt consists of:
Notes payable to banks..... $190,000 $180,000
Subordinated notes payable. 54,853 53,000
Various loans.............. 4,517 11,135
-------- --------
249,370 244,135
Less current maturities....... (945) (4,149)
-------- --------
$248,425 $239,986
======== ========
Maturities are as follows, in thousands of dollars:
Years Ending
------------
2002....... $ 945
2003....... 190,945
2004....... 945
2005....... 945
2006....... 10,674
2007....... 12,231
Thereafter. 32,685
--------
$249,370
========
The Company has a credit facility, which is a three-year revolving facility
that matures on March 31, 2003 and permits the Company to obtain revolving
credit loans and to issue letters of credit for the account of the Company from
time to time in an aggregate amount not to exceed $225 million. The borrowing
base is $210 million and is subject to semi-annual determination and certain
other redeterminations based upon a variety of factors, including the
discounted present value of estimated future net cash flow from the Company's
natural gas and crude oil production. The next scheduled re-determination date
will be as of May 1, 2002, based on December 31, 2001 assets and proved
reserves. At the Company's option, loans may be prepaid, and revolving credit
commitments may be reduced in whole or in part at any time in minimum amounts.
As of year-end, the Company can designate the interest rate on amounts
outstanding at either the LIBOR + 2.25% or bank prime. At December 31, 2001,
the Company's interest rate was 4.85% through April 2, 2001 on $177 million.
The collateral for the credit facility consists of substantially all of the
existing assets of the Company and any future reserves acquired. The loan
agreements prohibit the declaration or payment of dividends by the Company and
contain other restrictive covenants, which, among other things, require the
maintenance of a minimum current ratio. The Company currently is in compliance
with all such restrictions. At December 31, 2001, the Company had $19,431,000
available under the credit facility.
The Company also sold $43 million of 14.75% Second Mortgage Notes
("Subordinated Notes") on March 31, 2000 and an additional $10 million on April
24, 2000. Prepayments made before March 28, 2003 will require a premium payment
ranging from 3% to 6%. Quarterly interest payments to the note holders may be
paid in kind with respect to all or any portion of interest in excess of 10% by
issuing additional notes. The Subordinated Notes contain restrictive covenants,
which, among other things, require maintenance of working capital, collateral
coverage ratio and an earnings ratio before interest, taxes, depreciation and
amortization and
49
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
costs associated with seismic geological and geological services in connection
and attributable to oil and gas exploration ("EBITDAX"). The Company is
currently in compliance with such restrictions. The Subordinated Notes include
a FAS 133 fair value adjustment of $1,853,000 as of December 31, 2001. The
Subordinated Notes are due on March 30, 2009, with quarterly principal payments
starting on June 28, 2006.
As a part of the Mercury Acquisition, the Company assumed a Mercury
Exploration Company note payable with a balance of $1,853,000 and an interest
rate of 10% as of December 31, 2001. The Company also incurred debt to Mercury
Exploration Company as part of this acquisition. This note has an interest rate
of 9% with quarterly principal payments of $160,000 plus interest through
December 2005. The balance of this note was $2,560,000 as of December 31, 2001.
As of December 31, 2001, the balance reflected for the Company's fixed-rate
debt, including the SFAS No. 133 fair value adjustment for the interest rate
hedge, approximates fair value.
11. TAX CREDIT SALES
Certain properties of the Company carry Internal Revenue Code Section 29
income tax benefits. Code Section 29 allows a credit against regular federal
income tax liability for certain eligible gas production.
On March 31, 2001, the Company conveyed, to a bank, Section 29 tax credits
for 99.5% of the interests acquired from CMS and the Terra interests in
Devonian production from certain wells located in Michigan. Cash proceeds
received from the sale were $25 million and were recorded as unearned revenue.
Revenue is recognized as reserves are produced. The purchase and sale agreement
and ancillary agreements with the bank include a production payment in favor of
Quicksilver burdening future production on the properties. Revenue of
$9,396,000 and $6,842,000 was recognized in 2001 and 2000, respectively, in
other revenue.
During 1997, other tax credits were conveyed through the sale of certain
working interests to a bank. As of December 31, 2001, a balance of $800,000 in
other long-term liabilities existed as a result of the cash consideration
received in excess of the tax benefit earned. The balance of $800,000 will be
applied to repurchasing the remaining interests in the properties after the
Section 29 credits expire at the end of 2002. Revenue of $1,499,000 and
$1,431,000 was recognized in 2001 and 2000, respectively, in other revenue.
12. COMMITMENTS AND CONTINGENCIES
The Company leases office buildings and other property under operating
leases. Future minimum lease payments, in thousands, for operating leases with
initial non-cancelable lease terms in excess of one year as of December 31,
2001, were as follows:
2002................... $1,049
2003................... 922
2004................... 751
2005................... 541
2006................... 510
2007................... 510
Thereafter............. 1,021
------
Total lease commitments $5,304
======
Rent expense for operating leases with terms exceeding one month was
$1,693,000 in 2001, $1,088,000 in 2000, and $206,000 in 1999.
50
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
As of December 31, 2001, the Company had approximately $799,000 in letters
of credit outstanding related to various state and federal bonding requirements.
The Company is subject to various possible contingencies, which arise
primarily from interpretation of federal and state laws and regulations
affecting the oil and natural gas industry. Such contingencies include
differing interpretations as to the prices at which oil and natural gas sales
may be made, the prices at which royalty owners may be paid for production from
their leases, environmental issues and other matters. Although management
believes it has complied with the various laws and regulations, administrative
rulings and interpretations thereof, adjustments could be required as new
interpretations and regulations are issued. In addition, production rates,
marketing and environmental matters are subject to regulation by various
federal and state agencies.
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 the
Company's 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. Due to administrative oversight
an answer was not timely filed and a default was entered against the Company in
December 2001. On March 8, 2002, the Michigan Court of Appeals vacated the
trial court's order denying Quicksilver's motion to set aside the default and
remanded the matter to the trial court with instructions to consider the
Company's meritorious defenses along with a motion for reconsideration. The
Company is taking all necessary and appropriate legal action to have the
default set aside and to defend the case.
The Company believes that it has meritorious defenses to the lawsuit and a
legal basis for having the default set aside. The issues in the lawsuit have
not been narrowed and any facts that would support a damage estimate have not
been gathered and analyzed. Therefore, it is not possible to estimate the
damages that could arise from the suit if the proposed class is certified.
Based on information currently available, the Company believes that the final
resolution of this matter will not have a material effect on operations, equity
or cash flows.
13. INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Significant components
of the Company's deferred tax assets and liabilities as of December 31, 2001,
and 2000 and 1999 are as follows:
2001 2000 1999
------- ------- -------
(in thousands)
Deferred tax assets
Deferred tax benefit on cash flow hedge losses. $ 7,252 $ -- $ --
Tax credit sale and unearned income............ 16,494 27,925 3,709
Net operating loss carry forwards.............. 13,650 4,381 4,171
Other.......................................... 355 538 1,556
------- ------- -------
Total deferred tax assets.................. 37,751 32,844 9,436
Deferred tax liabilities..........................
Properties, plant, and equipment............... 88,864 80,592 24,524
------- ------- -------
Net deferred tax liabilities............... $51,113 $47,748 $15,088
======= ======= =======
51
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
The provisions for income taxes for the years ended December 31, 2001, 2000
and 1999 are as follows:
2001 2000 1999
------- ------- -----
(in thousands)
Current state income tax expense...................... $ 272 $ -- $ --
Current federal income tax expense (benefit).......... 178 (33) (934)
Foreign............................................ 13 3 --
------- ------- -----
Total current income tax expense (benefit)..... 463 (30) (934)
------- ------- -----
Deferred federal income tax expense................ 10,364 10,082 936
Foreign income tax expense (benefit)............... (27) 61 --
------- ------- -----
Total deferred income tax expense.............. 10,337 10,143 936
------- ------- -----
Total.......................................... $10,800 $10,113 $ 2
======= ======= =====
A reconciliation of the statutory federal income tax rate and the effective
tax rate for the years ended December 31, 2001, 2000 and 1999 are as follows:
2001 2000 1999
----- ----- ------
U.S. federal statutory tax rate............ 35.00 % 35.00 % 34.00 %
Change in net operating loss carry-forwards -- (0.12)% (33.49)%
Permanent differences...................... .33 % (0.18)% (0.51)%
State income taxes net of federal deduction .59 % -- --
Other...................................... (.05)% 1.77 % --
----- ----- ------
Effective income tax rate.................. 35.87 % 36.47 % 0.00 %
===== ===== ======
Included in deferred tax assets are net operating losses of approximately
$39.0 million that are available for carryover beginning in the year 2002 to
reduce future U.S. taxable income. The net operating losses will begin to
expire in 2004. These net operating losses have not been reduced by a valuation
allowance, because management believes that future taxable income will more
likely than not be sufficient to utilize substantially all of its tax carry
forwards prior to their expirations. However, under Internal Revenue Code
Section 382, a change of ownership was deemed to have occurred for MSR in 1998.
Due to the limitations imposed by Section 382, a portion of MSR's net operating
losses could not be utilized and are not included in deferred tax assets.
14. EMPLOYEE BENEFITS
Quicksilver has a 401(k) retirement plan available to all employees with
three months of service and at least 21 years of age. The Company may make
discretionary contributions to the plan. Company contributions were $180,000,
$451,000 and $51,000 for the years ended December 31, 2001, 2000 and 1999,
respectively.
The Company initiated a self-funded health benefit plan effective July 1,
2001. The plan has been reinsured on an individual claim and total group claim
basis. Quicksilver is responsible for payment of the first $40,000 in claim
expense for each participant. The maximum claim liability for the total group
is approximately $1,050,000 for the plan year ending June 30, 2002. Aggregate
level reinsurance is in place for payment of excess claims up to $1,000,000
over and above the maximum.
52
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
15. STOCKHOLDERS' EQUITY
The Company is authorized to issue 40 million shares of common stock with a
par value per share of one cent ($0.01) and 10 million shares of preferred
stock with a par value per share of one cent ($0.01). At December 31, 2001, the
Company had 18,783,023 shares of common stock outstanding (including 280,169
shares issuable in respect of the MGV exchangeable shares) and one share of
special voting preferred stock outstanding.
Prior to completion of the CMS Acquisition, the Company issued 3,650,000
shares of its common stock to CMS. Those shares were held in escrow and upon
the closing of the acquisition were returned to the Company and are included in
treasury stock.
In connection with the Company's acquisition of properties from Unocal
Corporation's Spirit Energy 76 Unit in May of 1999, 404,381 contingently
issuable unregistered shares of common stock were held in escrow. The Company
released 299,242 shares in 2000. Shares totaling 105,139 were returned to the
Company in 2000 and are included in treasury stock.
As part of the MGV minority interest acquisition, all issued and outstanding
shares of MGV capital stock, other than those held by Quicksilver, were
converted into MGV exchangeable shares. The MGV exchangeable shares are
non-voting shares of MGV's capital stock exchangeable for 283,669 shares of
Quicksilver common shares, which exchange can occur as a result of (i)
liquidation of MGV; (ii) exercise of a redemption right by an MGV shareholder
requiring MGV to purchase exchangeable shares; or (iii) exercise of an exchange
put right by an MGV shareholder requiring Quicksilver to purchase the
exchangeable shares. Any MGV exchangeable shares still outstanding on December
31, 2005 will be treated as having been the subject of an exercise of an
exchange put right on that date. Upon exchange, the holder of exchangeable
shares is entitled to receive one share of Quicksilver common stock and the
full amount of all cash dividends declared on a share of Quicksilver common
stock from the date of issuance of the exchangeable share to the date of
exchange. In order to provide voting rights to holders of MGV exchangeable
shares equivalent to the voting rights of the Quicksilver common shares,
Quicksilver created, on December 15, 2000, a series of its preferred stock
designated as Special Voting Stock. Quicksilver issued a single share of
Special Voting Stock to an appointee. During 2001, 3,500 exchangeable shares of
MGV were presented to Quicksilver for purchase for $59,200.
As of December 31, 2001, the Company had warrants outstanding to sell
430,000 shares of common stock at $12.50 per share, 550,000 shares at $20 per
share, and 5,750 shares at $0.10 per share. These warrants were issued in
connection with the formation of the Company and expire March 31, 2002.
Warrants for 120,000 shares of stock at $ 12.50 per share were exercised in
August 2001. As of March 8, 2002, warrants for 330,000 shares of stock at
$12.50 per share had been exercised in 2002.
Stock Option Plan
On October 4, 1999, the Board of Directors adopted the Company's 1999 Stock
Option and Stock Retention Plan, which was approved at the annual stockholders'
meeting held in June 2000. There are 1.3 million shares of common stock
reserved under the plan, which provides for the grant of incentive stock
options, non-qualified stock options, stock appreciation rights and retention
stock awards.
Under terms of the Plan, options may be granted to officers and employees at
an exercise price that is not less than 100% of the fair market value on the
date of grant, which are exercisable in whole or part by the optionee after at
least one year of continuous service from the date of grant. Incentive stock
options and non-qualified options may not be exercised more than ten years from
date of grant. A summary of stock option
53
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
transactions under the 1999 Plan, including options for 24,856 shares of the
Company's common stock resulting from a conversion of outstanding MSR
Exploration Ltd. options in March of 1999, is as follows:
2001 2000 1999
------------------------ ------------------------ ----------------------
Weighted Weighted Weighted
Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
------- --------------- ------- --------------- ------ ---------------
Outstanding at beginning of year...... 802,059 $ 4.78 24,856 $ 8.75 24,856 $ 8.75
Granted............................ 132,153 13.03 804,203 5.16 -- --
Exercised.......................... (85,425) 4.62 -- -- -- --
Forfeited.......................... (2,700) 8.75 (27,000) 3.69 -- --
------- --------------- ------- --------------- ------ ---------------
Outstanding at end of year............ 846,087 $ 6.58 802,059 $ 4.78 24,856 $ 8.75
======= =============== ======= =============== ====== ===============
Exercisable at end of year............ 196,499 $ 5.88 24,856 $ 8.75 24,856 $ 8.75
======= =============== ======= =============== ====== ===============
Weighted average fair value of options
granted............................. $ 6.77 $ 2.13 NA
=============== =============== ===============
Pro forma information regarding net income and earnings per share is
required by SFAS No. 123, and has been determined as if the Company had
accounted for its employee stock options under the fair value method of that
statement. The fair value of each option grant is estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions:
2001 2000
---- ----
Risk-free interest rate. 3.5% 5.7%
Expected life (in years) 3.5 2.5
Expected volatility..... 60.7% 60.8%
Dividend yield.......... -- --
The following table reflects pro forma net income and earnings per share
under the fair value approach of SFAS No. 123 (in thousands, except per share
amounts):
2001 2000
----------------------- -----------------------
As Reported Pro Forma As Reported Pro Forma
------------ ---------- ------------ ----------
Net income.................. $ 19,310 $ 18,719 $ 17,618 $ 17,188
Basic net income per share.. 1.03 1.00 0.96 0.94
Diluted net income per share 1.00 0.97 0.95 0.93
These pro forma amounts may not be representative of future disclosures
since the estimated fair value of stock options is amortized to expense over
the vesting period, and additional options may be granted in future years.
54
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
The following table summarizes information about stock options outstanding
at December 31, 2001.
Options Outstanding Options Exercisable
-------------------------------------------- ---------------------------
Weighted
Range of Number Average Weighted Number Weighted
Exercisable Outstanding Remaining Average Exercisable Average
Prices at 12/31/01 Contractual Life Exercise Price at 12/31/01 Exercise Price
- ----------- ----------- ---------------- --------------- ----------- ---------------
$ 3-$ 4 370,113 3.1 years $ 3.69 81,978 $ 3.69
7- 8 321,665 3.5 years 7.12 91,665 7.12
8- 9 22,856 .2 years 8.75 22,856 8.75
9- 10 64,152 4.1 years 9.80 -- --
16- 17 67,301 4.8 years 16.11 -- --
----------- ---------------- --------------- ----------- ---------------
846,087 3.6 years $ 6.58 196,499 $ 5.88
=========== ================ =============== =========== ===============
16. OTHER REVENUE
Other revenue consists of the following:
For the Years Ended
December 31,
----------------------
2001 2000 1999
------- ------- ------
(in thousands)
Section 29 tax credit income........ $10,895 $ 8,273 $1,280
Marketing income.................... 3,623 598 224
Processing and transportation income 1,520 604 793
Income (loss) from equity affiliates 1,125 768 (99)
Other............................... 580 145 --
------- ------- ------
$17,743 $10,388 $2,198
======= ======= ======
17. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid (received) for interest and income taxes is as follows:
For the Years Ended
December 31,
-----------------------
2001 2000 1999
------- ------- ------
(in thousands)
Interest.... $22,877 $18,670 $8,190
Income taxes 303 (663) 306
55
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Other non-cash transactions are as follows:
For the Years Ended
December 31,
------------------
2001 2000
---- --------
(in thousands)
Common stock used in acquisitions:
283,669 shares used for minority interest of MGV Energy, Inc.. -- $ 2,309
404,381 shares used for Unocal properties..................... -- 2,221
3,650,000 shares used for CMS Acquisition..................... -- 14,600
Treasury stock reissued (acquired):
15,095 shares for payment of director's compensation.......... $100 $ --
3,650,000 shares from CMS Acquisition......................... -- (14,600)
105,139 shares from Unocal Acquisition........................ -- (1)
18. RELATED PARTY TRANSACTIONS
As of December 31, 2001, the Darden Family has 54.5% beneficial ownership in
Quicksilver including shares owned directly, and shares owned by Mercury
Exploration Company, and Quicksilver Energy L.C., companies that are owned by
the Dardens. Thomas Darden, Glenn Darden and Anne Darden Self are officers and
directors of the Company.
Effective July 1, 2000, Quicksilver purchased the natural gas producing,
gathering, transmission and marketing assets of, and 65% of Voyager Compression
Services, LLC, a gas compression company from, Mercury for $18 million. An
independent appraiser determined the fairness, from a financial point of view,
of the $18 million purchase price and the non-related party members of the
Board of Directors approved the purchase. Mercury continues to own 33% of
Voyager, and Jeff Cook, an officer of the Company, owns 2%.
Quicksilver accounts for its investment in Voyager under the equity method
since control over Voyager is shared equally with Mercury. During 2001,
Quicksilver purchased $8,177,000 of compressors, maintenance and related
services from Voyager at terms as favorable as those granted to third parties.
During 2001, Quicksilver paid $902,000 for principal and interest on the
note payable to Mercury associated with the acquisition of assets from Mercury.
The balance of the note is $2,560,000 at December 31, 2001. Quicksilver and its
associated entities paid $731,000 for rent on buildings, which are owned by a
Mercury affiliate. Rental rates were determined based on comparable rates
charged by third parties.
19. SUPPLEMENTAL INFORMATION (UNAUDITED)
A. Proved Reserves
The following table reflects quantities of proved oil and gas reserves,
based upon a report prepared by Holditch-Reservoir Technologies Consulting
Services, independent petroleum engineers and a subsidiary of Schlumberger. The
reserve report was prepared in accordance with guidelines established by the
Securities and Exchange Commission and, accordingly, was based on existing
economic and operating conditions. Oil and natural gas prices in effect as of
the reserve report date were used without any escalation except in those
instances where the sale of production was covered by contract, in which case
the applicable contract prices, including fixed and determinable escalations,
were used for the duration of the contract, and thereafter the year-end price
was used (See "Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves" below for a
discussion of the effect of the different prices on
56
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
reserve quantities and values.) Operating costs, production and ad valorem
taxes and future development costs were based on current costs with no
escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
Reserves are primarily located in the United States. Canadian reserves are
currently immaterial.
For the Years Ended December 31,
-------------------------------
2001 2000 1999
--------- --------- ---------
Natural gas (Mmcf)
Beginning of year........................... 570,814 192,963 147,226
Revisions of previous estimates............. (43,351) 14,434 17,381
Extensions and discoveries.................. 54,855 17,923 --
Purchases of reserves-in-place.............. 1,893 372,149 44,287
Sales of reserves-in-place.................. -- -- (5)
Production.................................. (32,689) (26,655) (15,926)
--------- --------- ---------
Total proved, end of year............... 551,522 570,814 192,963
========= ========= =========
Proved developed reserves............... 464,964 444,865 135,327
========= ========= =========
Crude oil (Mbbl)
Beginning of year........................... 14,856 15,281 17,983
Revisions of previous estimates............. (455) (787) (4,646)
Purchases of reserves-in-place.............. 2 1,397 2,673
Sales of reserves-in-place.................. -- -- (5)
Production.................................. (1,059) (1,035) (724)
--------- --------- ---------
Total proved, end of year............... 13,344 14,856 15,281
========= ========= =========
Proved developed reserves............... 8,543 9,391 9,954
========= ========= =========
Natural gas liquids (Mbbl)
Beginning of year........................... 1,535 845 996
Revisions of previous estimates............. 197 555 (168)
Purchases of reserves-in-place.............. 1 296 146
Production.................................. (195) (161) (129)
--------- --------- ---------
Total proved, end of year............... 1,538 1,535 845
========= ========= =========
Proved developed reserves............... 1,023 813 838
========= ========= =========
Proved reserves equivalent end of year (Mmcfe):
Natural gas................................. 551,522 570,814 192,963
Crude oil................................... 80,064 89,136 91,686
Natural gas liquids......................... 9,228 9,210 5,070
--------- --------- ---------
Total proved............................ 640,814 669,160 289,719
========= ========= =========
Total proved developed.................. 522,360 506,089 200,078
========= ========= =========
57
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
B. Drilling Activity
The following table sets forth the number of wells attributable to
Quicksilver direct interests drilled.
Years Ended December 31,
---------------------------------
2001 2000 1999
----------- ---------- ----------
Gross Net Gross Net Gross Net
----- ----- ----- ---- ----- ----
DEVELOPMENT WELLS:
Productive..... 198.0 122.6 55.0 35.5 25.0 24.8
Dry............ 1.0 -- -- -- 3.0 2.9
----- ----- ---- ---- ---- ----
Total...... 199.0 122.6 55.0 35.5 28.0 27.7
===== ===== ==== ==== ==== ====
EXPLORATORY WELLS:
Productive..... 89.0 36.1 8.0 2.8 -- --
Dry............ 5.0 4.5 -- -- -- --
----- ----- ---- ---- ---- ----
Total...... 94.0 40.6 8.0 2.8 -- --
===== ===== ==== ==== ==== ====
C. Volumes, Sales Prices and Oil and Gas Production Expense
The following table sets forth certain information regarding the production
and sales volumes and average sales prices and production costs associated with
Quicksilver's producing properties for the periods indicated.
Year Ended December 31,
-----------------------
2001 2000 1999
------- ------- -------
Production:
Natural gas (Mmcf)..................................... 32,689 26,655 15,926
Oil (Mbbl)............................................. 1,059 1,035 724
NGL (Mbbl)............................................. 195 161 129
Total (Mmcfe)...................................... 40,212 33,831 21,044
Weighted average sales price (including impact of hedges):
Natural gas (per Mmcf)................................. $ 3.03 $ 3.04 $ 2.25
Oil (per Mbbl)......................................... 21.03 22.87 14.55
NGL (per Mbbl)......................................... 19.97 25.25 9.93
Production cost (per Mcfe) (1)............................ 1.33 1.11 0.90
- --------
(1) Includes production taxes.
D. Productive Oil and Gas Wells
The following table summarizes the productive oil and gas wells as of
December 31, 2001, attributable to Quicksilver's direct interests.
Gross Net
----- -------
Natural Gas 4,419 1,273.9
Oil........ 597 538.8
----- -------
Total... 5,016 1,812.7
===== =======
58
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
E. Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold
acreage held directly by Quicksilver. Developed acres are defined as acreage
spaced or able to be assigned to productive wells. 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 oil or gas, regardless of whether or
not such acreage contains proved reserves. Gross acres are the total number of
acres in which Quicksilver has a working interest. Net acres are the sum of
Quicksilver's fractional interests owned in the gross acres. States in which
Quicksilver holds undeveloped acreage include Michigan, Montana, Indiana and
Wyoming.
2001 2000 1999
----------------- ----------------- ---------------
Gross Net Gross Net Gross Net
--------- ------- --------- ------- ------- -------
Developed acreage.. 801,461 270,735 594,033 272,484 268,412 132,458
Undeveloped acreage 417,193 333,812 687,472 251,034 368,438 203,825
--------- ------- --------- ------- ------- -------
Total........... 1,218,654 604,547 1,281,505 523,518 636,850 336,283
========= ======= ========= ======= ======= =======
F. Capitalized Exploration and Production Costs
Capitalized exploration and production costs are as follows:
2001 2000
--------- --------
(in thousands)
Proved oil and gas properties......... $ 480,925 $430,328
Unproved oil and gas interests........ 14,458 8,239
Accumulated depletion and depreciation (114,437) (88,079)
--------- --------
$ 380,946 $350,488
========= ========
Unevaluated costs incurred in 2001 include $8,241,000 for the Company's coal
bed methane exploration project in the Alberta province of Canada, which is
expected to be tested and evaluated in 2002. These costs include internal costs
of $481,000 directly related to the project. An additional $1,996,000 was
incurred in 2000 to purchase the minority interest in MGV. The remaining
unevaluated costs are primarily for leasehold acquisitions.
G. Costs Incurred in Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
2001 2000 1999
------- -------- -------
(in thousands)
Acquisition of properties $ 5,749 $167,855 $40,272
Development costs........ 50,202 20,078 9,486
Exploration costs........ 10,103 360 --
------- -------- -------
Total................. $66,054 $188,293 $49,758
======= ======== =======
59
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
H. Results of Operation for Producing Activities
Results of operations from producing activities are set forth below:
2001 2000 1999
-------- -------------- -------
(in thousands)
Oil and gas sales......................................... $125,345 $108,772 $47,616
Operating expense......................................... 53,550 37,574 18,771
Depletion expense......................................... 26,162 22,985 13,315
-------- -------- -------
45,633 48,213 15,530
Income tax expense........................................ 15,973 16,927 5,280
-------- -------- -------
Results of operations from producing activities (excluding
corporate overhead and interests costs)................. $ 29,660 $ 31,286 $10,250
======== ======== =======
I. Standard Measures of Discounted Future Net Cash Flow Relating to Proved Oil
and Gas Reserves
The standardized measure of discounted cash flows relating to oil and gas
reserves are set forth below:
As of December 31,
----------------------------------
2001 2000 1999
---------- ----------- ---------
(in thousands)
Future cash flows....................................... $1,706,300 $ 5,434,874 $ 913,485
Future production and development costs................. (925,891) (1,408,337) (462,822)
Future income tax expense............................... (195,691) (1,323,341) (104,715)
---------- ----------- ---------
Future net cash flows................................... 584,718 2,703,196 345,948
10% annual discount for estimated timing of cash flows.. (315,776) (1,633,904) (141,899)
---------- ----------- ---------
Standardized measure of discounted future net cash flows $ 268,942 $ 1,069,292 $ 204,049
========== =========== =========
An analysis of changes in the standardized measure of discounted future net
cash flow follows:
As of December 31,
--------------------------------
2001 2000 1999
----------- --------- --------
(in thousands)
Net changes in price and production costs.... $(1,289,950) $ 468,720 $ 72,641
Development costs incurred................... 50,202 20,078 9,486
Revision of estimates........................ (11,390) 62,462 (17,089)
Changes in estimated future development costs (44,978) (25,307) (7,196)
Purchase and sale of reserves, net........... 2,015 828,327 61,919
Extensions and discoveries................... 16,699 40,404 --
Net change in income taxes................... 433,461 (464,565) (26,829)
Sales of oil and gas net of production costs. (71,795) (71,560) (26,571)
Accretion of discount........................ 106,929 20,405 12,842
Other........................................ 8,457 (13,721) (3,573)
----------- --------- --------
Net increase (decrease)............... $ (800,350) $ 865,243 $ 75,630
=========== ========= ========
60
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
The Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized
Measure") does not purport to present the fair market value of the Company's
oil and natural gas properties. An estimate of such value should consider,
among other factors, anticipated future prices of oil and natural gas, the
probability of recoveries in excess of existing proved reserves, the value of
probable reserves and acreage prospects, and perhaps different discount rates.
It should be noted that estimates of reserve quantities, especially from new
discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices, adjusted for fixed price contracts but excluding
hedges, to the estimated future production of the year-end reserves. These
prices were adjusted by field for appropriate regional differentials. The
average product prices resulting from such adjustments were $2.66, $8.12 and
$3.15 per Mcfe for 2001, 2000 and 1999, respectively. These prices have varied
widely and have a significant impact on both the quantities and value of the
proved reserves as reduced prices cause wells to reach the end of their
economic life much sooner and also make certain proved undeveloped locations
uneconomical, both of which reduce reserves.
Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the Company's tax basis in the associated
proved oil and natural gas properties. Tax credits and net operating loss carry
forwards were also considered in the future income tax calculation. Future net
cash inflows after income taxes were discounted using a 10% annual discount
rate to arrive at the Standardized Measure.
J. Selected Quarterly Data
Mar 31 Jun 30 Sep 30 Dec 31
------- ------- ------- -------
(In thousands, except per share data)
2001
Operating revenues........................... $43,432 $38,287 $32,228 $29,141
Operating income (1)......................... 20,881 13,649 10,736 7,834
Net income................................... 9,404 5,004 3,120 1,782
Basic net income per share................... 0.51 0.27 0.17 0.09
Diluted net income per share................. 0.50 0.26 0.16 0.09
2000
Operating revenues........................... $15,284 $32,237 $30,784 $40,855
Operating income............................. 4,084 12,828 13,550 18,926
Net income................................... 1,269 3,778 4,767 7,804
Basic net income per share................... 0.07 0.21 0.26 0.43
Diluted net income per share................. 0.07 0.21 0.26 0.42
1999
Operating revenues........................... $ 9,694 $11,606 $14,233 $14,513
Operating income (loss)...................... (799) 2,360 4,086 4,387
Net income (loss)............................ (485) 224 1,011 2,412
Basic and diluted net income (loss) per share (0.04) 0.02 0.08 0.18
- --------
(1) The first and second quarters of 2002 include $760 and $891 of income
related to the settlement of claims in a bankruptcy proceeding for a
customer.
61
ITEM 9. Change in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
ITEM 10. Directors and Executive Officers of the Registrant
The information set forth under Item 1--Election of Directors, in the
Company's proxy statement, for the annual meeting of stockholder's to be held
June 4, 2002 (the "Proxy Statement"), is incorporated herein by reference.
The following information is provided with respect to the executive officers
of the Company.
Name Age Position(s) Held With Quicksilver
- ---- --- ---------------------------------
Thomas F. Darden....... 48 Chairman of the Board
Glenn Darden........... 46 President, Chief Executive Officer and Director
Bill M. Lamkin......... 56 Executive Vice President and Chief Financial Officer
Jeff Cook.............. 45 Senior Vice President--Operations
Houston Kauffman....... 47 Vice President--Manager of Acquisitions, Divestitures & Trades
Robert N. Wagner....... 38 Vice President--Engineering
Anne Darden Self....... 44 Vice President--Human Resources and Director
John B. Gremillion, Jr. 55 Vice President--Investor Relations
Fred van Naerssen...... 60 Vice President and Chief Accounting Officer
D. Wayne Blair......... 45 Vice President and Controller
MarLu Hiller........... 39 Treasurer
The following biographies describe the business experience of our executive
officers.
THOMAS F. DARDEN has served on the Company's Board of Directors since
December 1997. Previously, he served as President of Mercury. While he was
President of Mercury, Mercury developed and acquired interests in over 1,200
producing wells in Michigan, Indiana, Kentucky, Wyoming, Montana, New Mexico
and Texas. A graduate of Tulane University with a BA in Economics in 1975, Mr.
Darden was employed by Mercury or its parent corporation, Mercury Production
Company, for 22 years. He became a director and the President of MSR on March
7, 1997. On January 1, 1998, he was named Chairman of the Board and Chief
Executive Officer of MSR. Mr. Darden became one of the Company's directors and
its President upon Quicksilver's formation in December 1997 and was elected
Chairman of the Board and Chief Executive Officer on March 4, 1999. Mr. Darden
became Chairman of the Board of the Company exclusively in November 1999.
GLENN DARDEN has served on the Company's 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
Corporation. He graduated from Tulane University in 1979 with a BA in Earth
Sciences. 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. Mr. Darden served as Quicksilver's Vice-President until he was elected
President and Chief Operating Officer on March 4, 1999. He became the Chief
Executive Officer of the Company in November 1999.
BILL M. LAMKIN is a Certified Management Accountant and a Certified Cash
Manager with over 20 years of experience in the oil and gas industry. He
graduated from Texas Wesleyan University with a BBA in Accounting in 1968. He
served as Controller/Chief Financial Officer at Whittaker Corporation and
Sargeant Industries, Inc. between 1970 and 1978. He worked as Treasurer,
Controller, and Director of Financial Services at Union Pacific Resources until
he became the Company's Executive Vice President and Chief Financial Officer
when he joined the Company in June 1999.
62
JEFF COOK became the Company's Senior Vice President-Operations in 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 Exploration Company and became Vice President of
Operations in 1991 and Executive Vice President in 1998 before joining
Quicksilver. Mr. Cook graduated from Texas Christian University with a BA in
Business Administration in 1979.
HOUSTON KAUFFMAN is a professional landman having graduated from the
University of Texas in 1978 with a degree in petroleum land management. From
1979 to 1991, he held various staff and supervisory positions with Amoco
Production Company. After receiving his master's degree in business
administration from Houston Baptist University in 1991, he was a land manager
and ultimately land acquisition and divestment manager with CNG Producing
Company. He became manager of business development for Mercury Exploration
Company in 1995, and became Quicksilver's manager of acquisitions, divestments
and trades at Quicksilver's inception in December 1997. On March 4, 1999, Mr.
Kauffman was elected Vice President-Manager of Acquisitions, Divestitures &
Trades, of Quicksilver.
ROBERT N. WAGNER has served as the Company's Vice President-Engineering
since July 1999. From January 1999 to July 1999, he was the Company's 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, Mr.
Wagner was with Mesa, Inc. for over 8 years and served as both drilling
engineer and production engineer. Mr. Wagner received a BS in Petroleum
Engineering from the Colorado School of Mines in Golden, Colorado in 1986.
ANNE DARDEN SELF became Quicksilver's Vice President-Human Resources in
November 2000. She previously held the position of Senior Vice President of
Human Resources for Mercury Exploration Company, where she had worked since
1992. From 1988 to 1991, she was with Banc PLUS Savings 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. She attended Sweet Briar College and graduated from the University
of Texas in Austin in 1980 with a BA in history. Ms. Self was elected as one of
the Company's directors in September 1999.
JOHN B. GREMILLION, JR. has served as the Company's Vice President of
Investor Relations since November 2001. From June 2000 to November 2001, Mr.
Gremillion held the position of Director of Investor Relations. He is a
Certified Public Accountant with over 30 years experience in public and
industry accounting. He was with Arthur Andersen & Co. and Dresser Industries,
Inc. for 12 years before joining Union Pacific Resources in 1981. At Union
Pacific he served in various tax positions and retired from Union Pacific
Corporation in August 1998 as Vice President of Taxes. Mr. Gremillion graduated
from Louisiana State University with a BA in Accounting in 1968.
FRED VAN NAERSSEN is a Certified Public Accountant with over 30 years
experience in public and industry accounting. He was with
PricewaterhouseCoopers for seven years before joining Union Pacific Corporation
in 1973. At Union Pacific he served in various capacities in the financial
field, including 13 years at Union Pacific Resources. Mr. van Naerssen joined
the Company in July 1999 after retiring from Union Pacific Corporation.
D. WAYNE BLAIR is a Certified Public Accountant with over 20 years of
experience in the oil and gas industry. He graduated from Texas A&M University
in 1979 with a BBA in Accounting. Sabine Corporation employed him 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 Quicksilver in April
2000, he was the Controller for Mercury Exploration Company.
63
MARLU HILLER is a Certified Public Accountant with over 15 years of
experience in public and oil and gas accounting. She graduated from Baylor
University with a BBA in Accounting in 1985, and was with Ernst & Young for
three years before joining Union Pacific Resources. At Union Pacific Resources
she served in various capacities, including financial reporting, financial
system implementations, and manager of accounting for Union Pacific Fuels,
which was Union Pacific Resources' marketing company. Ms. Hiller joined
Quicksilver in August of 1999 as Director of Financial Reporting and Planning
and was named Treasurer in May of 2000.
ITEM 11. Executive Compensation
The information set forth under "Executive Compensation" of the Proxy
Statement is incorporated herein by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management
The information set forth under "Security Ownership of Management and
Certain Beneficial Holders" in the Proxy Statement is incorporated herein by
reference.
ITEM 13. Certain Relationships and Related Transactions
The information set forth under "Transactions with Management and Certain
Stockholders" in the Proxy Statement is incorporated herein by reference.
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements:
The following financial statements of the Company and the Report of
the Company's Independent Public Accountants thereon are included on
pages 33 through 61 of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 2001 and 2000
Consolidated Statement of Incomes for the years ended December 31,
2001, 2000 and 1999
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 2001, 2000 and 1999
Consolidated Statements of Cash Flows for the years ended December
31, 2001, 2000 and 1999
Notes to the Consolidated Financial Statements
2. Financial Statement Schedules:
[All schedules are omitted because the required information is
inapplicable or the information is presented in the Financial
Statements or the notes thereto.]
64
(c) Exhibits:
Exhibit No. Sequential Description
- ----------- ----------------------
2.1 Purchase and Sale Agreement, dated March 4, 2000, between CMS Oil and Gas Company and Quicksilver
Resources Inc. (filed as Exhibit 2.1 to the Company's Form 8-K filed April 14, 2000 and included herein by
reference).
3.1 Restated Certificate of Incorporation of Quicksilver Resources Inc. (filed as Exhibit 4.1 to the Company's Form
S-4 File No. 333-66709, filed November 3, 1998 and included herein by reference).
3.2 Certificate of Designation, Preferences and Rights of Preferred Stock (filed as Exhibit 3.2 to the Company's
Form 10-K filed March 27, 2001 and included herein by reference).
3.3 Certificate of Amendment to the Restated Certificate of Incorporation of Quicksilver Resources Inc. (filed as
Exhibit 3.1 to the Company's Form 10-Q filed August 14, 2001 and included herein by reference).
3.4 Bylaws of Quicksilver Resources Inc. (filed as Exhibit 4.2 to the Company's Form S-4 File No. 333-66709,
filed November 3, 1998 and included herein by reference).
3.5 Amendment to Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.4 to the Company's Form 10-K filed
March 27, 2001 and included herein by reference).
3.6 Amendment to the Bylaws of Quicksilver Resources Inc., adopted June 5, 2001 (filed as Exhibit 3.2 to the
Company's Form 10-Q filed August 14, 2001 and included herein by reference.)
4.1 Form of Quicksilver Resources Inc. Common Stock Certificate (filed as Exhibit 4.3 to the Company's
Form S-4/A File No. 333-66709, filed January 20, 1999 and included herein by reference).
4.2 Note Purchase Agreement, dated March 31, 2000, between the Company and the Purchasers identified therein
(filed as Exhibit 4.1 to the Company's Form 8-K filed April 14, 2000 and included herein by reference).
10.1 Master Gas Purchase and Sale Agreement, dated March 1, 1999 by and between Quicksilver Resources Inc. and
Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company's Form S-1 File No. 333-89229, filed
October 18, 1999 and included herein by reference).
10.2 Wells Agreement, (filed as an exhibit to the Registration Statement on Form S-4 File No. 333-29769, and
included herein by reference).
10.3 Purchase and Sale Agreement, dated March 31, 1999, between Union Oil Company of California and
Quicksilver Resources Inc. (filed as Exhibit 2.1 to the Company's Form 8-K File No. 001-14837, filed May 28,
1999 and included herein by reference).
10.4 Amendment to Purchase and Sale Agreement, dated May 17, 1999, between Union Oil Company of California
and Quicksilver Resources Inc. (filed as Exhibit 2.2 to the Company's Form 8-K File No. 001-14837, filed
May 28, 1999 and included herein by reference).
+10.5 Quicksilver Resources 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.28 to the Company's
Form S-1 File No. 333-89229, filed October 18, 1999 and included herein by reference).
10.6 Third Amended and Restated Credit Agreement, dated as of March 31, 2000, among Quicksilver Resources
Inc., as Borrower, Bank of America, N.A., as Administrative Agent, and the financial institutions listed on
Schedule 1 thereto (filed as Exhibit 10.1 to the Company's Form 10-Q filed May 15, 2000 and included herein
by reference).
10.7 First Amendment to Third Amended and Restated Credit Agreement, dated effective as of April 24, 2000,
among the parties described in Exhibit 10.6 above (filed as Exhibit 10.2 to the Company's Form 10-Q filed
May 15, 2000 and included herein by reference).
10.8 Second Amendment to Third Amended and Restated Credit Agreement, dated effective as of August 31, 2000,
among the parties described in Exhibit 10.6 above (filed as Exhibit 10.8 to the Company's Form 10-K filed
March 27, 2001 and included herein by reference).
10.9 Third Amendment to Third Amended and Restated Credit Agreement, dated effective as of November 30,
2000, among the parties described in Exhibit 10.6 above (filed as Exhibit 10.9 to the Company's Form 10-K
filed March 27, 2001).
10.10 Amended and Restated Purchase and Sale Agreement, dated as of March 31, 2000, between Quicksilver
Resources Inc., as Seller, and Mariner Gas LLC, as Buyer (filed as Exhibit 10.3 to the Company's Form 10-Q
filed May 15, 2000 and included herein by reference).
10.11 Agency Agreement, dated November 30, 2000, for the sales of up to 1,340,405 shares of Common Stock of the
Company (filed as Exhibit 10.11 to the Company's Form 10-K filed March 27, 2001 and included herein by
reference).
10.12 Agency Agreement, dated November 30, 2000, for the sales of up to 299,242 shares of Common Stock of the
Company (filed as Exhibit 10.12 to the Company's Form 10-K filed March 27, 2001 and included herein by
reference).
*21.1 List of subsidiaries of Quicksilver Resources Inc.
*23.1 Consent of Deloitte & Touche LLP
*23.2 Consent of Holditch-Resevoir Technologies Consulting Services
- --------
* Filed herewith
+ Identifies management contracts and compensatory plans or arrangements.
Reports on Form 8-K
No Form 8-K was filed in the last reporting period covered by this Form 10-K.
65
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
QUICKSILVER RESOURCES INC.
(the "Registrant")
By: /s/ GLENN DARDEN
-----------------------------
Glenn Darden
President and Chief Executive
Officer
Dated: March 25, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, the
following persons on behalf of the Registrant and in the capacities and on the
dates indicated have signed this report below.
Signature Title Date
--------- ----- ----
/S/ THOMAS F. DARDEN Chairman of the Board March 25, 2002
- -----------------------------
Thomas F. Darden
/S/ GLENN DARDEN President, Chief Executive March 25, 2002
- ----------------------------- Officer And Director
Glenn Darden
/S/ BILL LAMKIN Executive Vice-President And March 25, 2002
- ----------------------------- Chief Financial Officer
Bill Lamkin
/s/ FRED VAN NAERSSEN Vice-President And Chief March 25 2002
- ----------------------------- Accounting Officer
Fred van Naerssen
/S/ ANNE DARDEN SELF Vice-President--Human March 25, 2002
- ----------------------------- Resources And Director
Anne Darden Self
/S/ JAMES A. HUGHES Director March 25, 2002
- -----------------------------
James A. Hughes
/S/ D. RANDALL KENT Director March 25, 2002
- -----------------------------
D. Randall Kent
/S/ STEVEN M. MORRIS Director March 25, 2002
- -----------------------------
Steven M. Morris
/S/ W. YANDELL ROGERS, III Director March 25, 2002
- -----------------------------
W. Yandell Rogers, III
/S/ MARK WARNER Director March 25, 2002
- -----------------------------
Mark Warner
66