UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
[ ] 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: 333-61547
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Oklahoma 73-0767549
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
302 N. Independence, Enid, Oklahoma 73701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (580) 233-8955
Securities registered pursuant to Section 12 (b) of the Act: None
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 [ ] No [X]
The Registrant is not subject to the filing requirements of Section 13 and 15(d)
of the Securities Exchange Act of 1934, but files reports required by those
sections pursuant to contractual obligation requirements.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (229.405 of this chapter) 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.[X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act.) Yes [ ] No [X]
As of March 28, 2003, there were 14,368,919 shares of the registrant's common
stock, par value $.01 per share, outstanding. The common stock is privately held
by affiliates of the registrant.
Document incorporated by reference: None
CONTINENTAL RESOURCES, INC.
Annual Report on Form 10-K
for the Year Ended December 31, 2002
TABLE OF CONTENTS
PART I
ITEM 1. BUSIESS ..........................................................3
ITEM 2. PROPERTIES ......................................................14
ITEM 3. LEGAL PROCEEDINGS ...............................................22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .............22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS..........................................................22
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA ...........................22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS .......................................24
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ......30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .....................32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE ........................................32
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ..............32
ITEM 11. EXECUTIVE COMPENSATION ..........................................34
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...35
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ..................36
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.37
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain of the statements under this Item and elsewhere in this Form 10-K
are "forward-looking statements" within the meaning of Section 27A of the
Securities Act and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of
historical facts included in this Form 10-K, including without limitation
statements under "Item 1. Business," "Item 2. Properties" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" regarding budgeted capital expenditures, increases in oil and
gas production, the Company's financial position, oil and gas reserve
estimates, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes
that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to
have been correct. There are numerous uncertainties inherent in estimating
quantities of proved oil and natural gas reserves and in projecting future
rates of production and timing of development expenditures, including many
factors beyond the control of the Company. Reserve engineering is a
subjective process of estimating underground accumulation of oil and
natural gas that cannot be measured in an exact way, and the accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result,
estimates made by different engineers often vary from one another. In
addition, results of drilling, testing and production subsequent to the
date of an estimate may justify revisions of such estimates and such
revisions, if significant, would change the schedule of any further
production and development drilling. Accordingly, reserve estimates are
generally different from the quantities of oil and natural gas that are
ultimately recovered. Additional important factors that could cause actual
results to differ materially from the Company's expectations are disclosed
under "Risk Factors" and elsewhere in this Form 10-K. Should one or more of
these risks or uncertainties occur, or should underlying assumptions prove
incorrect, the Company's actual results and plan for 2003 and beyond could
differ materially from those expressed in forward-looking statements. All
subsequent written and oral forward-looking statements to the Company or
persons acting on its behalf are expressly qualified in their entirety by
such factors.
ITEM 1. BUSINESS
OVERVIEW
Continental Resources, Inc. and its subsidiaries, Continental Gas, Inc.
("CGI"), Continental Resources of Illinois, Inc. ("CRII") and Continental Crude
Co. ("CCC") (collectively "Continental" or the "Company"), are engaged in the
exploration, exploitation, development and acquisition of oil and gas reserves,
primarily in the Rocky Mountain and Mid-Continent regions of the United States,
and to a lesser but growing extent, in the Gulf Coast region of Texas and
Louisiana. In addition to its exploration, development, exploitation and
acquisition activities, the Company currently owns and operates 700 miles of
natural gas pipelines, eight gas gathering systems and three gas processing
plants in its operating areas. The Company also engages in natural gas
marketing, gas pipeline construction and saltwater disposal. Capitalizing on its
growth through the drill-bit and its acquisition strategy, the Company has
increased its estimated proved reserves from 26.6 million barrels of oil
equivalent ("MMBoe") in 1995 to 74.9 MMBoe at year-end 2002, and has increased
its annual production from 2.2 MMBoe in 1995 to 5.4 MMBoe in 2002. As of
December 31, 2002, the Company's reserves had a present value of estimated
future net revenues, discounted at 10% ("PV-10") of $633.4 million calculated in
accordance with the Securities and Exchange Commission (the "Commission" or
"SEC") guidelines. At that date, approximately 84% of the Company's estimated
proved reserves were oil and approximately 60% of its total estimated reserves
were classified as proved developed. At December 31, 2002, the Company had
interests in 2,385 producing wells of which it operated 1,823. The Company was
originally formed in 1967 to explore, develop and produce oil and gas in
Oklahoma. Through 1993 the Company's activities and growth remained focused
primarily in Oklahoma. In 1993, the Company expanded its activity into the Rocky
Mountain and Gulf Coast regions. Through drilling success and strategic
acquisitions, 83% of the Company's estimated proved reserves as of December 31,
2002 are now found in the Rocky Mountain region. The Company's growth in the
Gulf Coast region during the mid-1990's was slowed due to the rapid growth of
the Rocky Mountain region. Since 1999, drilling activity has increased in the
Gulf Coast region and it is expected to be another core operating area for the
Company. To further expand its Mid-Continent operations, the Company acquired
Mt. Vernon, Illinois-based Farrar Oil Company in 2001. Farrar has been a long
time partner with the Company and provides the assets and experienced personnel
from which the Company can expand its operations into the Illinois and
Appalachian basins of the eastern United States.
BUSINESS STRATEGY
The Company's business strategy is to increase production, cash flow and
reserves through the exploration, development, exploitation and acquisition of
properties in the Company's core operating areas. The Company seeks to increase
production and cash flow, and develop additional reserves by drilling new wells
(including horizontal wells), secondary recovery operations, workovers,
recompletions of existing wells and the application of other techniques designed
to increase production. The Company's acquisition strategy includes seeking
properties that have an established production history, have undeveloped reserve
potential, and through use of the Company's technical expertise in horizontal
drilling and secondary recovery, allow the Company to maximize the utilization
of its infrastructure in core operating areas. The Company's exploration
strategy is designed to combine the knowledge of its professional staff with the
competitive and technical strengths of the Company to pursue new field
discoveries in areas that may be out of favor or overlooked. This strategy
enables the Company to build a controlling lease position in targeted projects
and to realize the full benefit of any project success. The Company tries to
maintain an inventory of three or four new exploratory projects at all times for
future growth and development. On an ongoing basis, the Company evaluates and
considers divesting of oil and gas properties considered to be non-core to the
Company's reserve growth plans with the goal that all Company assets are
contributing to its long-term strategic plan.
PROPERTY OVERVIEW
Rocky Mountain Region. The Company's Rocky Mountain properties are
concentrated in the North Dakota, South Dakota and Montana portions of the
Williston Basin, and in the Big Horn Basin in Wyoming. These properties
represented 83% of the Company's estimated proved reserves and 76% of the PV-10
of the Company's proved reserves as of December 31, 2002. The Company owns
approximately 465,000 net leasehold acres, has interests in 710 gross (615 net)
producing wells, is the operator of 93% of these wells, and has identified 86
potential drilling locations in the Rocky Mountain region.
The Williston Basin properties represented 74% of the Company's estimated
proved reserves and 70% of the PV-10 of its proved reserves at December 31,
2002. In the Williston Basin, the Company owns approximately 369,000 net
leasehold acres, has interests in 381 gross (328 net) producing wells and has
identified 86 potential drilling locations. The Company's principal properties
in the Williston Basin include eight high-pressure air injections, or HPAI,
secondary recovery units located in the Cedar Hills, Medicine Pole Hills and
Buffalo Fields. The Company's extensive experience has demonstrated that its
secondary recovery methods have increased the reserves recovered from existing
fields by 200% to 300% through the injection and withdrawal of fluids or gases.
The combination of injection and withdrawal recovers additional oil from the
reservoir that cannot be recovered by primary recovery methods. The Buffalo
Field units are the oldest of the Company's secondary recovery projects and have
been in operations since 1978. The Cedar Hills Field units are the most recent
and largest of the Company's secondary recovery units representing approximately
59% of the proved reserves and 58% of the PV-10 attributable to the Company's
proved reserves at December 31, 2002. Combined, the Company's eight HPAI
secondary recovery projects represent 80% of the HPAI projects in North America.
In the Big Horn Basin, the Company's properties are focused in and around
the Worland Field. The Worland Field represents 9% of the Company's estimated
proved reserves and 6% of the PV-10 of the Company's proved reserves at December
31, 2002. In the Worland Field, the Company owns approximately 96,000 net
leasehold acres and has interests in 329 gross (287 net) producing wells, of
which the Company operates 303. In the Worland Field, the Company has identified
70 potential workovers or recompletions and has initiated three pilot secondary
recovery projects to increase recovery of known oil in the field.
Mid-Continent Region. The Company's Mid-Continent properties are located
primarily in the Anadarko Basin of western Oklahoma, southwestern Kansas,
Illinois, and in the Texas Panhandle. At December 31, 2002, the Company's
estimated proved reserves in the Mid-Continent region represented 16% of the
Company's total estimated proved reserves, 66% of the Company's natural gas
reserves and 22% of the Company's PV-10. In the Mid-Continent region, the
Company owns approximately 162,000 net leasehold acres, has interests in 1,574
gross (956 net) producing wells and has identified 32 potential drilling
locations. The Company operates 68% of the gross wells in which it has
interests.
Gulf Coast Region. The Company's Gulf Coast properties are located
primarily onshore, along the Texas and Louisiana coasts, and include the Pebble
Beach and Luby projects in Nueces County, Texas and the Jefferson Island project
in Iberia Parish, Louisiana. The Company also participates in Gulf of Mexico
drilling ventures as part of the Company's ongoing expansion in the Gulf Coast
region. During 2002, the Company's Gulf Coast producing wells represented only
4% of the Company's total producing well count, but produced 21% of the
Company's total gas production for the year. As of December 31, 2002, the
Company's Gulf Coast properties represented 1% of the Company's total estimated
proved reserves, 4% of its estimated proved gas reserves and 2% PV-10 of the
Company's proved reserves. In the Gulf Coast, the Company owns approximately
24,000 net leasehold acres; has interests in 101 gross (83 net) producing wells
and has identified 53 potential drilling locations from 95 square miles of
proprietary 3-D data and several hundred miles of non-proprietary 2-D and 3-D
seismic data. The Company operates 79% of the gross wells in which it has
interests.
OTHER INFORMATION
The Company's subsidiary, Continental Gas, Inc., was formed as a gas
marketing company in April 1990. Currently, Continental Gas, Inc. specializes in
gas marketing, pipeline construction, gas gathering systems and gas plant
operations. On June 19, 2001, the Company formed a new subsidiary, Continental
Resources of Illinois, Inc., or CRII. On July 9, 2001, the Company, through
CRII, purchased the assets of Farrar Oil Company and Har-Ken Oil Company, oil
and gas operating companies in Illinois and Kentucky, respectively. The
Company's remaining subsidiary, Continental Crude Co., has been inactive since
its formation in 1998.
Continental Resources, Inc. and its subsidiaries are headquartered in Enid,
Oklahoma, and Mt. Vernon, Illinois, with additional offices in Baker, Montana;
Buffalo, South Dakota; and field offices located within its various operating
areas.
BUSINESS STRENGTHS
The Company believes that it has certain strengths that provide it with
competitive advantages and provide it with diversified growth opportunities,
including the following:
PROVEN GROWTH RECORD. The Company has demonstrated consistent growth
through a balanced program of development, exploitation and exploratory drilling
and acquisitions. The Company has increased its proved reserves 182% from 26.6
MMBoe in 1995 to 74.9 MMBoe as of December 31, 2002.
SUBSTANTIAL AND DIVERSIFIED DRILLING INVENTORY. The Company is active in
seven different geologic basins in 11 states and has identified more than 171
potential drilling locations based on geological and geophysical evaluations. As
of December 31, 2002, the Company held approximately 651,000 net acres, of which
approximately 57% were classified as undeveloped. Management believes that its
current inventory and acreage holdings could support three to five years of
drilling activities depending upon oil and gas prices.
LONG-LIFE NATURE OF RESERVES. The Company's producing reserves are
primarily characterized by relatively stable, mature production that is subject
to gradual decline rates. As a result of the long-lived nature of its
properties, the Company has relatively low reinvestment requirements to maintain
reserve quantities and primary and secondary production levels. The Company's
properties have an average reserve life of approximately 14 years.
SUCCESSFUL DRILLING AND ACQUISITION RECORD. The Company has maintained a
successful drilling record. During the five years ended December 31, 2002, the
Company participated in 239 gross wells of which 83% were completed as
producers. During this time, reserves added from drilling, workovers and related
activities totaled 34.4 MMBoe of proved developed reserves at an average finding
cost of $7.36 per barrel of oil equivalent ("Boe"). During 2002, the Company
spent $57.0 million on the development of the Cedar Hills field. $32.4 million
was spent drilling injection wells and $24.6 million was spent on
infrastructure, including compressors and pipelines, which resulted in no
additional reserves in 2002. Excluding these costs, our 5year average finding
cost would be $5.71. During the same period, the Company acquired 21.2 MMBoe at
an average cost of $4.60 per Boe. Including major revisions of 12.0 MMBoe due
primarily to fluctuating prices, the Company added a total of 67.7 MMBoe at an
average cost of $5.19 per Boe during the last five years.
SIGNIFICANT OPERATIONAL CONTROL. Approximately 97.4% of the Company's PV-10
at December 31, 2002, was attributable to wells operated by the Company, giving
Continental significant control over the amount and timing of capital
expenditures and production, operating and marketing activities.
TECHNOLOGICAL LEADERSHIP. The Company has demonstrated significant
expertise in the continually evolving technologies of 3-D seismic, directional
drilling, and precision horizontal drilling, and is among the few companies in
North America to successfully utilize high pressure air injection enhanced
recovery technology on a large scale. Through the use of precision horizontal
drilling the Company has experienced a 400% to 700% increase in initial flow
rates. From inception, the Company has drilled 243 horizontal wells in the Rocky
Mountains and Mid-Continent regions. Through the combination of precision
horizontal drilling and secondary recovery technology, the Company has
significantly enhanced the recoverable reserves underlying its oil and gas
properties. Since its inception, Continental has experienced a 300% to 400%
increase in recoverable reserves through use of these technologies.
EXPERIENCED AND COMMITTED MANAGEMENT. Continental's senior management team
has extensive expertise in the oil and gas industry. The Company's Chief
Executive Officer, Harold Hamm, began his career in the oil and gas industry in
1967. Eight senior officers have an average of 24 years of oil and gas industry
experience. Additionally, the Company's technical staff, which includes 14
petroleum engineers and 11 geoscientists, have an average of more than 25 years
experience in the industry.
DEVELOPMENT, EXPLORATION AND EXPLOITATION ACTIVITIES
CAPITAL EXPENDITURES. The Company's projected capital expenditures for
development, exploitation and exploration activities in 2003 total $105.9
million. Approximately $74.0 million (69%) is targeted for drilling, $8.3
million (8%) for lease acquisitions and seismic, $4.0 million (4%) for workovers
and recompletions, $3.3 million (3%) for acquisitions, and $16.4 million (16%)
for secondary recovery projects and facilities. Funding for these expenditures
will come from a combination of cash flow and the Company's credit facility.
Top priority will be given to completing installation of secondary recovery
facilities at the Cedar Hills Field by year-end 2003. This will account for
$52.6 million or 50% of the Company's projected capital expenditures for 2003.
This includes $40.2 million for drilling injector wells and $12.4 million for
compressors, equipment and facilities. Approximately $33.8 million will be spent
on development and exploration drilling outside of the Cedar Hills unit.
Expenditures on projects outside of Cedar Hills are discretionary and may vary
from projections in response to commodity prices and available cash flow.
DEVELOPMENT AND EXPLOITATION. The Company's development and exploitation
activities are designed to maximize the value of existing properties. Activities
include the drilling of vertical, directional and horizontal development wells,
workover and recompletions in existing wellbores, and secondary recovery water
flood and HPAI projects. During 2003, the Company expects to invest $52.0
million drilling 59 development-drilling projects, representing 70% of the
Company's total 2003 drilling budget. Within the development drilling budget,
77% will be spent drilling injector wells within the Cedar Hills units, 5% on
other projects in the Williston and Big Horn Basins, 10% in the Gulf Coast
region and 8% in the Mid-Continent region. The Company also expects to invest
$4.0 million during 2003 on workovers and recompletions, $3.3 million for
acquisitions, and $16.4 million on secondary recovery projects and related
facilities.
EXPLORATION ACTIVITIES. The Company's exploration projects are designed to
locate new reserves and fields for future growth and development. The Company's
exploration projects vary in risk and reward based on their depth, location and
geology. The Company routinely uses the latest in technology, including 3-D
seismic, horizontal drilling and new completion technologies to enhance its
projects. The Company will continue to build exploratory inventory throughout
the year for future drilling.
The Company will initiate, on a priority basis, as many projects as cash
flow prudently justifies. The Company anticipates investing $21.9 million
drilling 36 exploratory projects during 2003, representing 30% of the Company's
total 2003 drilling budget with 14% to be spent in the Mid-Continent region, 50%
in the Rocky Mountain region and 36% in the Gulf Coast region.
The following table summarizes the number of projects Continental expects
to complete in 2003.
Drilling Secondary 3-D
Locations Workovers Recovery Seismic TOTAL
-------------------- ----------------- ------------------ ------------ ----------
DEVELOPMENT
MID CONTINENT
Anadarko 10 14 0 0 24
Black Warrior 0 0 0 0 0
Illinois 3 32 3 0 38
-------------------------------------------------------------------------------------
Total 13 46 3 0 62
ROCKY MOUNTAIN
Williston 2 2 4 0 8
Cedar Hills 37 10 0 0 47
Big Horn 0 10 3 0 13
-------------------------------------------------------------------------------------
Total 39 22 7 0 68
GULF COAST
Texas 7 0 0 0 7
Louisiana 0 0 0 0 0
Gulf of Mexico 0 0 0 0 0
-------------------------------------------------------------------------------------
Total 7 0 0 0 7
TOTAL DEV 59 68 10 0 137
=====================================================================================
EXPLORATORY
MID CONTINENT
Anadarko 1 0 0 1 2
Black Warrior 5 0 0 3 8
Illinois 10 0 0 3 13
-------------------------------------------------------------------------------------
Total 16 0 0 7 23
ROCKY MOUNTAIN
Williston 11 0 0 8 19
Cedar Hills 0 0 0 0 0
Big Horn 0 0 0 0 0
-------------------------------------------------------------------------------------
Total 11 0 0 8 19
GULF COAST
Texas 6 0 0 2 8
Louisiana 1 0 0 1 2
Gulf of Mexico 2 0 0 3 5
-------------------------------------------------------------------------------------
Total 9 0 0 6 15
TOTAL EXPL 36 0 0 21 57
=====================================================================================
GRAND TOTAL 95 68 10 21 194
=====================================================================================
ACQUISITION ACTIVITIES
The Company seeks to acquire properties, which have the potential to be
immediately positive to cash flow, have long-lived, lower risk, relatively
stable production potential, and provide long-term growth in production and
reserves. The Company focuses on acquisitions that complement its existing
exploration program, provide opportunities to utilize the Company's
technological advantages, have the potential for enhanced recovery activities,
and/or provide new core areas for the Company's operations.
RISK FACTORS
VOLATILITY OF OIL AND GAS PRICES
The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil, gas and natural gas
liquids, which are dependent upon numerous factors such as weather, economic,
political and regulatory developments and competition from other sources of
energy. The Company is affected more by fluctuations in oil prices than natural
gas prices, because a majority of its production is oil. The volatile nature of
the energy markets and the unpredictability of actions of OPEC members makes it
particularly difficult to estimate future prices of oil, gas and natural gas
liquids. Prices of oil and gas and natural gas liquids are subject to wide
fluctuations in response to relatively minor changes in circumstances, and there
can be no assurance that future prolonged decreases in such prices will not
occur. All of these factors are beyond the control of the Company. Any
significant decline in oil and, to a lesser extent, in natural gas prices would
have a material adverse effect on the Company's results of operations and
financial condition. Although the Company may enter into price risk management
arrangements from time to time to reduce its exposure to price risks in the sale
of its oil and gas, the Company's price risk management arrangements are likely
to apply to only a portion of its production and provide only limited price
protection against fluctuations in the oil and gas markets. See more discussion
in "Management's Discussion and Analysis of Financial Condition and Results of
Operations".
REPLACEMENTS OF RESERVES
The Company's future success depends upon its ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable.
Unless the Company successfully replaces the reserves that it produces (through
successful development, exploration or acquisition), the Company's proved
reserves would decline. There can be no assurance that the Company will continue
to be successful in its effort to increase or replace its proved reserves. To
the extent the Company is unsuccessful in replacing or expanding its estimated
proved reserves, the Company may be unable to pay the principal of and interest
on its Senior Subordinated Notes (the "Notes") and other indebtedness in
accordance with their terms, or otherwise to satisfy certain of the covenants
contained in the indenture governing its Notes (the "Indenture") and the terms
of its other indebtedness.
UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES AND FUTURE NET CASH FLOWS
This report contains estimates of the Company's oil and gas reserves and
the future net cash flows from those reserves, which have been prepared by the
Company and certain independent petroleum consultants. Reserve engineering is a
subjective process of estimating the recovery from underground accumulations of
oil and gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. There are numerous
uncertainties inherent in estimating quantities and future values of proved oil
and gas reserves, including many factors beyond the control of the Company. Each
of the estimates of proved oil and gas reserves, future net cash flows and
discounted present values rely upon various assumptions, including assumptions
required by the Commission as to constant oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
process of estimating oil and gas reserves in complex, requiring significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. As a result, such
estimates are inherently imprecise. Actual future production, oil and gas
prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and gas reserves may vary substantially from those
estimated in the report. Any significant variance in these assumptions could
materially affect the estimated quantity and value of reserves set forth in this
annual report on Form 10-K. In addition, the Company's reserves may be subject
to downward or upward revision, based upon production history, results of future
exploration and development, prevailing oil and gas prices and other factors,
many of which are beyond the Company's control. The PV-10 of the Company's
proved oil and gas reserves does not necessarily represent the current or fair
market value of such proved reserves, and the 10% discount rate required by the
Commission may not reflect current interest rates, the Company's cost of capital
or any risks associated with the development and production of the Company's
proved oil and gas reserves. At December 31, 2002, the estimated future net cash
flow of $1,304 million and PV-10 of $633.4 million attributable to the Company's
proved oil and gas reserves are based on prices in effect at the date ($29.04
per barrel ("Bbl") of oil and $3.33 per thousand cubic feet ("Mcf") of natural
gas), which may be materially different from actual future prices.
PROPERTY ACQUISITION RISKS
The Company's growth strategy includes the acquisition of oil and gas
properties. There can be no assurance, however, that the Company will be able to
identify attractive acquisition opportunities, obtain financing for acquisitions
on satisfactory terms or successfully acquire identified targets. In addition,
no assurance can be given that the Company will be successful in integration
acquired business into its existing operations, and such integration may result
in unforeseen operational difficulties or require a disproportionate amount of
management's attention. Future acquisitions may be financed through the
incurrence of additional indebtedness to the extent permitted under the
Indenture or through the issuance of capital stock. Furthermore, there can be no
assurance that competition for acquisition opportunities in these industries
will not escalate, thereby increasing the cost to the Company or making further
acquisitions or causing the Company to refrain from making additional
acquisitions.
The Company is subject to risks that properties acquired by it will not
perform as expected and that the returns from such properties will not support
the indebtedness incurred or the other consideration used to acquire, or the
capital expenditures needed to develop, the properties. In addition, expansion
of the Company's operations may place a significant strain on the Company's
management, financial and other resources. The Company's ability to manage
future growth will depend upon its ability to monitor operations, maintain
effective cost and other controls and significantly expand the Company's
internal management, technical and accounting systems, all of which will result
in higher operating expenses. Any failure to expend these areas and to implement
and improve such systems, procedures and controls in an efficient manner at a
pace consistent with the growth of the Company's business could have a material
adverse effect on the Company's business, financial condition and results of
operations. In addition, the integration of acquired properties with existing
operations will entail considerable expenses in advance of anticipated revenues
and may cause substantial fluctuations in the Company's operating results. There
can be no assurance that the Company will be able to successfully integrate the
properties acquired and to be acquired or any other businesses it may acquire.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and will continue to make, substantial capital
expenditures in connection with the acquisition, development, exploitation,
exploration and production of its oil and gas properties. Historically, the
Company has funded its capital expenditures through borrowings from banks and
from its principal stockholder, and cash flow from operations. Future cash flows
and the availability of credit are subject to a number of variables, such as the
level of production from existing wells, borrowing base determinations, prices
of oil and gas and the Company's success in locating and producing new oil and
gas reserves. If revenues were to decrease as a result of lower oil and gas
prices, decreased production or otherwise, and the Company had not availability
under its bank credit facility (the "Credit Facility") or other sources of
borrowings, the Company could have limited ability to replace its oil and gas
reserves or to maintain production at current levels, resulting in a decrease in
production and revenues over time. If the Company's cash flow from operations
and availability under the Credit Facility are not sufficient to satisfy its
capital expenditure requirements, there can be no assurance that additional debt
or equity financing will be available.
EFFECTS OF LEVERAGE
At December 31, 2002, on a consolidated basis, the Company and the
Subsidiary Guarantors (defined below) had $247.1 million in indebtedness
(including short-term indebtedness and current maturities of long-term
indebtedness) compared to the Company's stockholder's equity of $115.0 million.
Although the Company's cash flow from operations has been sufficient to meet its
debt service obligations in the past, there can be no assurance that the
Company's operating results will continue to be sufficient for the Company to
meet its obligations. See "Selected Financial and Operating Data" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
The degree to which the Company is leveraged could have important
consequences to the holders of the Notes. The potential consequences could
include:
o The Company's ability to obtain additional financing for acquisitions,
capital expenditures, working capital or general corporate purposes
may be impaired in the future;
o A substantial portion of the Company's cash flow from operations must
be dedicated to the payment of principal of and interest on the Notes
and the borrowings under the Credit Facility, thereby reducing funds
available to the Company for its operations and other purposes;
o Certain of the Company's borrowings are and will continue to be at
variable rates of interest, which expose the Company to the risk
increased interest rates;
o Indebtedness outstanding under the Credit Facility is senior in right
of payment to the Notes, is secured by substantially all of the
Company's proved reserves and certain other assets, and will mature
prior to the Notes; and
o The Company may be substantially more leveraged than certain of its
competitors, which may place it a relative competitive disadvantage
and make it more vulnerable to change market conditions and
regulations.
The Company's ability to make scheduled payments or to refinance its
obligations with respect to its indebtedness will depend on its financial and
operating performance, which, in turn, is subject to the volatility of oil and
gas prices, production levels, prevailing economic conditions and to certain
financial, business and other factors beyond its control. If the Company's cash
flow and capital resources are insufficient to fund its debt service
obligations, the Company may be forced to sell assets, obtain additional debt or
equity financing or restructure its debt. Even if additional financing could be
obtained, there can be no assurance that it would be on terms that are favorable
or acceptable to the Company. There can be no assurance that the Company's cash
flow and capital resources will be sufficient to pay its indebtedness in the
future. In the absence of such operating results and resources, the Company
could face substantial liquidity problems and might be required to dispose of
material assets or operations to meet debt service and other obligations, and
there can be no assurance as to the timing of such sales or the adequacy of the
proceeds that the Company could realize there from. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources."
RESTRICTIVE COVENANTS
The Credit Facility and the Indenture governing the Notes include certain
covenants that, among other things restrict:
o The making of investments, loans and advances and the paying of
dividends and other restricted payments;
o The incurrence of additional indebtedness;
o The granting of liens, other that liens created pursuant to the Credit
Facility and certain permitted liens;
o Mergers, consolidations and sales of all or substantial part of the
Company's business or property;
o The hedging, forward sale or swap of crude oil or natural gas or other
commodities;
o The sale of assets; and
o The making of capital expenditures.
The Credit Facility requires the Company to maintain certain financial
ratios, including interest coverage and leverage ratios. All of these
restrictive covenants may restrict the Company's ability to expand or pursue its
business strategies. The ability of the Company to comply with these and other
provisions of the Credit Facility may be affected by changes in economic or
business conditions, results of operations or other events beyond the Company's
control. The breach of any of these covenants could result in a default under
the Credit Facility, in which case, depending on the actions taken by the
lenders there under or their successors or assignees, such lenders could elect
to declare all amounts borrowed under the Credit Facility, together with accrued
interest, to be due and payable, and the Company could be prohibited from making
payments with respect to the Notes until the default is cured or all senior debt
is paid or satisfied in full. If the Company were unable to repay such
borrowings, such lenders could proceed against their collateral. If the
indebtedness under the Credit Facility were to be accelerated, there can be no
assurance that the assets of the Company would be sufficient to repay in full
such indebtedness and the other indebtedness of the Company, including the
Notes.
OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS
Oil and gas drilling activities are subject to numerous risks, many of
which are beyond the Company's control, including the risk that no commercially
productive oil and gas reservoirs will be encountered. The cost of drilling,
completing and operating wells is often uncertain, and drilling operations may
be curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure irregularities in formations, equipment
failure or accidents, adverse weather conditions, title problems and shortages
or delays in the delivery of equipment. The Company's future drilling activities
may not be successful and, if unsuccessful, such failure will have an adverse
effect on future results of operations and financial condition.
The Company's properties may be susceptible to hydrocarbon drainage from
production by other operators on adjacent properties. Industry operating risks
include the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases, the occurrence of any of which could
result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. In accordance with
customary industry practice, the Company maintains insurance against the risks
described above. There can be no assurance that any insurance will be adequate
to cover losses or liabilities. The Company cannot predict the continued
availability of insurance, or its availability at premium levels that justify
its purchase.
GAS GATHERING MARKETING
The Company's gas gathering and marketing operations depend in large part
on the ability of the Company to contract with third party producers to purchase
their gas, to obtain sufficient volumes of committed natural gas reserves, to
replace production from declining wells, to assess and respond to changing
market conditions in negotiating gas purchase and sale agreements and to obtain
satisfactory margins between the purchase price of its natural gas supply and
the sales price for such natural gas. In addition, the Company's operations are
subject to changes in regulations relating to gathering and marketing of oil and
gas. The inability of the Company to attract new sources of third party natural
gas or to promptly respond to changing market conditions or regulations in
connection with its gathering and marketing operations could have a material
adverse effect on the Company's financial condition and results of operations.
SUBORDINATION OF NOTES AND GUARANTEES
The Notes are subordinated in right of payment to all existing and future
senior debt (consisting of commitments under the Credit Facility) of the Company
and the Company's subsidiaries that have guaranteed payment of the Notes (the
"Subsidiary Guarantors") including borrowings under the Credit Facility. In the
event of bankruptcy, liquidation or reorganization of the Company or a
subsidiary Guarantor, the assets of the Company, or the Subsidiary Guarantors as
the case may be, will be available to pay obligations on the Notes only after
all Senior debt has been paid in full, and there may not be sufficient assets
remaining to pay amounts due on any or all of the Notes outstanding. The
aggregate principal amount of senior debt of the Company and the Subsidiary
Guarantors, on a consolidated basis, as of March 28, 2003, was $126.5 million.
The Subsidiary Guarantees are subordinated to the guarantor's senior debt to the
same extent and in the same manner as the Notes are subordinated to senior debt.
The Company or the Subsidiary Guarantors may incur additional senior debt from
time to time, subject to certain restrictions. In addition to being subordinated
to all existing and future senior debt of the Company, the Notes are not secured
by any of the Company's assets, unlike the borrowings under the Credit Facility.
POSSIBLE UNENFORCEABILITY OF SUBSIDIARY GUARANTEES; DEPENDENCE ON DISTRIBUTIONS
BY SUBSIDIARIES
The Company has derived approximately 29% of its operating cash flows from
its subsidiaries, Continental Gas and Continental Resources of Illinois, Inc.
The holders of the Notes have no direct claim against the Company's subsidiaries
other that a claim created by one or more of the Subsidiary Guarantees, which
may themselves be subject to legal challenge in a bankruptcy or reorganization
case or a lawsuit by or on behalf of creditors of a Subsidiary Guarantor. If
such a challenge were upheld, such Subsidiary Guarantees would be invalid and
unenforceable. To the extent that any of such Subsidiary Guarantees are not
enforceable, the rights of the holder of the Notes to participate in any
distribution of assets of any Subsidiary Guarantor upon liquidation, bankruptcy,
reorganization or otherwise will, as is that case with other unsecured creditors
of the Company, be subject to prior claims of creditors of that Subsidiary
Guarantor. The Company relies in part upon distributions from its subsidiaries
to generate the funds necessary to meet its obligations, including the payment
of principal and interest on the Notes. The Indenture contains covenants that
restrict the ability of the Company's subsidiaries to enter into any agreement
limiting distributions and transfers to the Company, including dividends.
However, the ability of the Company's subsidiaries to make distributions may be
restricted by among other things, applicable state corporate laws and other laws
and regulations or by terms of agreements of which they are or may become a
party. In addition, there can be no assurance that such distributions will be
adequate to fund the interest and principal payments on the Credit Facility and
the Notes when due.
REPURCHASE OF NOTES UPON A CHANGE OF CONTROL AND CERTAIN OTHER EVENTS
Upon a Change of Control (as defined in the Indenture), holders of the
Notes may have the right to require the Company to repurchase all Notes then
outstanding at a purchase price equal to 101% of the principal amount thereof,
plus accrued interest to the dates of repurchase. In the event of certain asset
dispositions, the Company will be required under certain circumstances to use
the Excess Cash (as defined in the Indenture) to offer to repurchase the Notes
at 100% of the principal amount thereof, plus accrued interest to the date of
repurchase (an "Excess Cash Offer").
The events that constitute a Change of Control or require an Excess Cash
Offer under the Indenture may also be events of default under the Credit
Facility or other senior debt of the Company until the Company's indebtedness
under the Credit Facility or other senior debt is paid in full. In addition,
such events may permit the lenders under such debt instruments to accelerate the
debt and, if the debt is not paid, to enforce security interests on
substantially all the assets of the Company and the Subsidiary Guarantors,
thereby limiting the Company's ability to raise cash to repurchase the Notes and
reducing the practical benefit of the offer to repurchase provisions to the
holders of the Notes. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources." There can
be no assurance that the Company will have sufficient funds available at the
time of any Change of Control or Excess Cash Offer to make any debt payment
(including repurchases of Notes) as described above. Any failure by the Company
to repurchase Notes tendered pursuant to a Change of Control offer or an Excess
Cash Offer will constitute an event of default under the Indenture.
RISK OF HEDGING
From time to time the Company may use energy swap and forward sale
arrangements to reduce its sensitivity to oil and gas price volatility. If the
Company's reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, or otherwise, the Company would be required to satisfy
its obligations under potentially unfavorable terms. Beginning January 1, 2001,
all derivatives must be marked to market under the provisions of statement of
Financial Accounting Standards No. 133, "Accounting for Derivatives" ("SFAS No.
133"). If the Company enters into qualifying derivative instruments for the
purpose of hedging prices and the derivative instruments are not perfectly
effective in hedging the underlying risk, all ineffectiveness will be recognized
currently in earnings. The effective portion of the gain or loss on qualifying
derivative instruments will be reported as other comprehensive income and
reclassified to earnings in the same period as the hedged production takes
place. Physical delivery contracts, which are deemed to be normal purchases or
normal sales, are not accounted for as derivatives. Further, under financial
instrument contracts, the Company may be at risk for basis differential, which
is the difference in the quoted financial price for contract settlement and the
actual physical point of delivery price. The Company will from time to time
attempt to mitigate basis differential risk by entering into physical basis swap
contracts. Substantial variations between the assumptions and estimates used by
the Company in the hedging activities and actual results, experienced could
materially adversely effect the Company's anticipated profit margins and its
ability to manage risk associated with fluctuations in oil and gas prices.
Furthermore, the fixed price sales and hedging contracts limit the benefits the
Company will realize if actual prices rise above the contract prices.
WRITE DOWN OF CARRYING VALUES
The Company periodically reviews the carrying value of its oil and gas
properties in accordance with SFAS No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets". SFAS No. 144 requires that long-lived assets,
including proved oil and gas properties, and certain identifiable intangibles to
be held and used by the Company be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of the assets may not
be recoverable. In performing the review for recoverability, the Company
estimates the future cash flows expected to result from the use of the asset and
its eventual disposition. If the sum of the expected future cash flows
(undiscounted and without interest changes) is less that the carrying value of
the asset, an impairment loss is recognized in the form of additional
depreciation, depletion and amortization expense. Measurement of an impairment
loss for proved oil and gas properties is calculated on a property-by-property
basis as the excess of the net book value of the property over the projected
discounted future net cash flows of the impaired property, considering expected
reserve additions and price and cost escalations. The Company may be required to
write down the carrying value of its oil and gas properties when oil and gas
prices are depressed or unusually volatile, which would result in a charge to
earnings. Once incurred, a write down of oil and gas properties is not
reversible at a later date.
LAWS AND REGULATIONS; ENVIRONMENTAL RISK
Oil and gas operations are subject to various federal, state and local
governmental regulations that may be changed from time to time in response to
economic or political conditions. From time to time, regulatory agencies have
imposed price controls and limitations on production in order to conserve
supplies of oil and gas. In addition, the production, handling, storage,
transportation and disposal of oil and gas, by-products thereof and other
substances and materials produced or used in connection with oil and gas
operations are subject to regulation under federal, state and local laws and
regulations. See "Business--Regulations."
The Company is subject to a variety of federal, state and local
governmental regulations related to the storage, use, discharge and disposal of
toxic, volatile of otherwise hazardous materials. These regulations subject the
Company to increased operating costs and potential liability associated with the
use and disposal of hazardous materials. Although these laws and regulations
have not had a material adverse effect on the Company's financial condition or
results of operations, there can be no assurance that the Company will not be
required to make material expenditures in the future. If such laws and
regulations become increasingly stringent in the future, it could lead to
additional material costs for environmental compliance and remediation by the
Company.
The Company's twenty years of experience with the use of HPAI technology
has not resulted in any known environmental claims. The Company's saltwater
injection operations will pose certain risks of environmental liability to the
Company. Although the Company will monitor the injection process, any leakage
from the subsurface portions of the wells could cause degradation of fresh
ground water resources, potentially resulting in suspension of operation of the
wells, fine and penalties from governmental agencies, expenditures for
remediation of the affected resource, and liability to third parties for
property damages and personal injuries. In addition, the sale by the Company of
residual crude oil collected as part of the saltwater injection process could
impose a liability on the Company in the event the entity to which the oil was
transferred fails to manage the material in accordance with applicable
environmental health and safety laws.
Any failure by the Company to obtain required permits for, control the use
of, or adequately restrict the discharge of, hazardous substances under present
or future regulations could subject the Company to substantial liability or
could cause its operations to be suspended. Such liability or suspension of
operations could have a material adverse effect on the Company's business,
financial condition and results of operations.
COMPETITION
The oil and gas industry is highly competitive. The Company competes for
the acquisition of oil and gas properties, primarily on the basis of the price
to be paid for such properties, with numerous entities including major oil
companies, other independent oil and gas concerns and individual producers and
operators. Many of these competitors are large, well-established companies and
have financial and other resources substantially greater that those of the
Company. The Company's ability to acquire additional oil and gas properties and
to discover reserves in the future will depend upon its ability to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment.
CONTROLLING STOCKHOLDER
At March 28, 2003, Harold Hamm, the Company's principal stockholder,
President and Chief Executive Officer and a Director, beneficially owned
13,037,328 shares of Common Stock representing, in the aggregate, approximately
91% of the outstanding common stock of the Company. The Harold Hamm DST Trust
and Harold Hamm HJ Trust together own the remaining 9.3% of Common Stock. An
independent third party is the trustee for both of these trusts and Harold Hamm
has no beneficial ownership in them. As a result, Mr. Hamm is in a position to
control the Company. The Company is provided oilfield services by several
affiliated companies controlled by the principal stockholder. Such transactions
will continue in the future and may result in conflicts of interest between the
Company and such affiliated companies. There can be no assurance that such
conflicts will be resolved in favor of the Company. If the principal stockholder
ceases to be an executive officer of the Company, such would constitute an event
of default under the Credit Facility, unless waived by the requisite percentage
of banks. See "ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT" and "ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS".
REGULATIONS
GENERAL. Various aspects of the Company's oil and gas operations are
subject to extensive and continually changing regulation, as legislation
affecting the oil and gas industry is under constant review for amendment or
expansion. Numerous departments and agencies, both federal and state, are
authorized to statue to issue, and have issued, rules and regulations binding
upon the oil and gas industry and its individual members.
REGULATIONS OF SALES AND TRANSPORTATION OF NATURAL GAS. The Federal Energy
Regulatory Commission (the "FERC") regulates the transportation and sale of
resale of natural gas in interstate commerce pursuant to the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. In the past, the federal government
has regulated the prices at which oil and gas could be sold. While sales by
producers of natural gas and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. The Company's sales of natural gas are
affected by the availability, terms and cost of transportation. The price and
terms for access to pipeline transportation are subject to extensive regulation
and proposed regulation designed to increase competition within the natural gas
industry, to remove various barriers and practices that historically limited
non-pipeline natural gas sellers, including producers, from effectively
competing with interstate pipelines for sales to local distribution companies
and large industrial and commercial customers and to establish the rates
interstate pipelines may charge for their services. Similarly, the Oklahoma
Corporation Commission and the Texas Railroad Commission have been reviewing
changes to their regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers. While the changes being
considered by these federal and state regulators would affect us only
indirectly, they are intended to further enhance competition in natural gas
markets. The Company cannot predict what further action the FERC or state
regulators will take on these matters; however, the Company does not believe
that any actions taken will have an effect materially different from the effect
on other natural gas producers with whom the Company competes.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. The Company's sales of crude
oil, condensate and gas liquids are not currently regulated and are made at
market prices. The price the Company receives from the sale of these products
may be affected by the cost of transporting the products to market.
ENVIRONMENTAL. The Company's oil and gas operations are subject to
pervasive federal, state and local laws and regulations concerning the
protection and preservation of the environment (e.g., ambient air, and surface
and subsurface soils and waters), human health, worker safety, natural
resources, and wildlife. These laws and regulations affect virtually every
aspect of the Company's oil and gas operations, including its exploration for,
and production, storage, treatment, and transportation of, hydrocarbons and the
disposal of wastes generated in connection with those activities. These laws and
regulations increase the Company's costs of planning, designing, drilling,
installing, operating, and abandoning oil and gas wells and appurtenant
properties, such as gathering systems, pipelines, and storage, treatment and
salt water disposal facilities.
The Company has expended and will continue to expend significant financial
and managerial resources to comply with applicable environmental laws and
regulations, including permitting requirements. The Company's failure to comply
with these laws and regulations can subject it to substantial civil and criminal
penalties, claims for injury to persons and damage to properties and natural
resources, and clean up and other remedial obligations. Although the Company
believes that the operation of its properties generally complies with applicable
environmental laws and regulations, the risk of incurring substantial costs and
liabilities are inherent in the operation of oil and gas wells and appurtenant
properties. The Company could also be subject to liabilities related to the past
operations conducted by others at properties now owned by it, without regard to
any wrongful or negligent conduct by the Company.
The Company cannot predict what effect future environmental legislation and
regulation will have upon its oil and gas operations. The possible legislative
reclassification of certain wastes generated in connection with oil and gas
operations as "hazardous wastes" would have a significant impact on the
Company's operating costs, as well as the oil and gas industry in general. The
cost of compliance with more stringent environmental laws and regulations, or
the more vigorous administration and enforcement of those laws and regulations,
could result in material expenditures by the Company to remove, acquire, modify,
and install equipment, store and dispose of waters, remediate facilities, employ
additional personnel, and implement systems to ensure compliance with those laws
and regulations. These accumulative expenditures could have a material adverse
effect upon the Company's profitability and future capital expenditures.
REGULATION OF OIL AND GAS EXPLORATION AND PRODUCTION. The Company's
exploration and production operations are subject to various types of regulation
at the federal, state and local levels. Such regulations include requiring
permits and drilling bonds for the drilling of wells, regulating the location of
wells, the method of drilling and casing wells, and the surface use and
restoration of properties upon which wells are drilled. Many states also have
statutes or regulations addressing conservation matters, including provisions
for the unitization or pooling of oil and gas properties, the establishment of
maximum rates of production from oil and gas wells and the regulation of
spacing, plugging and abandonment of such wells. Some state statutes limit the
rate at which oil and gas can be produced from the Company's properties.
EMPLOYEES
As of March 28, 2003, the Company employed 288 people, including 97
administrative personnel, 11 geoscientists, 14 engineers and 166 field
personnel. The Company's future success will depend partially on its ability to
attract, retain and motivate qualified personnel. The Company is not a party to
any collective bargaining agreements and has not experienced any strikes or work
stoppages. The Company considers its relations with its employee to be
satisfactory. From time to time the Company utilizes the services of independent
contractors to perform various field and other services.
ITEM 2. PROPERTIES
The Company's oil and gas properties are located in selected portions of
the Mid-Continent, Rocky Mountains and Gulf Coast regions. Through 1993, most of
the Company's activity and growth was focused in the Mid-Continent region. In
1993 the Company expanded its drilling and acquisition activities into the Rocky
Mountain and Gulf Coast regions seeking added opportunity for production and
reserve growth. The Rocky Mountain region was targeted for oil reserves with
good secondary recovery potential and therefore, long life reserves. The Gulf
Coast region was targeted for natural gas reserves with shorter reserve life but
high current cash flow. As of December 31, 2002, the Company's estimated net
proved reserves from all properties totaled 74.9 MMBoe with 83% of the reserves
located in the Rocky Mountains, 16% in the Mid-Continent and 1% in the Gulf
Coast regions. At December 31, 2002, 84% of the Company's net proved reserves
were oil and 16% were natural gas. The Company's oil reserves are confined
primarily to the Rocky Mountain region and its natural gas reserves are
primarily from the Mid-Continent and Gulf Coast regions. Approximately $66.8
million, or 63%, of the Company's projected $105.9 million capital expenditures
for 2003 are focused on expansion and development of its oil properties in the
Rocky Mountain region while the remaining $39.1 million, or 37%, is focused
primarily on natural gas projects in the Mid-Continent and Gulf Coast regions.
The following table provides information with respect to the Company's
net proved reserves for its principal oil and gas properties as of December
31, 2002:
% of Total
Oil Present Value Present Value
Oil Gas Equivalent Of Future Net Of Future Net
Area (MBbl) (MMcf) (MBoe) Revenues(1)(M$) Revenues(1)
- ----------------------------------------------------------------------------------------------------------------------------
ROCKY MOUNTAINS:
Williston Basin 54,026 10,817 55,829 $ 446,824 70%
Big Horn Basin 4,758 10,119 6,445 35,511 6%
------------------ ---------------- -------------- ----------------- ----------------
Total ROCKY MOUNTAINS 58,784 20,936 62,274 482,335 76%
MID-CONTINENT:
Anadarko Basin 1,835 42,561 8,929 106,230 17%
Black Warrior Basin 0 721 120 1,920 0%
Texas Panhandle 17 2,480 430 4,613 1%
Illinois Basin 2,565 464 2,642 28,243 4%
------------------ ---------------- -------------- ----------------- ----------------
Total MID-CONTINENT 4,417 46,226 12,121 141,006 22%
GULF COAST:
Luby 17 1,010 185 3,232 1%
Pebble Beach 31 1,054 207 3,628 1%
Louisiana Onshore 21 170 49 887 0%
Offshore 11 551 103 2,309 0%
------------------ ---------------- -------------- ----------------- ----------------
Total GULF COAST 80 2,785 544 10,056 2%
TOTALS 63,281 69,947 74,939 $ 633,397 100%
================== ================ ============== ================= ================
<FN>
(1) Future estimated net revenues discounted at 10%
</FN>
ROCKY MOUNTAINS
The Company's Rocky Mountain properties are located primarily in the
Williston Basin of North Dakota, South Dakota and Montana and in the Big Horn
Basin of Wyoming. Estimated proved reserves for its Rocky Mountains properties
at December 31, 2002, totaled 62.3 MMBoe and represented 76% of the Company's
PV-10. Approximately 52% of these estimated proved reserves are proved
developed. During the twelve months ended December 31, 2002, the average net
daily production was 8,121 Bbls of oil and 4,891 Mcf of natural gas, or 8,943
Boe per day from the Rocky Mountain properties. The Company's leasehold
interests include 173,000 net developed and 292,000 net undeveloped acres, which
represent 27% and 45% of the Company's total leasehold, respectively. This
leasehold is expected to be developed utilizing 3-D seismic, precision
horizontal drilling and secondary recovery technologies, where applicable. As of
December 31, 2002, the Company's Rocky Mountain properties included an inventory
of 65 development and 21 exploratory drilling locations.
WILLISTON BASIN
CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994.
During the twelve months ended December 31, 2002, the Cedar Hills Field
properties produced 3,813 net Boe per day to the Company's interests. The Cedar
Hills Field produces oil from the Red River "B" formation, a thin (eight feet),
non-fractured, blanket-type, dolomite reservoir found at depths of 8,000 to
9,500 feet. All wells drilled by the Company in the Red River "B" formation were
drilled exclusively with precision horizontal drilling technology. The Cedar
Hills Field covers approximately 200 square miles and has a known oil column of
1,000 feet. Through December 31, 2002, the Company drilled or participated in
199 gross (139 net) horizontal wells, of which 192 were successfully completed,
for a 96% net success rate. The Company believes that the Red River "B"
formation in the Cedar Hills Field is well suited for enhanced secondary
recovery using either HPAI and/or traditional water flooding technology. Both
technologies have been applied successfully in adjacent secondary recovery units
for over 30 years and have proven to increase oil recoveries from the Red River
"B" formation by 200% to 300% over primary recovery. The Company is proficient
using either technology and is in the process of implementing both as part of
its secondary recovery operations in the Cedar Hills Field. Effective March 1,
2001, the Company obtained approval for two secondary recovery units in the
Cedar Hills Field; the Cedar Hills North-Red River "B" Unit ("CHNRRU") located
in Bowman and Slope Counties, North Dakota and the West Cedar Hills Unit
("WCHU") located in Fallon County, Montana. The Company owns 95% of the working
interest in the CHNRRU and is the operator of the unit. The CHNRRU contains 79
wells and 50,000 acres. The Company owns 100% of the working interest in the
WCHU and is the unit operator. The WCHU contains 10 wells and 8,000 acres. An
estimated $52.5 million will need to be invested during 2003 to fully implement
the Company's secondary recovery operations in the Cedar Hills Field. The
components of the $52.5 million invested are $40.2 million for infill drilling
and $12.3 million for infrastructure. By year-end 2003, the Company expects to
have completed 56 of the 65 required injectors and installed facilities to begin
injection in 100% of the units. The Cedar Hills Field represents 59% of the
Company's estimated proved reserves and $367.4 million, or 58%, of the PV-10 of
the Company's proved reserves at December 31, 2002.
MEDICINE POLE HILLS, MEDICINE POLE HILLS WEST, MEDICINE POLE HILLS SOUTH,
BUFFALO, WEST BUFFALO AND SOUTH BUFFALO UNITS. In 1995, the Company acquired the
following interests in four production units in the Williston Basin: Medicine
Pole Hills (63%), Buffalo (86%), West Buffalo (82%), and South Buffalo (85%).
During the twelve months ended December 31, 2002, these units produced 1,034 Boe
per day, net to the Company's interests, and represented 5.3 MMBoe and $36.4
million, or 6%, of the PV-10 attributable to the Company's estimated proved
reserves as of December 31, 2002. These units are HPAI enhanced recovery
projects that produce from the Red River "B" formation and are operated by the
Company. All were discovered and developed with conventional vertical drilling.
The oldest vertical well in these units has been producing for 47 years,
demonstrating the long-lived production characteristic of the Red River "B"
formation. There are 156 producing wells in these units and current estimates of
remaining reserve life range from four to 13 years. The Company subsequently
expanded the Medicine Pole Hills Unit through horizontal drilling into the
Medicine Pole Hills West Unit ("MPHWU"), which became effective April 1, 2000.
The MPHWU produces from 25 wells and encompasses an additional 22 square miles
of productive Red River "B" reservoir. The Company owns approximately 80% of the
MPHWU and began secondary injection November 22, 2000. The MPHWU was the first
in a scheduled two-phase expansion of the Medicine Pole Hills Unit. Phase two of
the expansion plan was successfully completed during 2001 delineating another 20
square miles of productive Red River B reservoir through horizontal drilling.
The Medicine Pole Hills South Unit ("MPHSU") became effective October 1, 2002,
with injection expected to begin by mid-year 2003.
LUSTRE AND MIDFORK FIELDS. In January 1992, the Company acquired the Lustre
and Midfork Fields which, during the twelve months ended December 31, 2002,
produced 357 Bbls per day, net to the Company's interests. Wells in both the
Lustre and Midfork Fields produce from the Charles "C" dolomite, at depths of
5,500 to 6,000 feet. Historically, production from the Charles "C" has a low
daily production rate and is long lived. There are currently 43 wells producing
in the two fields. No secondary recovery operations are underway in either field
at this time but are under consideration. The Company currently owns 99,000 net
acres in the Lustre and Midfork Field area.
The Company believes significant upside exists in the reservoirs that
underlie the Charles "C" dolomite including the Mission Canyon, Lodgepole, and
Nisku formations. Historically production from these reservoirs is more
difficult to locate but prolific when found. 3-D seismic is being utilized to
locate reserves in these reservoirs. During 2002, the Company made a modest
discovery in the Lodgepole formation utilizing 60 square miles of proprietary
3-D data acquired in late 2001. The discovery is significant in that it
established production 200 miles from the nearest Lodgepole production near
Dickinson, North Dakota, which was quite prolific. The Company controls
approximately 70,000 net undeveloped acres in this particular part of the play
and has identified 12 drilling locations from its 3-D seismic. During 2003, the
Company plans to drill 1 development and 2 exploratory wells.
BIG HORN BASIN
On May 14, 1998, the Company consummated the purchase, for $86.5 million,
of producing and non-producing oil and gas properties and certain other related
assets in the Worland Field, effective as of June 1, 1998. Subsequently, and
effective as of June 1, 1998, the Company sold an undivided 50% interest in the
Worland Field properties (excluding inventory and certain equipment) to the
Company's principal stockholder, for $42.6 million. On December 31, 1999, the
Company's principal stockholder contributed the undivided 50% interest in the
Worland Properties along with debt of $18,600,000. The stockholder contributed
$22,461,096 of the properties as additional paid-in-capital and the Company
assumed his outstanding debt for the balance of the purchase price.
During the twelve months ended December 31, 2002, the Worland Field
properties produced 1,763 Boe per day, net to the Company's interests. These
properties cover 96,000 net leasehold acres in the Worland Field of the Big Horn
Basin in northern Wyoming, of which 29,000 net acres are held by production and
67,000 net acres are non-producing or prospective. Approximately two-thirds of
the Company's producing leases in the Worland Field are within five federal
units, the largest of which, the Cottonwood Creek Unit, has been producing for
more than 40 years. All of the units produce principally from the Phosphoria
formation, which is the most prolific oil producing formation in the Worland
Field. Four of the units are unitized as to all depths, with the Cottonwood
Creek Field Extension (Phosphoria) Unit being unitized only as to the Phosphoria
formation. The Company is the operator of all five of the federal units. The
Company also operates 38 producing wells located on non-unitized acreage. The
Company's Worland Field properties include interests in 329 producing wells, 303
of which are operated by the Company.
As of December 31, 2002, the estimated net proved reserves attributable to
the Company's Worland Field properties were approximately 6.4 MMBoe, with an
estimated PV-10 of $35.5 million. Approximately 74%, by volume, of these proved
reserves consist of oil, principally in the Phosphoria formation. Oil produced
from the Company's Worland Field properties is low gravity, sour (high sulphur
content) crude, resulting in a lower sales price per barrel than non-sour crude,
and is sold into a Marathon pipeline or is trucked from the lease. Gas produced
from the Worland Field properties is also sour, resulting in a sale price that
is less per Mcf than non-sour natural gas. From the effective date of the
Worland Field Acquisition through September 30, 1998, the average price of crude
oil produced by the Worland Field properties was $5.19 per Bbl less than the
NYMEX price of crude oil. The Company entered into a contract effective December
1, 2001, through December 31, 2001, to sell crude oil produced from its Worland
Field properties at an average price of $6.00 per Bbl less than the NYMEX price.
Subsequent to these contracts, and effective January 1, 2002, the Company
entered into a contract to sell the Worland Field production at a
gravity-adjusted price of $4.21 per barrel less than the monthly NYMEX average
price. This contract was renegotiated January 2003 at a price that will average
$4.00 to $5.00 less than the monthly NYMEX average price.
The Company believes that secondary and tertiary recovery projects have
significant potential for the addition of reserves in the Worland Field area
fields. The Company continues to seek the best method for increasing recovery
from the producing reservoirs. Currently the Company has one Tensleep waterflood
project and one pilot imbibition flood underway. The Company implemented water
injection into five wells in late 2002 to evaluate secondary and pressure
recovery techniques that will best process the Phosphoria dolomite oil reserves.
Production should be enhanced in as many as 20 offset wells. The Company has
installed the system for expansion if the results meet expectations. In addition
to the secondary and pressure recovery projects, the Company is evaluating
infill drilling opportunities based on neural network analysis techniques and
has identified 70 wells for acid fracturing treatments. The infill drilling and
acid frac procedures will be evaluated as each well is completed to ensure that
the techniques are viable. As evidenced by past infill drilling and acid
fracturing stimulations, reserve growth can be significant.
MID-CONTINENT
The Company's Mid-Continent properties are located primarily in the
Anadarko Basin of western Oklahoma and the Texas Panhandle. During 2001, the
Company expanded its operations in the Mid-Continent through successful
exploration in the Black Warrior Basin in Mississippi and the acquisition of
Farrar Oil Company's assets in the Anadarko and Illinois Basins. At December 31,
2002, the Company's estimated proved reserves in the Mid-Continent totaled 12.1
MMBoe and represented 22% of the Company's PV-10. At December 31, 2002,
approximately 64% of the Company's estimated proved reserves in the
Mid-Continent were natural gas. Net daily production from these properties
during 2002 averaged 2,129 Bbls of oil and 15,150 Mcf of natural gas, or 4,658
Boe to the Company's interests. The Company's Mid-Continent leasehold position
includes 100,000 net developed and 62,000 net undeveloped acres, representing
15% and 10% of the Company's total leasehold, respectively, at December 31,
2002. As of December 31, 2002, the Company's Mid-Continent properties included
an inventory of 15 development and 17 exploratory drilling locations.
ANADARKO BASIN. The Anadarko Basin properties contained 74% of the
Company's estimated proved reserves for the Mid-Continent and 17% of the
Company's total PV-10 at December 31, 2002, and represented 61% of the Company's
estimated proved reserves of natural gas. During the twelve months ended
December 31, 2002, net daily production from its Anadarko Basin properties
averaged 799 Bbls of oil and 13,167 Mcf of natural gas, or 2,993 Boe to the
Company's interests from 655 gross (289 net) producing wells, 330 of which are
operated by the Company. The Anadarko Basin wells produce from a variety of
sands and carbonates in both stratigraphic and structural traps in the Arbuckle,
Oil Creek, Viola, Mississippian, Springer, Morrow, Red Fork, Oswego, Skinner and
Tonkawa formations, at depths ranging from 6,000 to 12,000 feet. These
properties have been a steady source of cash flow for the Company and are
continually being developed by infill drilling, recompletions and workovers. As
of December 31, 2002, the Company had identified 12 development and one
exploratory drilling location on its properties in the Anadarko Basin.
ILLINOIS BASIN. On July 9, 2001, the Company purchased the assets of Farrar
Oil Company and its subsidiary, Har-Ken Oil Company, for $33.7 million under its
newly formed subsidiary, Continental Resources of Illinois, Inc. ("CRII"). The
Illinois Basin properties contained 22% of the Company's estimated proved
reserves for the Mid-Continent and 4% of the Company's total PV-10 at December
31, 2002. Net daily production during the twelve months ended December 31, 2002,
averaged 1,244 Bbls of oil and 189 Mcf of natural gas, or 1,275 Boe to the
Company's interests from 880 gross (646 net) producing wells, 714 of which are
operated by the Company. Approximately 70% of the Company's net oil production
in this basin comes from 31 active secondary recovery projects. Company
expertise resulting in very efficient operations combined with low decline rates
makes most of the properties very long lived. Many of the projects have been
active for over 15 years with many years of economic life remaining. At year-end
the Company was evaluating a production acquisition possessing significant
secondary recovery potential. Three new secondary recovery projects are planned
for implementation during 2003. All properties are constantly being evaluated
and we are continually performing numerous workovers and making injection
enhancements. As of December 31, 2002, the Company had 3 development and 10
exploratory drilling locations in inventory and scheduled for drilling during
2003. All of the exploratory drill sites were selected from interpretations
utilizing detailed geological studies and computer mapping with all but one
defined by seismic programs shot by the Company. In addition, the Company has 6
active exploration project areas with seismic programs to cover all the areas to
be shot during 2003. Included in this seismic program are three projects where
the use of 3-D seismic will be employed.
BLACK WARRIOR BASIN. In April 2000, the Company began a grass roots effort
to expand its exploration program into the Black Warrior Basin located in
eastern Mississippi and western Alabama. The Company believes the Black Warrior
Basin offers opportunity for growth and adds a component of low cost, high rate
of return, shallow gas reserves to the Company's overall drilling program.
Reservoirs are Pennsylvanian and Mississippian age sands found at depths of
2,500 feet to 4,500 feet with reserves of .75 Bcf per well on average. Net daily
production during the ten months ended December 31, 2002, averaged 766 Mcf of
natural gas or 128 Boe to the Company's interests. Competition in the basin is
low which has enabled the Company to readily acquire leases on new projects and
keep costs low. As of December 31, 2002, the Company had acquired 25,000 net
acres on selected projects. The Company has also augmented its geological
expertise by acquiring licenses to approximately 1,500 miles of 2-D seismic data
across the basin. During 2002, the Company drilled 12 wells and established four
producers for a 33% success rate. Although this success rate is in line with
historical averages for the basin, the production and reserves found have not
met expectations. During 2003, the Company plans to drill 5 wells and the
results of these wells will dictate the Company's continued commitment to the
basin.
GULF COAST
The Company's Gulf Coast activities are located primarily in the Pebble
Beach and Luby Projects in Nueces County, Texas and the Jefferson Island Project
in Iberia Parish, Louisiana. The Company is also a partner in a joint venture
arrangement with Challenger Minerals, Inc. to locate and participate in drilling
opportunities on the shallow shelf of the Gulf of Mexico. At December 31, 2002,
the Company's estimated proved reserves in the Gulf Coast totaled .5 MMBoe (85%
gas) representing 2% of the Company's total PV-10 and 4% of the Company's
estimated proved reserves of natural gas. During 2002, the Company's Gulf Coast
producing wells represented only 4% of the Company's total producing well count,
but produced 21% of the Company's total gas production for the year. Net daily
production from these properties is 187 Bbls of oil and 5,245 Mcf of natural gas
or 1,061 Boe to the Company's interests from 5wells. The Company's leasehold
position includes 6,000 net developed and 18,000 net undeveloped acres
representing 1% and 3% of the Company's total leasehold respectively. From a
combined total of 95 square miles of proprietary 3-D data, 22 development and 21
exploratory locations have been identified for drilling on these projects.
PEBBLE BEACH/LUBY. The Pebble Beach/Luby projects target the prolific Frio
and Vicksburg sands underlying and surrounding the Clara Driscoll and Luby
fields in Nueces County, Texas. These sandstone reservoirs produce on structures
readily defined by seismic and remain largely untested below the existing
producing reservoirs in the fields at depths ranging from 6,000 feet to 13,000
feet. At December 31, 2002, the Company's estimated proved reserves in the
Pebble Beach/Luby fields totaled 2,064 MMcf or 3% of the Company's estimated
proved reserves of natural gas. Net daily production during the twelve months
ended December 31, 2002, averages 65 Bbls of oil and 2,723 Mcf of gas, or 519
Boe to the Company's interests. The Company owns 23,000 gross and 19,000 net
acres and has acquired 95 square miles of proprietary 3-D seismic data in these
two projects. From the proprietary 3-D data, the Company has identified 22
development and 13 exploratory locations for drilling.
During 2002, the Company drilled 9 wells with 8 being completed as
producing wells and 1 dry hole. In 2003, the Company will continue its
development and expects to drill 13 additional wells in the Pebble Beach/Luby
projects. The Company also expects to acquire additional leasehold and
approximately 60 square miles of new proprietary 3-D data in selected projects
as part of its ongoing expansion in South Texas.
JEFFERSON ISLAND. The Jefferson Island project is an underdeveloped salt
dome that produces from a series of prolific Miocene sands. To date the field
has produced 111.1 MMBoe from approximately one quarter of the total dome. The
remaining three quarters of the faulted dome complex are essentially unexplored
or underdeveloped. The Company controls 2,000 gross and 1,000 net acres in the
project and owns 35 square miles of proprietary 3-D seismic covering the
property through an agreement with a third party. Under the agreement, the third
party had to pay 100% of costs for acquiring 3-D seismic and drill five wells,
carrying the Company for 16% working interest at no cost, to earn 50% interest
in the Jefferson Island project. During 2000, the third party completed its 3-D
seismic and drilling obligation and earned 50% of the project. Out of the five
wells drilled by the third party, two are commercial wells, two non-commercials
and one was a dry hole. With the third party's seismic and drilling obligations
fulfilled, the Company regained control of drilling operations and drilled one
exploratory well in 2001 seeking higher reserve potential. The exploratory well
was successful and penetrated 180 feet of pay in multiple sands underlying a 3-D
imaged salt overhang along the flank of the salt dome complex. The discovery is
quite significant in that it confirmed our ability to image the salt and
encounter pay in sand reservoirs not previously known to produce in the field.
The Company has identified 5 additional exploratory drilling locations and plans
to drill at least one in 2003.
GULF OF MEXICO. In July 1999 the Company elected to expand its drilling
program into the shallow waters of the Gulf of Mexico ("GOM") though a joint
venture arrangement with Challenger Minerals, Inc. This was part of the
Company's ongoing strategy to build its opportunity base of high rate of return,
natural gas reserves in the Gulf Coast region. The expansion into the GOM has
proven successful and as of December 31, 2002, the Company has participated in
15 wells that have resulted in seven producers, seven dry holes, and one well
has been plugged. The Company plans to continue its activity in the GOM as a
non-operator, restricting its risked investments to approximately $750,000 per
project. The Company currently has 2 potential wells in inventory for 2003.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and
gas production, prices and costs attributable to all oil and gas property
interests owned by the Company for the periods shown:
Year Ended December 31,
---------------------------------------------------------
NET PRODUCTION DATA: 2000 2001 2002
------------------ ----------------- -----------------
Oil and condensate (MBbl) 3,360 3,489 3,810
Natural gas (MMcf) 7,939 8,411 9,229
Total (MBoe) 4,684 4,893 5,352
UNIT ECONOMICS
Average sales price per Bbl (w/o hedges) $29.02 $23.79 $24.05
Average sales price per Bbl (with hedges) $27.41 $23.87 $22.56
Average sales price per Mcf $2.91 $3.41 $2.46
Average sales price per Boe (w/o hedges) $25.75 $22.82 $21.36
Average sales price per Boe (with hedges) $24.65 $22.92 $20.32
Lifting cost per Boe (1) $6.36 $7.52 $6.75
DD&A expense per Boe (1) $3.71 $4.90 $5.04
General and administrative expense per Boe (2) $1.52 $1.79 $1.99
Gross Margin $13.06 $8.71 $6.54
- ---------------
<FN>
(1) Related to oil and gas producing properties.
(2) Related to oil and gas producing properties, net of operating overhead income.
</FN>
PRODUCING WELLS
The following table sets forth the number of productive wells, exclusive of
injection wells and water wells, as of December 31, 2002. In the table "gross"
refers to total wells in which the Company had a working interest and "net"
refers to gross wells multiplied by our working interest.
OIL WELLS GAS WELLS TOTAL WELLS
------------------------------------- -------------------------------- -------------------------------
ROCKY MOUNTAIN GROSS NET GROSS NET GROSS NET
------------------- ----------------- ---------------- --------------- ---------------- --------------
Williston Basin 381 328 0 0 381 328
Big Horn Basin 328 287 1 1 329 288
------------------- ----------------- ---------------- --------------- ---------------- ---------------
Total ROCKY MOUNTAIN 709 615 1 1 710 616
MID-CONTINENT
Anadarko Basin 370 206 285 83 655 289
Texas Panhandle 19 12 15 5 34 17
Illinois Basin 843 612 37 34 880 646
Black Warrior Basin 0 0 5 4 5 4
------------------- ----------------- ---------------- --------------- ---------------- ---------------
Total MID-CONTINENT 1,232 830 342 126 1,574 956
GULF COAST
Louisiana Onshore 2 1 7 3 9 4
Luby 33 33 31 31 64 64
Offshore 0 0 7 1 7 1
Pebble Beach 8 6 11 7 19 13
Texas Onshore 0 0 2 2 2 2
------------------- ----------------- ---------------- --------------- ---------------- ---------------
Total GULF COAST 43 40 58 43 101 84
TOTAL 1,984 1,485 401 171 2,385 1,656
=================== ================= ================ =============== ================ ===============
ACREAGE
The following table sets forth the Company's developed and undeveloped
gross and net leasehold acreage as of December 31, 2002. In the table "gross"
refers to total acres in which the Company had a working interest and "net"
refers to gross acres multiplied by our working interest.
Developed Undeveloped Total
----------------------------- ----------------------------- ----------------------------
Rocky Mountains Gross Net Gross Net Gross Net
------------- -------------- -------------- ------------- ------------- -------------
Williston Basin 163,470 143,915 249,198 207,644 412,668 351,559
Big Horn Basin 30,569 29,358 69,788 66,884 100,357 96,242
Canada 0 0 17,117 17,117 17,117 17,117
New Mexico 0 0 560 560 560 560
------------- -------------- -------------- ------------- ------------- -------------
Total Rocky Mountains 194,039 173,273 336,663 292,205 530,702 465,478
Mid-Continent
Anadarko Basin 119,879 68,110 30,870 26,953 150,749 95,063
Black Warrior Basin 1,530 1,102 37,820 24,380 39,350 25,482
Illinois Basin 39,809 30,384 1,905 1,905 41,714 32,289
Other 0 0 8,715 8,714 8,715 8,714
------------- -------------- -------------- ------------- ------------- -------------
Total Mid-Continent 161,218 99,596 79,310 61,952 240,528 161,548
Gulf Coast 15,515 5,872 29,659 17,893 45,174 23,765
------------- -------------- -------------- ------------- ------------- -------------
Total Gulf Coast 15,515 5,872 29,659 17,893 45,174 23,765
Grand Total Acreage 370,772 278,741 445,632 372,050 816,404 650,791
============= ============== ============== ============= ============= =============
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on its
properties for the periods indicated. In the table "gross" refers to total wells
in which the Company had a working interest and "net" refers to gross wells
multiplied by our working interest.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------------------
2000 2001 2002
------------------------------ ------------------------------- ------------------------------
DEVELOPMENT WELLS: GROSS NET GROSS NET GROSS NET
-------------- --------------- --------------- --------------- -------------- ---------------
Productive 23 19.4 32 25.4 52 46.4
Non-productive 3 2.9 15 7.2 5 4.3
-------------- --------------- --------------- --------------- -------------- ---------------
Total 26 22.3 47 32.6 57 50.7
============== =============== =============== =============== ============== ===============
EXPLORATORY WELLS:
Productive 15 9.3 11 5.7 16 12.8
Non-productive 7 3.0 10 5.5 9 6.2
-------------- --------------- --------------- --------------- -------------- ---------------
Total 22 12.3 21 11.2 25 19.0
============== =============== =============== =============== ============== ===============
OIL AND GAS RESERVES
The following table summarizes the estimates of the Company's net proved
oil and gas reserves and the related PV-10 of such reserves at the dates shown.
Ryder Scott Company Petroleum Engineers ("Ryder Scott") prepared the reserve and
present value data with respect to the Company's oil and gas properties, which
represented 83% of the PV-10 at December 31, 2000, 97.6% of the PV-10 at
December 31, 2001, and 89% of the PV-10 at December 31, 2002. The Company
prepared the reserve and present value data on all other properties.
(Dollars in thousands) December 31,
---------------------------------------------------------
Proved developed reserves: 2000 2001 2002
------------------ ------------------- ------------------
Oil (MBbl) 33,173 31,325 33,626
Natural Gas (MMcf) 58,438 56,647 69,273
Total (MBoe) 42,913 40,766 45,172
Proved undeveloped reserves:
Oil (MBbl) 2,091 28,406 29,655
Natural Gas (MMcf) 1,435 (4,381) 674
Total (MBoe) 2,330 27,676 29,767
Total proved reserves:
Oil (MBbl) 35,264 59,731 63,281
Natural Gas (MMcf) 59,873 52,267 69,947
Total (MBoe) 45,243 68,442 74,939
PV-10 (1) $491,799 $308,604 $633,397
- ---------------
<FN>
(1) PV-10 represents the present value of estimated future net cash flows before income
tax discounted at 10%. In accordance with applicable requirements of the
Commission, estimates of the Company's proved reserves and future net cash flows are
made using oil and gas sales prices estimated to be in effect as of the date of such
reserve estimates and are held constant throughout the life of the properties
(except to the extent a contract specifically provides for escalation). The prices
used in calculating PV-10 as of December 31, 2000, 2001 and 2002, were $26.80 per
Bbl of oil and $9.78 per Mcf of natural gas, $18.67 per Bbl of oil and $1.96 per Mcf
of natural gas and $29.04 per Bbl of oil and $3.33 per Mcf of natural gas,
respectively.
</FN>
Estimated quantities of proved reserves and future net cash flows there from are
affected by oil and gas prices, which have fluctuated widely in recent years.
There are numerous uncertainties inherent in estimating oil and gas reserves and
their values, including many factors beyond the control of the producer. The
reserve data set forth in this annual report on Form 10-K represent only
estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates of different engineers, including those used by the Company,
may vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities,
prevailing oil and gas prices, operating costs and other factors, which
revisions may be material. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they are based.
In general, the volume of production from oil and gas properties declines
as reserves are depleted. Except to the extent the Company acquires properties
containing proved reserves or conducts successful exploitation and development
activities, the proved reserves of the Company will decline as reserves are
produced. The Company's future oil and gas production is, therefore, highly
dependent upon its level of success in finding or acquiring additional reserves.
GAS GATHERING SYSTEMS
The Company's gas gathering systems are owned by Continental Gas Inc.
("CGI"). Natural gas and casinghead gas are purchased at the wellhead primarily
under either market-sensitive percent-of-proceeds-index contracts or keep-whole
gas purchase contracts or fee-based contracts. Under percent-of-proceeds-index
contracts, CGI receives a fixed percentage of the monthly index posted price for
natural gas and a fixed percentage of the resale price for natural gas liquids.
CGI generally receives between 20% and 30% of the posted index price for natural
gas sales and from 20% to 30% of the proceeds received from natural gas liquids
sales. Under keep-whole gas purchase contracts, CGI retains all natural gas
liquids recovered by its processing facilities and keeps the producers whole by
returning to the producers at the tailgate of its plants an amount of residue
gas, equal on a BTU basis, to the natural gas received at the plant inlet. The
keep-whole component of the contract permits the Company to benefit when the
value of natural gas liquids is greater as a liquid than as a portion of the
residue gas stream. Under the fee-based contracts, CGI receives a fixed rate per
MMBTU of gas sold. This rate per MMBTU remains fixed regardless of commodity
prices.
OIL AND GAS MARKETING
The Company's oil and gas production is sold primarily under
market-sensitive or spot price contracts. The Company sells substantially all of
its casinghead gas to purchasers under varying percentage-of-proceeds contracts.
By the terms of these contracts, the Company receives a fixed percentage of the
resale price received by the purchaser for sales of natural gas and natural gas
liquids recovered after gathering and processing the Company's gas. The Company
normally receives between 80% and 100% of the proceeds from natural gas sales
and from 80% to 100% of the proceeds from natural gas liquids sales received by
the Company's purchasers when the products are resold. The natural gas and
natural gas liquids sold by these purchasers are sold primarily based on spot
market prices. The revenues received by the Company from the sale of natural gas
liquids are included in natural gas sales. As a result of the natural gas
liquids contained in the Company's production, the Company has historically
improved its price realization on its natural gas sales as compared to Henry Hub
or other natural gas price indexes. For the year ended December 31, 2002,
purchases of the Company's natural gas production by ONEOK Field Services
accounted for 23% of the Company's total gas sales for such period and for the
same period purchases of the Company's oil production by EOTT Energy Corp.
accounted for 61% of the Company's total produced oil sales. Due to the
availability of other markets, the Company does not believe that the loss of any
crude oil or gas customer would have a material effect on the Company's results
of operations.
Periodically the Company utilizes various price risk management strategies
to fix the price of a portion of its future oil and gas production. The Company
does not establish hedges in excess of its expected production. These strategies
customarily emphasize forward-sale, fixed-price contracts for physical delivery
of a specified quantity of production or swap arrangements that establish an
index-related price above which the Company pays the hedging partner and below
which the hedging partner pays the Company. These contracts allow the Company to
predict with greater certainty the effective oil and gas prices to be received
for its hedged production and benefit the Company when market prices are less
than the fixed prices provided in its forward-sale contracts. However, the
Company does not benefit from market prices that are higher than the fixed
prices in such contracts for its hedged production. In August 1998, the Company
began engaging in oil trading arrangements as part of its oil marketing
activities. Under these arrangements, the Company contracts to purchase oil from
one source and to sell oil to an unrelated purchaser, usually at disparate
prices. During the second quarter of 2002, the Company discontinued crude oil
trading contracts.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is party to litigation or other legal
proceedings that it considers to be a part of the ordinary course of its
business. The Company is not involved in any legal proceedings nor is it party
to any pending or threatened claims that could reasonably be expected to have a
material adverse effect on its financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT?S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
There is no established trading market for the Company's common stock. The
Company authorized an approximate 293:1 stock split during 2000. As a result all
amounts are presented retroactive to account for the split. As of March 28,
2003, there were three record holders of the Company's common stock. The Company
issued no equity securities during 2002. During 2000, the Company established a
Stock Option Plan with 1,020,000 shares available, of which options to purchase
an aggregate of 172,000 shares have been granted.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected historical consolidated financial
data for the periods ended and as of the dates indicated. The statements of
operations and other financial data for the years ended December 31, 1998, 1999,
2000, 2001 and 2002, and the balance sheet data as of December 31, 1998, 1999,
2000, 2001 and 2002, have been derived from, and should be reviewed in
conjunction with, the consolidated financial statements of the Company, and the
notes thereto. Ernst and Young LLP audited our financial statements for 2002 and
Arthur Andersen LLP audited the remaining years. The balance sheets as of
December 31, 2001, and 2002, and the statements of operations for the years
ended December 31, 2000, 2001 and 2002, are included elsewhere in this annual
report on Form 10-K. The data should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the consolidated financial statements and the related notes thereto included
elsewhere in this Report.
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
Statement of Operating Data: YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
(dollars in thousands) 1998 1999 2000 2001 2002
-------------- ------------- ------------- --------------- ---------------
Revenue:
Oil and Gas Sales $ 60,162 $ 65,949 $ 115,478 $ 112,170 $ 108,752
Crude Oil Marketing Income 232,216 241,630 279,834 245,872 153,547
Change in Derivative Fair Value 0 0 0 0 (1,455)
Gathering, Marketing and Processing 17,701 21,563 32,758 44,988 33,708
Oil and Gas Service Operations 4,003 3,368 5,760 6,047 5,739
-------------- ------------- ------------- --------------- ---------------
Total Revenues 314,082 332,510 433,830 409,077 300,291
Operating Costs and Expenses:
Production Expenses and Taxes 22,611 19,368 29,807 36,791 36,112
Exploration Expenses 5,468 3,191 9,965 15,863 10,229
Crude Oil Marketing Expense. 228,797 236,135 278,809 245,003 152,718
Gathering, Marketing and Processing 16,233 18,391 28,303 36,367 29,783
Oil and Gas Service Operations 3,664 3,420 5,582 5,294 6,462
Depreciation, Depletion and Amortization 30,198 19,549 19,552 27,731 31,380
Property Impairments 10,165 5,154 5,631 10,113 25,686
General and Administrative 6,098 4,540 7,142 8,753 10,713
-------------- ------------- ------------- --------------- ---------------
Total Operating Costs and Expenses 323,234 309,748 384,791 385,915 303,083
Operating Income (Loss) (9,152) 22,762 49,039 23,162 (2,792)
Interest Income 967 310 756 630 285
Interest Expense (12,826) (17,370) (16,514) (15,674) (18,401)
Change in Accounting Principle (1) 0 (2,048) 0 0 0
Other Revenue (Expense), net 3,031 266 4,499 3,549 876
-------------- ------------- ------------- --------------- ---------------
Total Other Income(Expense) (8,828) (18,842) (11,259) (11,495) (17,240)
Net Income (Loss) $ (17,980) $ 3,920 $ 37,780 $ 11,667 $ (20,032)
============== ============= ============= =============== ===============
OTHER FINANCIAL DATA:
Adjusted EBITDA (2) $ 40,677 $ 49,184 $ 89,442 $ 81,048 $ 65,664
Net cash provided by operations 27,884 26,179 72,262 63,413 46,997
Net cash used in investing (114,743) (15,972) (44,246) (106,384) (113,295)
Net cash provided by (used in)financing 101,376 (15,602) (31,287) 43,045 61,593
Capital expenditures (3) 95,474 57,530 51,911 111,023 113,447
RATIOS:
Adjusted EBITDA to interest expense 3.2x 2.8x 5.4x 5.2x 3.6x
Total funded debt to Adjusted EBITDA (4) 4.2x 3.5x 1.6x 2.2x 3.6x
Earnings to fixed charges (5) N/A 1.2x 3.3x 1.7x N/A
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents $ 15,817 $ 10,421 $ 7,151 $ 7,225 $ 2,520
Total assets 253,739 282,559 298,623 354,485 406,677
Long-term debt, including current maturities 167,637 170,637 140,350 183,395 247,105
Stockholder's equity 60,284 86,666 123,446 135,113 115,081
- ----------------
<FN>
(1) Change in accounting principle represents the cumulative effect impact of adopting EITF 98-10 "Accounting for Energy Trading
and Risk Management Activities."
(2) Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment
of property and exploration expense, excluding proceeds from litigation settlements. Adjusted EBITDA is not a measure of cash
flow as determined in accordance with GAAP. Adjusted EBITDA should not be considered as an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with GAAP or as an indicator of a company's operating performance
or liquidity. Certain items excluded from adjusted EBITDA are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of
depreciable assets, none of which are components of adjusted EBITDA. The Company's computation of adjusted EBITDA may not be
comparable to other similarly titled measures of other companies. The Company believes that adjusted EBITDA is a widely
followed measure of operating performance and may also be used by investors to measure the Company's ability to meet future
debt service requirements, if any. Adjusted EBITDA does not give effect to the Company's exploration expenditures, which are
largely discretionary by the Company and which, to the extent expended, would reduce cash available for debt service,
repayment of indebtedness and dividends.
(3) Capital expenditures include costs related to acquisitions of producing oil and gas properties and include the contribution
of the Worland properties by the principal stockholder of $22.4 million during the year ended December 31, 1999, and the
purchase of the assets of Farrar Oil Company and Har-Ken Oil Company for $33.7 million during the year ended December 31,
2001. Capital expenditures for 2002 included $47.2 million for Cedar Hill's development and $9.9 for capital leases.
(4) Total funded debt to Adjusted EBITDA excludes capital leases of $11.9 million.
(5) For purposes of computing the ratio of earnings to fixed charges, earnings are computed as income from continuing operations
before fixed charges. Fixed charges consist of interest expense and amortization of costs incurred in the offering of the
Notes. For the year ended December 31, 1998 and 2002, earnings were insufficient to cover fixed charges by $18.0 million and
$20.0 million, respectively.
</FN>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CRITICAL ACCOUNTING POLICIES AND PRACTICES
The use of estimates is necessary in the preparation of the Company's
consolidated financial statements. The circumstances that make these judgments
difficult, subjective and complex have to do with the need to make estimates
about the effect of matters that are inherently uncertain. The use of estimates
and assumptions affects the reported amounts of assets and liabilities. Such
estimates and assumptions also affect the disclosure of legal reserves,
abandonment reserves, oil and gas reserves and other contingent assets and
liabilities at the date of the consolidated financial statements, as well as
amounts of revenues and expenses recognized during the reporting period. Of the
estimates and assumptions that affect reported results, estimates of the
Company's oil and gas reserves are the most significant. Changes in oil and gas
reserves estimates impact the Company's calculation of depletion and abandonment
expense and is critical in the Company's assessment of asset impairments.
Management believes it is necessary to understand the Company's significant
accounting policies, "Item 8. Financial Statements and Supplementary Data-Note
1-Summary of Significant Accounting Policies" of this form 10-K, in order to
understand the Company's financial condition, changes in financial condition and
results of operations.
The following discussion should be read in conjunction with the Company's
consolidated financial statements and notes thereto and the selected
consolidated financial data included elsewhere herein.
OVERVIEW
The Company's revenue, profitability and cash flow are substantially
dependent upon prevailing prices for oil and gas and the volumes of oil and gas
it produces. The Company produced more oil and gas in 2002 than in 2001. Average
wellhead prices during 2002 were $22.90 per Bbl of oil and $2.46 per Mcf of
natural gas compared to $24.05 per Bbl of oil and $3.41 per Mcf of natural gas
during 2001
The Company uses the successful efforts method of accounting for its
investment in oil and gas properties. Under the successful efforts method of
accounting, costs to acquire mineral interests in oil and gas properties, to
drill and provide equipment for exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. These costs are amortized
to operations on a unit-of-production method based on petroleum engineering
estimates. Geological and geophysical costs, lease rentals and costs associated
with unsuccessful exploratory wells are expensed as incurred. Maintenance and
repairs are expensed as incurred, except that the cost of replacements or
renewals that expand capacity or improve production are capitalized. Significant
downward revisions of quantity estimates or declines in oil and gas prices that
are not offset by other factors could result in a writedown for impairment of
the carrying value of oil and gas properties. Once incurred, a writedown of an
oil and gas property is not reversible at a later date, even if oil or gas
prices increase.
The Company is an S-Corporation for federal income tax purposes. The
Company currently anticipates it will pay periodic dividends in amounts
sufficient to enable the Company's stockholders to pay their income tax
obligations with respect to the Company's taxable earnings. Based upon funds
available to the Company under its credit facility and the Company's anticipated
cash flow from operating activities, the Company does not currently expect these
distributions to materially impact the Company's liquidity.
RESULTS OF OPERATIONS
The following tables set forth selected financial and operating information
for each of the three years in the periods indicated:
December 31,
---------------------------------------
(Dollars in thousands, except price data) 2000 2001 2002
- ---------------------------------------------- ----------- ------------ ------------
Revenues $ 433,830 $ 409,077 $ 300,291
Operating expenses 384,791 385,915 303,083
Non-Operating income (expense) (11,259) (11,495) (17,240)
Net income (loss) 37,780 11,667 (20,032)
Adjusted EBITDA (1) 89,442 81,048 65,664
Production Volumes:
Oil and condensate (MBbl) 3,360 3,489 3,810
Natural gas (MMcf) 7,939 8,411 9,229
Oil equivalents (MBoe) 4,681 4,893 5,352
Average Prices:
Oil and condensate, with hedges ($/Bbl) $ 27.41 $ 23.87 $ 22.56
Natural gas ($/Mcf) $ 2.91 $ 3.41 $ 2.46
Oil equivalents, with hedges ($/Boe) $ 24.65 $ 22.92 $ 20.32
- ---------------
<FN>
(1) Adjusted EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization, impairment of property and exploration
expense, excluding proceeds from litigation settlements. Adjusted EBITDA is not a
measure of cash flow as determined in accordance with GAAP. Adjusted EBITDA should
not be considered as an alternative to, or more meaningful than, net income or cash
flow as determined in accordance with GAAP or as an indicator of a company's
operating performance or liquidity. Certain items excluded from adjusted EBITDA are
significant components in understanding and assessing a company's financial
performance, such as a company's cost of capital and tax structure, as well as
historic costs of depreciable assets, none of which are components of adjusted
EBITDA. The Company's computation of adjusted EBITDA may not be comparable to other
similarly titled measures of other companies. The Company believes that adjusted
EBITDA is a widely followed measure of operating performance and may also be used
by investors to measure the Company's ability to meet future debt service
requirements, if any. Adjusted EBITDA does not give effect to the Company's
exploration expenditures, which are largely discretionary by the Company and which,
to the extent expended, would reduce cash available for debt service, repayment of
indebtedness and dividends.
</FN>
YEAR ENDED DECEMBER 31, 2002, COMPARED TO YEAR ENDED DECEMBER 31, 2001
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
REVENUES
OIL AND GAS SALES
Our oil and gas sales revenue for 2002 decreased $3.4 million, or 3%, to
$108.8 million from $112.2 million in 2001 due primarily to a loss on hedging
activity of $4.9 million in 2002 and a decrease in gas prices. Gas prices
decreased $0.95/Mcf, or 28%, from an average of $3.41/Mcf in 2001 to $2.46/Mcf
in 2002.
CRUDE OIL MARKETING
We discontinued our crude oil trading activities effective May 2002. Prior
to May 2002, we entered into third party contracts to purchase and resell crude
oil. Although we no longer enter into third party contracts, we did continue to
repurchase our physical production from the Rockies and resell equivalent
barrels at Cushing to take advantage of better pricing and to reduce our credit
exposure from sales to our first purchaser. We present sales and purchases of
our production from the Rockies as crude oil marketing income and crude oil
marketing expense, respectively. For the year to date period ended December 31,
2002, we recognized revenue of $153.5 million on crude oil marketing activities
from January 2002 thru May 2002, compared to income of $245.9 million for the
twelve months ended December 31, 2001
GATHERING, MARKETING AND PROCESSING
Our 2002 gathering, marketing and processing revenues decreased $11.3
million, or 25%, to $33.7 million compared to $45.0 million for 2001. Of this
decrease, $10.3 million was attributable to operations from the Eagle Chief
Plant in Oklahoma, $1.1 million from the south Texas gathering systems, Driscoll
and Arend, $0.8 million was from the Matli, Badlands and Worland gas gathering
systems. These decreases were offset by increases in the remaining gas gathering
systems, including an increase from the North Enid Plant in Oklahoma of $1.9
million. The decreases were due to lower natural gas and natural gas liquids
prices in 2002.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenues decreased $0.3 million, or 5%,
to $5.7 million in 2002 from $6.0 million in 2001 due primarily to lower volumes
of reclaimed oil sales from our central treating unit.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses and taxes were $36.1 million for 2002, a decrease
of $0.7 million, or 2%, over the 2001 expenses of $36.8 million, primarily as a
result of decreased energy costs and taxes of $1.8 million offset by increases
in all other areas of direct costs associated with the Company's operations.
EXPLORATION EXPENSE
Our exploration expenses decreased $5.6 million, or 35%, to $10.2 million
in 2002 from $15.8 million in 2001. The decrease was attributable to a $6.9
million decrease in dry hole expenses, offset by a $1.3 million increase in
seismic and geological and geophysical expenses along with a $0.9 million
increase in other expenses.
CRUDE OIL MARKETING EXPENSE
We discontinued our crude oil trading activities effective May 2002. Prior
to May 2002, we entered into third party contracts to purchase and resell crude
oil. Although we no longer enter into third party contracts, we did continue to
repurchase our physical production from the Rockies and resell equivalent
barrels at Cushing to take advantage of better pricing and to reduce our credit
exposure from sales to our first purchaser. We present sales and purchases of
our production from the Rockies as crude oil marketing income and crude oil
marketing expense, respectively. For the year ended December 31, 2002, we
recognized an expense of $152.7 million on crude oil marketing activities from
January 2002 thru May 2002, compared to an expense of $245.0 million for the
twelve months ended December 31, 2001
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing expense for 2002 was $29.8 million,
a decrease of $6.6 million, or 18%, from the $36.4 million incurred in 2001. Of
this decrease, $8.3 million was attributable to the Eagle Chief Plant in
Oklahoma which was offset by increases of $1.8 million from the North Enid Plant
in Oklahoma and $0.8 million from the Arend gathering system in Texas. The
decrease is a result of lower natural gas and natural gas liquids prices in
2002.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations expenses increased by $1.2 million, or
22%, to $6.5 million in 2002 from $5.3 million in 2001. The increase was due to
the cost of purchasing and treating reclaimed oil for resale by $0.4 million,
salaries increased $0.3 million and general repairs and maintenance made up the
difference of $0.4 million.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A")
For the year ended December 31, 2002, total DD&A expense was $31.3 million,
a $3.6 million, or 13%, increase over the 2001 expense of $27.7 million. The
increase was due to the DD&A associated with the Farrar assets acquired in July
2001, which were depreciated for a full year in 2002 and increased depreciation
by $0.7 million. Depreciable and depletable assets increased $86.2 million from
2001 to 2002, which also increased DD&A expense.
PROPERTY IMPAIRMENTS
During 2002, we recorded property impairments of $25.7 million, compared to
$10.1 million in 2001, a $15.6 million, or 154%, increase from last year. The
majority of this impairment was related to our Bepco acquisition in the Worland
Field. The Bepco acquisition included 466 proved undeveloped ("PUD") locations
with a PV-10 value of $145.5 million. We allocated $26.7 million to these
potential locations as part of the acquisition price. We have not developed any
of the identified PUD locations during the past 4-1/2 years due to capital
constraints imposed by our development of the Cedar Hills Field. A recent review
of the PUD valuation made by our reservoir-engineering department of the
original Ryder Scott report indicates that their analysis of reserve potential
was accurate for the up-dip portion of the field, but potentially not applicable
to all identified PUD locations. We have initiated a detailed review of the PUD
locations by a consulting firm and expect to have a report during the third
quarter of 2003. This review will involve geostatistical analysis of all
available data and development of a neural network correlation to predict well
performance. Economic analysis of specific locations and subsequent
recommendation for drilling will follow this study.
We may be required to write-down the carrying value of our oil and gas
properties when oil and gas prices are depressed or unusually volatile, which
would result in a charge to earnings. Once incurred, a write-down of oil and gas
properties is not reversible at a later date. We recorded a $5.3 million FASB
121 write-down in 2001 and a $2.3 million FASB 121 write-down in 2002.
GENERAL AND ADMINISTRATIVE ("G&A")
Our G & A expense for 2002 was $10.7 million, an increase of $1.9 million,
or 22%, from G&A expenses for 2001 of $8.8 million, primarily attributable to
increased salaries and employment expenses due to an increased number of
employees in 2002.
INTEREST INCOME
Our interest income for 2002 was $0.3 million compared to $0.6 million for
2001, a decrease of $0.3 million or 50%. The decrease in the 2002 period is
attributable to lower interest rates and levels of cash invested during 2002.
INTEREST EXPENSE
Our interest expense for 2002 was $18.4 million, an increase of $2.7
million or 17% from $15.7 million in 2002. The increase in the 2002 expense was
the additional interest paid on our credit facility due to higher average debt
balances outstanding.
OTHER INCOME
Our other income decreased $2.6 million or 75%, to $0.9 million for the
year ended December 31, 2002, from $3.5 million for 2001. Other income in 2001
reflects a gain on our sale of 62 uneconomical wells for $3.4 million, an
extraordinary gain of $0.1 million on the repurchase of $3.0 million of our
senior notes in 2001, and a gain of $0.3 million on the sale of miscellaneous
assets in 2002.
NET INCOME
Our net loss for 2002 was $20.0 million, a decrease of $31.7 million,
compared to net income of $11.7 million in 2001. This decrease reflects, among
other items, the lower gas prices, which created a decrease in gas revenues of
$8.0 million, an increase in DD&A expense and property impairments of $18.6
million, a $4.5 million decrease in gathering, marketing and processing margins,
an increase in interest expense of $2.1 million, and a decrease in other income
of $2.6 million.
YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. These reclassifications do
not affect our net income.
OIL AND GAS SALES
Our oil and gas sales revenues for 2001 decreased $3.3 million, or 3%, to
$112.2 million from $115.5 million in 2000 due primarily to a decrease of $3.54
per barrel or 13% in oil prices from an average of $27.41 per barrel in 2000 to
$23.87 per barrel in 2001. This decrease in oil prices was offset by an increase
of $0.50 per Mcf or 17%, in average gas sales price from an average of $2.91 per
Mcf in 2000 to $3.41 per Mcf in 2001.
CRUDE OIL MARKETING
We recognized a decrease in revenues on crude oil purchased for resale for
2001 of $34.0 million, or 12%, to $245.8 million from $279.8 million for 2000.
Total volumes decreased approximately 1.1 million barrels along with the
decrease in oil prices resulted in the decrease in crude oil marketing revenues.
GATHERING, MARKETING AND PROCESSING
Our 2001 gathering, marketing and processing revenues increased $12.2
million, or 37%, to $45.0 million compared to $32.8 for 2000. Of this increase,
$5.3 million was attributable to operations from our south Texas gathering
systems, $2.2 million was attributable to our Eagle Chief Plant in Oklahoma, and
$1.5 million was attributable to our Matli gas gathering system in Oklahoma. The
balance of the increase was due to an increase in gas prices. These increases
were offset by our sale of the Rattlesnake and Enterprise gathering systems in
January 2000.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenues increased 5% to $6.0 million in
2001 from $5.8 million in 2000.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses and taxes were $36.8 million for 2001, a $7.0
million or 23% increase over the 2000 expenses of $29.8 million, primarily as a
result of increased production volumes and energy costs. The increase was seen
in all areas of direct costs associated with our operations, except taxes. Taxes
decreased by approximately $1.0 million due to lower oil prices.
EXPLORATION EXPENSE
Our exploration expenses increased $5.9 million, or 59%, to $15.9 million
in 2001 from $10.0 million in 2000. The increase was attributable to a $6.2
million increase in dry hole expenses and a $0.3 million decrease in seismic and
geological/geophysical expenses.
CRUDE OIL MARKETING
Our expense for crude oil purchased for resale decreased $33.8 million, or
12%, to $245.0 million in 2001 from $278.8 million in 2000. This decrease was
caused by decreased crude oil prices and reduced volumes of crude oil purchased.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing expense for 2001 was $36.4 million,
an increase of $8.1 million or 29% from the $28.3 million we incurred in 2000,
due to increased system volumes resulting from the expansion of our existing
facilities, the construction and operation of our new gathering and compression
facilities in Texas, and higher natural gas and liquid prices.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations expenses decreased by $0.3 million or
5%, to $5.3 million in 2001 from $5.6 million in 2000. The decrease was
primarily due to salt water disposal operating expenses.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A")
For the year ended December 31, 2001, our total DD&A expense was $27.7
million, an $8.1 million or 42% increase over the 2000 expense of $19.6 million.
In 2001, our lease and well DD&A was $24.0 million, an increase of $6.6 million
from $17.4 million in 2000. The increase was primarily attributable to DD&A
associated with the assets of Farrar Oil Company that we acquired in July 2001,
and an increased FASB 121 write-down. We may be required to write-down the
carrying value of our oil and gas properties when oil and gas prices are
depressed or unusually volatile, which would result in a charge to earnings.
Once incurred, a write-down of oil and gas properties is not reversible at a
later date. We recorded a $1.7 million FASB 121 write-down in 2000 and a $5.3
million FASB 121 write-down in 2001. For 2001, DD&A expense on oil and gas
properties amounted to $4.90 per Boe compared to $3.71 per Boe in 2000.
GENERAL AND ADMINISTRATIVE ("G&A")
Our G & A expense for 2001 was $8.8 million, an increase of $1.7 million,
or 23%, from G&A expenses for 2000 of $7.1 million. The increase is primarily
attributable to an increase in our employment expenses, legal costs, and our
acquisition of the assets of Farrar Oil Company in July 2001.
INTEREST INCOME
Our interest income for 2001 was $0.6 million compared to $0.8 million for
2000, a decrease of $0.2 million or 25%. The decrease in the 2001 period was
attributable to lower levels of cash invested during 2001.
INTEREST EXPENSE
Our interest expense for 2001 was $15.7 million, a decrease of $0.8
million, or 5%, from $16.5 million in 2000. The decrease in the 2001 expense was
attributable primarily to the reduction in interest rates on borrowings under
our credit facility in 2001 and the purchase and retirement of $3.0 million of
our outstanding senior notes.
OTHER INCOME
Our other income decreased $1.0 million or 21%, to $3.5 million for the
year ended December 31, 2001, from $4.5 million for 2000. This decrease reflects
a $2.4 million gain on our sale of Arkoma Basin properties and an extraordinary
gain of $0.7 million on our repurchase of senior notes during the 2000 period,
compared to the sale of 62 uneconomical wells in 2001, which resulted in a gain
of approximately $2.0 million and an extraordinary gain of $0.1 million on the
repurchase of our senior notes in 2001.
NET INCOME
Our net income for 2001 was $11.7 million, a decrease of $26.1 million
compared to $37.8 million in 2000. This decrease reflects among other items,
lower oil prices which created a decrease in oil revenues of $8.8 million, an
increase in DD&A and property impairments of $14.3 million, an increase in
production expenses and taxes of $7.0 million and an increase in exploration
expense of $4.1 million.
LIQUIDITY AND CAPITAL ASSETS
Our primary sources of liquidity have been cash flow from operating
activities, financing provided by our credit facility and by our principal
stockholder, and a private debt offering. Our cash requirements, other than for
operations, are for acquisition, exploration, exploitation and development of
oil and gas properties and debt service payments.
CASH FLOW FROM OPERATIONS
Our net cash provided by operating activities was $47.0 million for 2002, a
decrease of 24% from the $62.1 million in 2001. The decrease was primarily due
to the decrease in net income from operations, which was primarily attributable
to the decreased gas prices and crude oil hedging loss.
RESERVES AND EXPENDITURES
We spent $111.0 million in 2001 and $113.4 million in 2002 on acquisitions,
exploration, exploitation and development of oil and gas properties. Our total
estimated proved reserves of natural gas increased from 52.3 Bcf at year-end
2001 to 69.9 Bcf at December 31, 2002, and our estimated total proved oil
reserves increased from 59.7 million barrels at year-end 2001 to 63.3 million
barrels at December 31, 2002. In 2002, we sold reserves estimated to contain
approximately 12,000 barrels.
FINANCING
Our long-term debt, including current portion, was $183.4 million at
December 31, 2001, and $247.1 million at December 31, 2002. The $63.7 million,
or 35%, increase was primarily attributable to a $51.8 million increase in our
bank debt. We used the majority of the proceeds of our 2002 borrowings for
exploration and development of the Cedar Hills Field.
CREDIT FACILITY
We had $108.0 million outstanding debt balance under our credit facility at
December 31, 2002. The effective rate of interest under the credit facility was
4.8% at December 31, 2001 and 4.37% at December 31, 2002. Our credit facility,
which matures March 28, 2005, charges interest based on a rate per annum equal
to the rate at which eurodollar deposits for one, two, three or six months are
offered by the lead bank plus an applicable margin ranging from 150 to 250 basis
points or the lead bank's reference rate plus an applicable margin ranging from
25 to 50 basis points. At December 31, 2002, the borrowing base of our credit
facility was $140.0 million. The borrowing base is re-determined semi-annually.
Between December 31, 2002 and March 28, 2003, we have drawn $18.5 million
on our line of credit and currently have $126.5 million of outstanding debt on
our line of credit.
SENIOR NOTES
On July 24, 1998, we issued $150.0 million of our 10 1/4% Senior
Subordinated Notes due August 1, 2008, in a private placement. Interest on the
senior notes is payable semi annually on each February 1 and August 1. In
connection with the issuance of the senior notes, we incurred debt issuance
costs of approximately $4.7 million, which we have capitalized as other assets
and amortize on a straight-line basis over the life of the senior notes. In May
1998 we entered into a forward interest rate swap contract to hedge exposure to
changes in prevailing interest rates on our senior notes. Due to changes in
Treasury note rates, we paid $3.9 million to settle the forward interest rate
swap contract. This payment resulted in an increase of approximately 0.5% to our
effective interest rate, or an increase of approximately $0.4 million per year,
over the term of the senior notes.
During 2000, we repurchased $19.9 million principal amount of our senior
notes at a cost of $18.3 million. We wrote off $0.9 million of the issuance
costs associated with the repurchased senior notes.
During 2001, we repurchased $3.0 million principal amount of our senior
notes at a cost of $2.7 million. We wrote off $0.1 million of the issuance costs
associated with the repurchased senior notes.
CAPITAL EXPENDITURES
In 2002, we incurred $113.4 million of capital expenditures, exclusive of
acquisitions. We will initiate, on a priority basis, as many projects as cash
flow allows. We anticipate that we will initiate approximately 194 projects in
2003 for projected capital expenditures of $105.9 million. We expect to fund our
2003 capital budget of $105.9 million through cash flow from operations and our
credit facility.
STOCKHOLDER DISTRIBUTION
During 2002, we paid no dividends to our stockholders. The terms of the
indenture and our credit facility restrict our ability to pay dividends.
However, we are permitted to pay dividends to our stockholders in an amount
sufficient to cover the taxes on the taxable income passed through to the
stockholders.
HEDGING
From time to time, we and our subsidiaries utilize energy derivative
contracts to hedge the price or basis risk associated with the specifically
identified purchase or sales contracts, oil and gas production or operational
needs. Prior to January 1, 2001, we accounted for changes in the market value of
derivative instruments used for hedging as a deferred gain or loss until the
production month of the hedged transaction, at which time the gain or loss on
the derivative instruments was recognized in earnings. Effective January 1,
2001, we account for derivative instruments in accordance with SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities." The specific
accounting treatment for changes in the market value of the derivative
instruments used in hedging activities is determined based on the designation of
the derivative instruments as either a cash flow, fair value, or foreign
currency exposure hedge, and effectiveness of the derivative instruments.
Additionally, in the normal course of business, we will enter into fixed
price forward sales contracts related to our oil and gas production to reduce
our sensitivity to oil and gas price volatility. We deem forward sales contracts
that will result in physical delivery of our production to be in the normal
course of our business and we do not account for them as derivatives.
In connection with our offering of senior notes, we entered into an
interest rate hedge on which we experienced a $3.9 million loss. This loss will
result in an effective increase of approximately 0.5% in our interest costs on
the senior notes.
OTHER
We follow the "sales method" of accounting for our gas revenue, whereby we
recognize sales revenue on gas sold, regardless of whether the sales are
proportionate to our ownership in the gas produced. We recognize a liability to
the extent that we have a net imbalance in excess of our share of the reserves
in the underlying properties. Historically, our aggregate imbalance positions
have been immaterial. We believe that any future periodic settlements of gas
imbalances will have little impact on our liquidity.
We sold a number of our non-strategic oil and gas properties and other
properties over the past three years, recognizing pretax gains of approximately
$3.7 million in 2000, $3.5 million in 2001, and $0.2million in 2002
respectively. The aggregate amount of oil and gas reserves associated with these
dispositions was 290 MBbls of oil and 4,913 MMcf of natural gas.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk in the normal course of our business
operations. Due to the volatility of oil and gas prices, we, from time to time,
have entered into financial contracts to hedge oil and gas prices and may do so
in the future as a means of controlling our exposure to price changes. Most of
our financial contracts settle against either a NYMEX based price or a fixed
price.
DERIVATIVES
The risk management process we established is designed to measure both
quantitative and qualitative risks in our businesses. We are exposed to market
risk, including changes in interest rates and certain commodity prices.
To manage the volatility relating to these exposures, periodically we enter
into various derivative transactions pursuant to our policies on hedging
practices. Derivative positions are monitored using techniques such as
mark-to-market valuation and value-at-risk and sensitivity analysis.
We had a derivative contract in place at December 31, 2002, which is being
marked to market under SFAS No. 133 with changes in fair value being recorded in
earnings as such contract does not qualify for special hedge accounting nor does
such contract meet the criteria to be considered in the normal course of
business. Such contract provides for a fixed price of $24.25 per barrel on
360,000 barrels of crude oil through December 2003 when market prices exceed
$19.00 per barrel. However, if the average NYMEX spot crude oil price is $19.00
per barrel or less, no payment is required of the counterparty. If NYMEX spot
crude oil prices during the month average more than $24.25 per barrel, we pay
the excess to the counterparty. As of December 31, 2002, we have recorded a net
unrealized loss of $2.1 million.
COMMODITY PRICE EXPOSURE
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss in value arising from adverse changes in our
commodity prices.
The prices of crude oil, natural gas, and natural gas liquids are subject
to fluctuations resulting from changes in supply and demand. To partially reduce
price risk caused by these market fluctuations, we may hedge (through the
utilization of derivatives) a portion of our production and sale contracts.
Because the commodities covered by these derivatives are substantially the same
commodities that we buy and sell in the physical market, no special studies
other than monitoring the degree of correlation between the derivative and cash
markets are deemed necessary.
A sensitivity analysis has been prepared to estimate the price exposure to
the market risk of our crude oil, natural gas and natural gas liquids commodity
positions. Our daily net commodity position consists of crude inventories,
commodity purchase and sales contracts and derivative commodity instruments. The
fair value of such position is a summation of the fair values calculated for
each commodity by valuing each net position at quoted futures prices. Market
risk is estimated as the potential loss in fair value resulting from a
hypothetical 10 percent adverse change in such prices over the next 12 months.
Based on this analysis, we have no significant market risk related to our crude
trading or hedging portfolios. During the fourth quarter of 2002, we entered
into forward fixed price sales contracts in accordance with our hedging policy,
to mitigate its exposure to the price volatility associated with its crude oil
production. As of December 31, 2002, we had entered into financial contracts
covering the notational volumes set forth in the following tables for the
periods indicated:
Time Period Barrels per Month Price per Barrel
----------- ----------------- ----------------
01/03-03/03 60,000 $21.98
01/03-06/03 30,000 $24.01
01/03-01/04 30,000 $24.01
01/03-12/03 30,000 $25.08
01/03-12/03 30,000 $24.85
Each month the contractual price per barrel is compared to average NYMEX
spot crude oil price. When the contractual price is greater than the NYMEX
price, we receive an amount equal to the difference multiplied by the notational
volume. When the contractual price is less than the NYMEX price, we pay an
amount equal to the difference multiplied by the notational volume.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and for Hedging Activities", with an effective date for
periods beginning after June 15, 1999. In July 1999 the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133". As a result of SFAS No. 137,
adoption of SFAS No. 133 was required for financial statements for periods
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities",
which amends the accounting and reporting standards of SFAS No. 133 for certain
derivative instruments and hedging activities. SFAS No. 133 sweeps in a broad
population of transactions and changes the previous accounting definition of a
derivative instrument. Under SFAS No. 133 every derivative instrument is
recorded on the balance sheet as either an asset or liability measured at its
fair value. SFAS No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. During 2000, we reviewed all our contracts to identify both freestanding
and embedded derivatives that meet the criteria set forth in SFAS No. 133 and
SFAS No. 138. We adopted the new standards effective January 1, 2001. We had no
outstanding hedges or derivatives which had not been previously marked to market
through its accounting for trading activity. As a result, the adoption of SFAS
No. 133 and SFAS No. 138 had no significant impact.
INTEREST RATE RISK
Our exposure to changes in interest rates relates primarily to long-term
debt obligations. We manage our interest rate exposure by limiting our
variable-rate debt to a certain percentage of total capitalization and by
monitoring the effects of market changes in interest rates. We might utilize
interest rate derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues. Interest rate
derivatives are used solely to modify interest rate exposure and not to modify
the overall leverage of the debt portfolio. The fair value of long-term debt is
estimated based on quoted market prices and management's estimate of current
rates available for similar issues. The following table itemizes our long-term
debt maturities and the weighted-average interest rates by maturity date.
2002
Year-end
(Dollars in thousands) 2003 2004 2005 2006 Thereafter Total Fair Value
- ---------------------- ---- ---- ---- ---- ---------- ----- ----------
Fixed rate debt:
Principal amount $0 $0 $0 $0 $127,150 $127,150 $116,978
Weighted-average
Interest rate N/A N/A N/A N/A 10.25% 10.25%
Variable-rate debt:
Principal amount $0 $0 $108,000 $0 $0 $0 $108,000
Weighted-average
Interest rate 0% 0% 4.4% 0% 0% 4.4%
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on Page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Arthur Andersen LLP audited our financial statements for 2000 and 2001. As
a result of Andersen's liquidation, we changed our auditors to Ernst and Young
LLP on July 12, 2002. This change was reported in a current report on Form 8-K
dated July 16, 2002.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth names, ages and titles of the directors and
executive officers of the Company.
NAME AGE POSITION
- --------------------------- --- -------------------------------------------
Harold Hamm (1)(3)......... 57 Chairman of the Board of Directors,
President, Chief Executive Officer
and Director
Jack Stark (1)(3).......... 48 Senior Vice President--Exploration and
Director
Jeff Hume (1)(3)........... 52 Senior Vice President-Resource Development
Randy Moeder (1)(3)........ 42 President - Continental Gas, Inc.
Roger Clement (1)(2)(4).... 58 Senior Vice President, Chief Financial
Officer, Treasurer and Director
Mark Monroe (2)(3)......... 48 Director
Robert Kelley (2)(5)....... 57 Director
H. R. Sanders (2)(4)....... 70 Director
- -----------------
(1) Member of the Executive Committee
(2) Member of the Audit Committee
(3) Term expires in 2003
(4) Term expires in 2004
(5) Resigned as of 2/2003
HAROLD HAMM, L.L.M., has been President and Chief Executive Officer and a
Director of the Company since its inception in 1967 and currently serves as
Chairman of the Board. Mr. Hamm is a long-time Oklahoma Independent Petroleum
Association board member and currently its Vice President of the Western Region.
He is the founder and served as the Chairman of Save Domestic Oil, Inc.
Currently, Mr. Hamm is the President of the National Stripper Well Association,
serves on the Executive Boards of the Oklahoma Independent Petroleum Association
and the Oklahoma Energy Explorers.
JACK STARK joined the Company as Vice President of Exploration in June 1992
and was promoted to Senior Vice President and Director in May 1998. He holds a
Masters degree in Geology from Colorado State University and has 24 years of
exploration experience in the Mid-Continent, Gulf Coast and Rocky Mountain
regions. Prior to joining the Company, Mr. Stark was the exploration manager for
the Western Mid-Continent Region for Pacific Enterprises from August 1988 to
June 1992. From 1978 to 1988, he held various staff and middle management
positions with Cities Service Co. and TXO Production Corp. Mr. Stark is a member
of the American Association of Petroleum Geologists, Oklahoma Independent
Petroleum Association, Rocky Mountain Association of Geologists, Houston
Geological Society and Oklahoma Geological Society.
JEFF HUME became Senior Vice President of Resource Development of the
Company in July 2002. He had been Vice President of Drilling Operations of the
Company since September 1996 and was promoted to Senior Vice President in May
1998. From May 1983 to September 1996, Mr. Hume was Vice President of
Engineering and Operations. Prior to joining the Company, Mr. Hume held various
engineering positions with Sun Oil Company, Monsanto Company and FCD Oil
Corporation. Mr. Hume is a Registered Professional Engineer and member of the
Society of Petroleum Engineers, Oklahoma Independent Petroleum Association, and
the Oklahoma and National Professional Engineering Societies.
RANDY MOEDER has been President of Continental Gas, Inc. since January 1995
and was Vice President of Continental Gas, Inc. from November 1990 to January
1995. Mr. Moeder was Senior Vice President and General Counsel of the Company
from May 1998 to August 2000 and was Vice President and General Counsel from
November 1990 to April 1998. From January 1988 to summer 1990, Mr. Moeder was in
private law practice. From 1982 to 1988, Mr. Moeder held various positions with
Amoco Corporation. Mr. Moeder is a member of the Oklahoma Independent Petroleum
Association and the Oklahoma and American Bar Associations. Mr. Moeder is also a
Certified Public Accountant.
ROGER CLEMENT became Vice President, Chief Financial Officer, Treasurer and
a Director of the Company in March 1989 and was promoted to Senior Vice
President in May 1998. He holds a Bachelor of Business Administration degree
from the University of Oklahoma and is a Certified Public Accountant. Prior to
joining the Company, Mr. Clement was a partner in the accounting firm of Hunter
and Clement in Oklahoma City for 17 years. The firm provided accounting, tax,
audit and consulting services for various industries. Mr. Clement's clients were
primarily involved in oil and gas and real estate. He was also a 50% partner in
a construction company from 1973 to 1984 that constructed residential real
estate and small commercial properties. He is a member of the Oklahoma
Independent Petroleum Association, the American Institute of Certified Public
Accountants and the Oklahoma Society of Certified Public Accountants.
MARK MONROE was the Chief Executive Officer and President of Louis Dreyfus
Natural Gas prior to its merger with Dominion Resources in October 2001. Prior
to the formation of Louis Dreyfus Natural Gas in 1990, he was the Chief
Financial Officer of Bogert Oil Company. He currently serves as the President of
the Oklahoma Independent Petroleum Association and is a Board member of the
Oklahoma Energy Explorers. Previously Mr. Monroe served on the Domestic
Petroleum Council and the Board of the Independent Petroleum Association of
America. Mr. Monroe is a Certified Public Accountant and received his Bachelor
of Business Administration degree from the University of Texas at Austin.
ROBERT KELLEY served as Chairman of the Board of Noble Affiliates, Inc.,
from 1992 until he retired in 2000. Noble Affiliates, Inc. is an independent
energy company with exploration and production operations throughout the United
States, the Gulf of Mexico, and international operations in Argentina, China,
Ecuador, Equatorial Guinea, the Mediterranean Sea, the North Sea, and Vietnam.
Prior to October 2000 he also served as President and Chief Executive Officer of
Noble Affiliates, Inc. and its three subsidiaries, Samedan Oil Corporation,
Noble Gas Marketing, Inc., and Noble Trading, Inc. He is a Director of OG&E
Energy Corporation, a public utility headquartered in Oklahoma; and Lone Star
Technologies, Inc., a leading manufacturer of oilfield tubular goods also
located in Texas. Mr. Kelley attended the University of Oklahoma and received a
Bachelor of Business Administration degree and he is a Certified Public
Accountant. Mr. Kelley resigned from the Board effective February 10, 2003, due
to conflicts of interest with other exploration and production companies.
H. R. SANDERS, JR. served as a Director of Devon Energy Corporation from
1981 through 2000. In addition, he held the position of Executive Vice President
of Devon from 1981 until his retirement in 1997. Prior to joining Devon, Mr.
Sanders served Republic Bank of Dallas, N.A. from 1970 to 1981 as the bank's
Senior Vice President with direct responsibility for independent oil, gas and
mining loans. Mr. Sanders is a former member of the Independent Petroleum
Association of America, Texas Independent Producers and Royalty owners
Association and Oklahoma Independent Petroleum Association. He currently is a
Director on the Board of Torreador Resources Corporation and is also a past
Director of Triton Energy Corporation.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
Other Annual Securities Underlying All Other
Annual Compensation Compensation Option Compensation Compensation
------------------- ------------ --------------------- ------------
Name Year Salary Bonus (1) # of shares (2) (3)
- --------------- ---- --------- --------- ------------- ------------------- ------------
Harold Hamm (4) 2002 $0 $0 $0 0 $0
2001 $0 $0 $0 0 $0
2000 $500,000 $0 $0 0 $0
Jack Stark 2002 $161,512 $36,651 $0 8,000 $11,751
2001 $151,384 $17,996 $0 0 $11,244
2000 $139,456 $16,850 $0 32,000 $10,648
Jeff Hume 2002 $135,012 $20,450 $0 0 $22,501
2001 $125,580 $15,747 $0 0 $22,029
2000 $119,226 $15,820 $0 32,000 $21,711
Roger Clement 2002 $146,424 $32,841 $0 0 $8,544
2001 $127,500 $15,883 $0 0 $12,068
2000 $120,376 $15,406 $0 40,000 $7,558
Randy Moeder 2002 $132,619 $23,930 $0 0 $21,625
2001 $124,208 $25,197 $0 0 $21,217
2000 $121,335 $16,024 $0 25,000 $11,817
- ---------------
<FN>
(1) Represents the value of perquisites and other personal benefits in excess of the lesser of $50,000 or 10% of
annual salary and bonus. For the years ended December 31, 2000, 2001 and 2002, the Company paid no other annual
compensation to its named executive officers.
(2) The Company adopted its 2000 Stock Option Plan effective October 1, 2000, and allocated a maximum of 1,020,000
shares of Common Stock to this plan. Effective October 1, 2000, the Company granted Incentive Stock Options to
purchase 90,000 shares and Non-qualified Options to purchase 54,000 shares. Effective April 1, 2002, the Company
granted Incentive Stock Options to purchase 13,000 shares and Non-qualified Options to purchase 5,000 shares.
Effective July 1, 2002, the Company granted Incentive Stock Options to purchase 5,000 shares and Non-qualified
Options to purchase 5,000 shares.
(3) Represents contributions made by the Company to the accounts of executive officers under the Company's profit
sharing plan and under the Company's nonqualified compensation plan.
(4) Received no compensation during the calendar year 2001 and 2002.
</FN>
2002 Year-End Option Value
- ------------------------------------------------------------------------------------------
Number of Securities Underlying Value of Unexercised In-the-Money
Unexercised Options at 12/31/02(#) Options at 12/31/02($)
Name Exercisable/Unexercisable Exercisable/Unexercisable (1)
- ------------------------------------------------------------------------------------------
Jack Stark 16,000/24,000 $170,886/$250,154
Jeff Hume 16,000/16,000 $170,886/$142,874
Roger Clement 21,334/18,666 $246,516/$180,684
Randy Moeder 11,334/13,666 $104,709/$109,791
- ---------------
<FN>
(1) The value of unexercised in-the-money options at December 31, 2002, is computed as the
product of the stock value at December 31, 2002, assumed to be $21.18 per share less
the stock option exercise price, and the number of underlying securities at December
31, 2002.
</FN>
Employment Agreements
The Company does not have formal employment agreements with any of its
senior management employees.
Stock Option Plan
The Company adopted its 2000 stock option plan to encourage its key
employees by providing opportunities to participate in its ownership and future
growth through the grant of incentive stock options and nonqualified stock
options. The plan also permits the grant of options to the Company's directors.
The plan is presently administered by the Company's Board of Directors.
2000 Stock Incentive Plan
The Company adopted the 2000 stock incentive plan effective October 1,
2000. The maximum number of shares for which it may grant options under the plan
is 1,020,000 shares of common stock, subject to adjustment in the event of any
stock dividend, stock split, recapitalization, reorganization or certain defined
change of control events. Shares subject to previously expired, canceled,
forfeited or terminated options become available again for grants of options.
The shares that the Company will issue under the plan will be newly issued
shares.
The Chairman of the Board of Directors determines the number of shares and
other terms of each grant. Under its plan, the Company may grant either
incentive stock options or nonqualified stock options. The price payable upon
the exercise of an incentive stock option may not be less than 100% of the fair
market value of the Company's common stock at the time of grant, or in the case
of an incentive stock option granted to an employee owning stock possessing more
than 10% of the total combined voting power of all classes of the Company's
common stock, 110% of the fair market value on the date of grant. The Company
may grant incentive stock options to an employee only to the extent that the
aggregate exercise price of all such options under all of its plans becoming
exercisable for the first time by the employee during any calendar year does not
exceed $100,000. The Company may not grant a nonqualified stock option at an
exercise price which is less than 50% of the fair market value of the Company's
common stock on the date of grant.
Each option that the Company has granted or will grant under the plan will
expire on the date specified by the Company, but not more than ten years from
the date of grant or, in the case of a 10% shareholder, not more than five years
from the date of grant. Unless otherwise agreed, an incentive stock option will
terminate not more than 90 days, or twelve months in the event of death or
disability, after the optionee's termination of employment.
An optionee may exercise an option by giving written notice to the Company,
accompanied by full payment:
o in cash or by check, bank draft or money order payable to the Company;
o by delivering shares of the Company's common stock or other equity
securities having a fair market value equal to the exercise price; or
o a combination of the foregoing.
Outstanding options become nonforfeitable and exercisable in full
immediately prior to certain defined change of control events. Unless otherwise
determined by the Company, outstanding options will terminate on the effective
date of the Company's dissolution or liquidation.
The plan may be terminated or amended by the Company at any time subject,
in the case of certain amendments, to shareholder approval. If not earlier
terminated, the plan expires on September 30, 2010.
With certain exceptions, Section 162(m) of the Internal Revenue Code denies
a deduction to publicly held corporations for compensation paid to certain
executive officers in excess of $1.0 million per executive per taxable year
(including any deduction with respect to the exercise of an option). An
exception exists, however, for amounts received upon exercise of stock options
pursuant to certain grandfathered plans. Options granted under the Company's
plan are expected to satisfy this exception.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the beneficial
ownership of the Company's common stock as of March 28, 2003 held by:
o each of the Company's directors who owns common stock,
o each of the Company's executive officers who owns common stock,
o each person known or believed by the Company to own beneficially 5% or
more of the Company's common stock, and
o all of the Company's directors and executive officers as a group
Unless otherwise indicated, each person has sole voting and dispositive
power with respect to such shares. The number of shares of common stock
outstanding for each listed person includes any shares the individual has the
right to acquire within 60 days of this prospectus.
Shares of Ownership
Name of Beneficial Owner Common Stock Percentage
- ------------------------ ------------ ----------
Harold Hamm (1)(2) 13,037,328 90.7%
Harold Hamm DST Trust 798,917 5.6%
Harold Hamm HJ Trust 532,674 3.7%
302 North Independence
Enid, Oklahoma 73702
All executive officers and directors as a group 13,037,328 90.7%
(5 persons)
- ---------------
(1) Director
(2) Executive officer
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Set forth below is a description of transactions entered into between the
Company and certain of its officers, directors, employees and stockholders
during 2002. Certain of these transactions will continue in the future and may
result in conflicts of interest between the Company and such individuals, and
there can be no assurance that conflicts of interest will always be resolved in
favor of the Company.
OIL AND GAS OPERATIONS. In its capacity as operator of certain oil and gas
properties, the Company obtains oilfield services from affiliated companies.
These services include leasehold acquisition, well location, site construction
and other well site services, saltwater trucking, use of rigs for completion and
workover of oil and gas wells and the rental of oil field tools and equipment.
Harold Hamm is the chief executive officer and principal stockholder of each of
these affiliated companies. The aggregate amounts paid by Continental to these
affiliated companies during 2002 was $11.7 million and at December 31, 2002, the
Company owed these companies approximately $0.9 million in current accounts
payable. The services discussed above were provided at costs and upon terms that
management believes are no less favorable to the Company than could have been
obtained from unaffiliated parties. In addition, Harold Hamm and certain
companies controlled by him own interests in wells operated by the Company. At
December 31, 2002, the Company owed such persons an aggregate of $0.1 million,
representing their shares of oil and gas production sold by the Company. During
2001, in its capacity as operator of certain oil and gas properties the Company
began selling natural gas produced to a related party.
During 2002, the Company sold natural gas valued at $1.24 million to this
related party.
During December 2002, the Company entered into a long-term lease agreement
with a related party for $12.0 million. These lease arrangements were entered
into at rates equal to, or better than, could have been negotiated with a third
party.
OFFICE LEASE. The Company leases office space under operating leases
directly or indirectly from the principal stockholder and an affiliate of the
principal stockholder. In 2002, the Company paid rents associated with these
leases of approximately $421,000. The Company believes that the terms of its
lease are no less favorable to the Company than those that would be obtained
from unaffiliated parties.
PARTICIPATION IN WELLS. Certain officers and directors of the Company have
participated in, and may participate in the future in, wells drilled by the
Company, or as in the principal stockholder's case the acquisition of
properties. At December 31, 2002, the aggregate unpaid balance owed to the
Company by such officers and directors was $1,294, none of which was past due.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following financial statements of the Company and the Report of the
Company's Independent Auditors thereon are included on pages F-1 through
F-20 of this Form 10-K.
Report of Independent Auditors
Copy of Report of Independent Public Accountants (Arthur Andersen LLP)
Consolidated Balance Sheets as of December 31, 2001 and 2002
Consolidated Statement of Operations for the three years in the period
ended December 31, 2002
Consolidated Statement of Cash Flows for the three years in the period
ended December 31, 2002
Consolidated Statement of Stockholder's Equity for the three years in the
period ended December 31, 2002
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
None.
3. EXHIBITS:
2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc.
dated October 1, 2000. [2.1](4)
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc. [3.1](1)
3.2 Amended and Restated Bylaws of Continental Resources, Inc. [3.2] (1)
3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3] (1)
3.4 Bylaws of Continental Gas, Inc., as amended and restated. [3.4] (1)
3.5 Certificate of Incorporation of Continental Crude Co. [3.5] (1)
3.6 Bylaws of Continental Crude Co. [3.6] (1)
4.1 Restated Credit Agreement dated April 21, 2000 between Continental
Resources, Inc. and Continental Gas, Inc., as Borrowers and MidFirst
Bank as Agent (the "Credit Agreement") [4.4] (3)
4.1.1 Form of Consolidated Revolving Note under the Credit Agreement [4.4]
(3)
4.1.2 Second Amended and Restated Credit Agreement among Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and MidFirst Bank, dated July 9,
2001.[10.1](5)
4.1.3 Third Amended and Restated Credit Agreement among Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and MidFirst Bank, dated January 17,
2002. [4.13] (7)
4.1.4 Fourth Amended and Restated Credit Agreement dated March 28, 2002,
among the Registrant, Union Bank of California, N. A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1] (8)
4.2 Indenture dated as of July 24, 1998 between Continental Resources,
Inc., as Issuer, the Subsidiary Guarantors named therein and the
United States Trust Company of New York, as Trustee [4.3] (1)
10.1 Unlimited Guaranty Agreement dated March 28, 2002 [10.2] (8)
10.2 Security Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.3] (8)
10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent [10.4] (8)
10.4 Conveyance Agreement of Worland Area Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April
23, 1984, to Continental Resources, Inc. [10.4](2)
10.5 Purchase Agreement signed January 2000, effective October 1, 1999, by
and between Patrick Energy Corporation as Buyer and Continental
Resources, Inc. as Seller [10.5](2)
10.6+ Continental Resources, Inc. 2000 Stock Option Plan. [10.6](4)
10.7+ Form of Incentive Stock Option Agreement. [10.7](4)
10.8+ Form of Non-Qualified Stock Option Agreement. [10.8](4)
10.9 Purchase and Sales Agreement between Farrar Oil Company and Har-Ken
Oil Company, as Sellers, and Continental Resources of Illinois, Inc.
as Purchaser, dated May 14, 2001.[2.1](5)
10.10 Collateral Assignment of Contracts dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as Agent. [10.5] (8)
12.1 Statement re computation of ratio of debt to Adjusted EBITDA [12.1]
(*)
12.2 Statement re computation of ratio of earning to fixed charges [12.2]
(*)
12.3 Statement re computation of ratio of Adjusted EBITDA to interest
expense [12.3] (*)
21.0 Subsidiaries of Registrant.[21](6)
99.1 Letter to the Securities and Exchange Commission dated March 28, 2002,
regarding the audit of the Registrant's financial statements by Arthur
Andersen LLP. [99.1] (7)
- ---------------
+ Represents management compensatory plans or agreements.
* Filed herewith
(1) Filed as an exhibit to the Company's Registration Statement on Form S-4, as
amended (No. 333-61547) which was filed with the Securities and Exchange
Commission. The exhibit number is indicated in brackets and is incorporated
herein by reference.
(2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1999. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended March 31, 2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(4) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal quarter ended December 31, 2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current report on Form 8-K dated July 18, 2001. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended June 30, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(7) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(8) Filed as an exhibit to current report on Form 8-K dated April 11,2002. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(b) REPORTS ON FORM 8-K
None
SIGNATURES
Pursuant to the requirements of Section 13 and 15 (d) 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.
March 28, 2003 CONTINENTAL RESOURCES, INC.
By HAROLD HAMM
Harold Hamm
Chairman of the Board, President
And Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in capacities and on the dates indicated.
Signatures Title Date
---------- ----- ----
HAROLD HAMM
Harold Hamm Chairman of the Board, March 28, 2003
President, Chief Executive
Officer (principal executive
officer) and Director
ROGER V. CLEMENT
Roger V. Clement Senior Vice President and March 28, 2003
Chief Financial Officer
(principal financial officer
and principal accounting
officer), Treasurer,
and Director
JACK STARK
Jack Stark Senior Vice President of Exploration March 28, 2003
and Director
H. R. SANDERS, JR.
H. R. Sanders, Jr. Director March 28, 2003
MARK MONROE
Mark Monroe Director March 28, 2003
Supplemental Information to be Furnished With Reports Pursuant to Section
15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to
Section 12 of the Act.
The Company has not sent, and does not intend to send, an annual report to
security holders covering its last fiscal year, nor has the Company sent a proxy
statement, form of proxy or other proxy soliciting material to its security
holders with respect to any annual meeting of security holders.
CERTIFICATIONS FOR FORM 10-K
I, Harold Hamm, Chief Executive Officer, certify that:
(1) I have reviewed this annual report on Form 10-K of Continental Resources,
Inc. ("Registrant");
(2) Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
(3) Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
(4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluations as of the Evaluation Date;
(5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls: and
(6) The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
CONTINENTAL RESOURCES, INC.
Date: March 28, 2003 By: HAROLD HAMM
Harold Hamm
Chief Executive Officer
CERTIFICATIONS FOR FORM 10-K
I, Roger V. Clement, Vice President and Chief Financial Officer, certify that:
(1) I have reviewed this annual report on Form 10-K of Continental Resources,
Inc. ("Registrant");
(2) Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
(3) Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
(4) The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluations as of the Evaluation Date;
(5) The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls: and
(6) The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
CONTINENTAL RESOURCES, INC.
Date: March 28, 2003 By: ROGER V. CLEMENT
Roger V. Clement
Vice President and Chief Financial Officer
INDEX OF FINANCIAL STATEMENTS
Report of Independent Auditors.............................................F - 3
Copy of Report of Independent Public Accountants (Arthur Andersen LLP).....F - 3
Consolidated Balance Sheets as of December 31, 2001 and 2002...............F - 3
Consolidated Statements of Operations for the Years Ended December 31,
2000, 2001 and 2002...................................................F - 5
Consolidated Statements of Stockholders' Equity
for the Years Ended December 31, 2000, 2001 and 2002..................F - 6
Consolidated Statements of Cash Flows for the Years Ended December 31,
2000, 2001 and 2002...................................................F - 7
Notes to Consolidated Financial Statements.................................F - 8
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors
of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheet of Continental
Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31,
2002, and the related consolidated statements of operations, stockholders'
equity and cash flows for the year then ended. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audit. The consolidated financial statements of
Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries as of
December 31, 2001 and for each of the two years in the period then ended were
audited by other auditors who ceased operations. Those auditors expressed an
unqualified opinion on those financial statements in their report dated February
15, 2002.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provided a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Continental Resources, Inc. and subsidiaries at December 31, 2002, and the
consolidated results of their operations and their cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States.
ERNST & YOUNG LLP
Oklahoma City, Oklahoma,
March 14, 2003
INFORMATION REGARDING PREDECESSOR INDEPENDENT PUBLIC ACCOUNTANTS' REPORT
The following report is a copy of a previously issued report by Arthur Andersen
LLP ("Andersen"). The report has not been reissued by Andersen nor has Andersen
consented to its inclusion in this annual report on Form 10-K. The Andersen
report refers to the consolidated balance sheet as of December 31, 2000 and the
consolidated statements of operations, stockholders' equity, and cash flows for
the year ended December 31, 1999, which are no longer included in the
accompanying financial statements.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Continental
Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31,
2000 and 2001, 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 consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Continental
Resources, Inc. and subsidiaries as of December 31, 2000 and 2001, and the
results of their operations and their 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.
Oklahoma City, Oklahoma ARTHUR ANDERSEN LLP
February 15, 2002
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
December 31,
------------------------------------
CURRENT ASSETS: 2001 2002
------------------ ----------------
Cash $ 7,225 $ 2,520
Accounts receivable -
Oil and gas sales 7,731 14,756
Joint interest and other, net 10,526 7,884
Inventories 6,321 6,700
Prepaid expenses 487 482
Fair value of derivative contracts - 628
------------------ ----------------
Total current assets 32,290 32,970
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties, based on
successful efforts accounting
Producing properties 395,559 488,432
Nonproducing leaseholds 50,889 33,781
Gas gathering and processing facilities 28,176 33,113
Service properties, equipment and other 17,427 18,430
------------------ ----------------
Total property and equipment 492,051 573,756
Less - Accumulated depreciation,
depletion and amortization (174,720) (205,853)
------------------ ----------------
Net property and equipment 317,331 367,903
OTHER ASSETS:
Debt issuance costs 4,851 5,796
Other assets 13 8
------------------ ----------------
Total other assets 4,864 5,804
------------------ ----------------
Total assets $ 354,485 $ 406,677
================== ================
The accompanying notes are an integral part of these consolidated balance
sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
December 31,
---------------------------
CURRENT LIABILITIES: 2001 2002
------------- ------------
Accounts payable $ 22,576 $ 26,665
Current debt 5,400 2,400
Revenues and royalties payable 3,404 5,299
Accrued liabilities and other 9,906 10,320
Fair Value of derivative contracts - 2,082
------------- ------------
Total current liabilities 41,286 46,766
LONG-TERM DEBT, net of current portion 177,995 244,705
OTHER NONCURRENT LIABILITIES 91 125
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 1,000,000 shares
authorized, 0 shares issued and outstanding - -
Common stock, $0.01 par value, 20,000,000 shares
authorized, 14,368,919 shares issued and outstanding 144 144
Additional paid-in-capital 25,087 25,087
Retained earnings 109,882 89,850
------------- ------------
Total stockholders' equity 135,113 115,081
------------- ------------
Total liabilities and stockholders' equity $ 354,485 $ 406,677
============= ============
The accompanying notes are an integral part of these consolidated balance
sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars in thousands, except share data)
December 31,
----------------------------------------------
REVENUES: 2000 2001 2002
-------------- -------------- --------------
Oil and gas sales $ 115,478 $ 112,170 $ 108,752
Crude oil marketing income 279,834 245,872 153,547
Change in derivative fair value - - (1,455)
Gathering, marketing and processing 32,758 44,988 33,708
Oil and gas service operations 5,760 6,047 5,739
-------------- -------------- --------------
Total revenues 433,830 409,077 300,291
OPERATING COSTS AND EXPENSES:
Production expenses 20,301 28,406 28,383
Production taxes 9,506 8,385 7,729
Exploration expenses 9,965 15,863 10,229
Crude oil marketing expenses 278,809 245,003 152,718
Gathering, marketing and processing 28,303 36,367 29,783
Oil and gas service operations 5,582 5,294 6,462
Depreciation, depletion and amortization 19,552 27,731 31,380
Property impairments 5,631 10,113 25,686
General and administrative 7,142 8,753 10,713
-------------- -------------- --------------
Total operating costs and expenses 384,791 385,915 303,083
OPERATING INCOME (LOSS) 49,039 23,162 (2,792)
OTHER INCOME (EXPENSES):
Interest income 756 630 285
Interest expense (16,514) (15,674) (18,401)
Other income, net 4,499 3,549 876
-------------- -------------- --------------
Total other income (expense) (11,259) (11,495) (17,240)
-------------- -------------- --------------
NET INCOME (LOSS) $ 37,780 $ 11,667 $ (20,032)
============== ============== ==============
EARNINGS PER COMMON SHARE:
Basic $ 2.63 $ 0.81 $ (1.39)
============== ============== ==============
Diluted $ 2.62 $ 0.81 $ (1.39)
============== ============== ==============
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002
(dollars in thousands)
Additional Total
Shares Common Paid-In Retained Stockholders'
Outstanding Stock Capital Earning Equity
------------- ------------ ------------ ------------- --------------
BALANCE, December 31, 1999 14,368,919 $ 144 $ 25,087 $ 61,435 $ 86,666
Net Income - - - 37,780 37,780
Dividends paid - - - (1,000) (1,000)
------------- ------------ ------------ ------------- --------------
BALANCE, December 31, 2000 14,368,919 $ 144 $ 25,087 $ 98,215 $ 123,446
------------- ------------ ------------ ------------- --------------
Net Income - - - 11,667 11,667
------------- ------------ ------------ ------------- --------------
BALANCE, December 31, 2001 14,368,919 $ 144 $ 25,087 $ 109,882 $ 135,113
------------- ------------ ------------ ------------- --------------
Net Loss - - - (20,032) (20,032)
------------- ------------ ------------ ------------- --------------
BALANCE, December 31, 2002 14,368,919 $ 144 $ 25,087 $ 89,850 $ 115,081
============= ============ ============ ============= ==============
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESORUCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMETNS OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002
2000 2001 2002
--------------- -------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 37,780 $ 11,667 $ (20,032)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Depreciation, depletion and amortization 19,552 27,731 31,380
Impairment of properties 4,786 6,595 25,686
Change in derivative fair value - - 1,455
Amortization of debt issuance costs 728 534 1,171
Gain on sale of assets (3,719) (3,460) (223)
Dry hole costs and impairment of undeveloped leases 7,119 12,996 5,880
Cash provided by (used in) changes in assets and liabilities-
Accounts receivable (5,591) 7,360 (4,383)
Inventories (876) (1,333) (379)
Prepaid expenses 1,481 (278) 5
Accounts payable 8,716 5,411 4,089
Revenues and royalties payable 315 (3,776) 1,895
Accrued liabilities and other 599 (469) 414
Other noncurrent assets 1,373 435 5
Other noncurrent liabilities - - 34
--------------- -------------- --------------
Net cash provided by operating activities 72,263 63,413 46,997
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (50,711) (68,123) (106,532)
Gas gathering and processing facilities and service
properties, equipment and other (1,200) (6,645) (6,260)
Purchase of oil and gas properties - (36,535) (655)
Proceeds from sale of assets 7,665 4,639 152
--------------- -------------- --------------
Net cash used in investing activities (44,246) (106,384) (113,295)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 37,000 52,245 138,830
Repayment of Senior Subordinated Notes (19,850) (3,000)
Repayment of line of credit and other (47,436) (6,200) (75,120)
Debt issuance costs - - (2,117)
Repayment of short-term debt due to stockholder - - -
Payment of cash dividend (1,000) - -
--------------- -------------- --------------
Net cash provided by (used in) financing activities (31,286) 43,045 61,593
NET INCREASE (DECREASE) IN CASH (3,269) 74 (4,705)
CASH, beginning of year 10,421 7,151 7,225
--------------- -------------- --------------
CASH, end of year $ 7,152 $ 7,225 $ 2,520
=============== ============== ==============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 16,615 $ 15,269 $ 16,386
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
ORGANIZATION
Continental Resources, Inc. ("CRI") was incorporated in Oklahoma on
November 16, 1967, as Shelly Dean Oil Company. On September 23, 1976, the name
was changed to Hamm Production Company. In January 1987, the Company acquired
all of the assets and assumed the debt of Continental Trend Resources, Inc.
Affiliated entities, J.S. Aviation and Wheatland Oil Co. were merged into Hamm
Production Company, and the corporate name was changed to Continental Trend
Resources, Inc. at that time. In 1991, the Company's name was changed to
Continental Resources, Inc.
CRI has three wholly owned subsidiaries, Continental Gas, Inc. ("CGI"),
Continental Resources of Illinois, Inc. ("CRII") and Continental Crude Co.
("CCC"). CGI was incorporated in April 1990, CRII was incorporated in June 2001
for the purpose of acquiring the assets of Farrar Oil Company and Har-Ken Oil
Company and CCC was incorporated in May 1998. Since its incorporation, CCC has
had no operations, has acquired no assets and has incurred no liabilities.
CRI and CRII's principal business is oil and natural gas exploration,
development and production. CRI and CRII have interests in approximately 2,460
wells and serve as the operator in the majority of these wells. CRI and CRII's
operations are primarily in Oklahoma, North Dakota, South Dakota, Montana,
Wyoming, Texas, Illinois, Mississippi and Louisiana. In July 1998, CRI began
entering into third party contracts to purchase and resell crude oil at prices
based on current month NYMEX prices, current posting prices or at a stated
contract price.
CGI is engaged principally in natural gas marketing, gathering and
processing activities and currently operates eight gas gathering systems and
three gas processing plants in its operating areas. In addition, CGI
participates with CRI in certain oil and natural gas wells.
Basis of Presentation
The accompanying consolidated financial statements include the accounts and
operations of CRI, CRII, CGI and CCC (collectively the "Company"). All
significant intercompany accounts and transactions have been eliminated in the
consolidated financial statements. Certain reclassifications have been made to
prior year amounts to conform to the current year presentation.
Recently Issued Accounting Pronouncements
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method and the liability
should be accreted to its face amount. The Company adopted SFAS No. 143 on
January 1, 2003. The primary impact of this standard relates to oil and gas
wells on which the Company has a legal obligation to plug and abandon the wells.
Prior to SFAS No. 143, the Company had not recorded an obligation for these
plugging and abandonment costs due to its assumption that the salvage value of
the surface equipment would substantially offset the cost of dismantling the
facilities and carrying out the necessary clean-up and reclamation activities.
The adoption of SFAS No. 143 on January 1, 2003, resulted in a net increase to
Property and Equipment and Asset Retirement Obligations of approximately $39.3
million and $35.2 million, respectively, as a result of the Company separately
accounting for salvage values and recording the estimated fair value of its
plugging and abandonment obligations on the balance sheet. The impact of
adopting SFAS No. 143 has been accounted for through a cumulative effect
adjustment that amounted to $4.1 million increase to net income recorded on
January 1, 2003. The increase in expense resulting from the accretion of the
asset retirement obligation and the depreciation of the additional capitalized
well costs is expected to be substantially offset by the decrease in
depreciation from the Company's consideration of the estimated salvage values in
the calculation.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS No. 144 requires (a) that an impairment
loss be recognized only if the carrying amount of a long-lived asset is not
recoverable from its undiscounted cash flows and (b) that the measurement of any
impairment loss be the difference between the carrying amount and the fair value
of the long-lived asset. SFAS No. 144 also requires companies to separately
report discontinued operations and extends that reporting to a component of an
entity that either has been disposed of (by sale, abandonment, or in a
distribution to owners) or is classified as held for sale.
Assets to be disposed of are reported at the lower of the carrying amount
or fair value less costs to sell. The Company adopted SFAS No. 144 effective
January 1, 2002. The adoption of this new standard did not have a material
impact on the Company's consolidated financial position or results of
operations.
As of May 15, 2002, the Company adopted SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. SFAS 145 rescinds the automatic treatment of gains and losses from
extinguishments of debt as extraordinary unless they meet the criteria for
extraordinary items as outlined in Accounting Principles Board Opinion No. 30,
Reporting the Results of Operations, Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions. SFAS 145 also requires sale-leaseback accounting for
certain lease modifications that have economic effects similar to a
sale-leaseback transaction and makes various corrections to existing
pronouncements. The adoption of SFAS 145 did not have a material effect on the
Company's consolidated financial position or results of operations.
In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. SFAS No. 146 addresses financial accounting
and reporting for costs associated with exit and disposal activities and
supersedes Emerging Issues Task Force (EITF) Issue No. 94-3, Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146
requires recognition of a liability for a cost associated with an exit or
disposal activity when the liability is incurred, as opposed to when the entity
commits to an exit plan under EITF 94-3. SFAS No. 146 also establishes that the
liability should initially be measured and recorded at fair value. Adoption of
SFAS No. 146 is required for exit and disposal activities initiated after
December 31, 2002. The Company adopted this new standard effective January 1,
2003. The impact on the financial position and results of operations of adopting
this new standard was not material.
In October 2002, the Emerging Issues Task Force (EITF) reached a consensus
on Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy
Trading and Risk Management Activities. The consensus rescinded EITF Issue No.
98-10, Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. The October 2002 consensus precludes mark-to-market accounting for
all energy trading contracts not within the scope of SFAS No. 133, Accounting
for Derivative and Hedging Activities. The consensus to rescind EITF 98-10 is
applicable for fiscal periods beginning after December 15, 2002 (early adoption
allowed), except that energy trading contracts not within the scope of SFAS No.
133 and executed after October 25, 2002, but prior to the implementation of the
consensus, are not permitted to apply mark-to-market accounting. The EITF also
reached a consensus that gains and losses (whether realized or unrealized) on
derivative instruments within the scope of SFAS No. 133 should be shown net in
the income statement if the derivative instruments are purchased for trading
purposes with the exception of derivative contracts that culminate in the
physical delivery of a commodity and meet the criteria of EITF 99-19, Reporting
Revenue Gross as a Principal versus Net as an Agent. The Company elected to
early adopt this consensus on October 1, 2002. As the Company has no contracts
outside the scope of SFAS No.133 that are being marked to market and as the
Company's prior policy related to the presentation of gains and losses on
derivative contracts entered into for trading purposes is consistent with the
requirements of EITF 02-3, the adoption of EITF 02-3 had no material impact on
the Company. As further discussed in Derivatives below, the Company has
discontinued its trading activities as of May 2002.
Accounts Receivable
The Company operates exclusively in the oil and natural gas exploration and
production, gas gathering and processing and gas marketing industries. Joint
interest and oil and gas sales receivables are generally unsecured. The
Company's joint interest receivables at December 31, 2001 and 2002, are recorded
net of an allowance for doubtful accounts of approximately $359,000 and
$544,000, respectively, in the accompanying consolidated balance sheets.
Inventories
Inventories consist primarily of tubular goods, production equipment and
crude oil in tanks, which are stated at the lower of average cost or market. At
December 31, 2001 and 2002, tubular goods and production equipment totaled
approximately $5,071,000 and $5,572,000, respectively and crude oil in tanks
totaled approximately $1,250,000 and $1,128,000, respectively.
Property and Equipment
The Company utilizes the successful efforts method of accounting for oil
and gas activities whereby costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. These costs are amortized
to operations on a unit-of-production method based on proved developed oil and
gas reserves, allocated property by property, as estimated by petroleum
engineers. Geological and geophysical costs, lease rentals and costs associated
with unsuccessful exploratory wells are expensed as incurred. Nonproducing
leaseholds are periodically assessed for impairment, based on exploration
results and planned drilling activity. Maintenance and repairs are expensed as
incurred, except that the cost of replacements or renewals that expand capacity
or improve production are capitalized. Gas gathering systems and gas processing
plants are depreciated using the straight-line method over an estimated useful
life of 14 years. Service properties and equipment and other are depreciated
using the straight-line method over estimated useful lives of 5 to 40 years.
Income Taxes
The Company filed a consolidated income tax return based on a May 31 fiscal
tax year-end through May 31, 1997, and deferred income taxes were provided for
temporary differences between financial reporting and income tax bases of assets
and liabilities. Effective June 1, 1997, the Company converted to an
S-Corporation under Subchapter S of the Internal Revenue Code. As a result,
income taxes attributable to Federal taxable income of the Company after May 31,
1997, if any, will be payable by the stockholders of the Company.
Earnings per Common Share
Basic earnings per common share is computed by dividing income available to
common stockholders by the weighted-average number of shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if diluted stock options were exercised calculated using the treasury
stock method. The weighted-average number of shares used to compute basic
earnings per common share was 14,368,919 in 2000, 2001 and 2002. The
weighted-average number of shares used to compute diluted earnings per share for
2000 and 2001 was 14,393,132. The outstanding stock options (see Note 7) were
not considered in the diluted earnings per share calculation for 2002, as the
effect would be antidilutive. There were no common stock equivalents or
securities outstanding during 1999 that would result in material dilution.
Accounting for Derivatives
Non-Trading Activity
The Company periodically utilizes derivative contracts to hedge the price
or basis risk associated with specifically identified purchase or sales
contracts, oil and gas production or operational needs. As of January 1, 2001,
the Company accounts for its non-trading derivative activities under the
guidance provided by SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. Prior to January 1, 2001, the Company accounted for changes
in the market value of derivative instruments used for hedging as a deferred
gain or loss until the production month of the hedged transactions, at which
time the gain or loss on the derivative instrument was recognized in earnings.
Under SFAS No. 133, the Company recognizes all of its derivative instruments as
assets or liabilities in the balance sheet at fair value with such amounts
classified as current or long-term based on their anticipated settlement. The
accounting for the changes in fair value of a derivative depends on the intended
use of the derivative and resulting designation. For derivative instruments that
are designated and qualify as a fair value hedge, the gain or loss on the
derivative instrument as well as the offsetting loss or gain on the hedged item
attributable to the hedged risk are recognized in the same line item associated
with the hedged item in current earnings during the period of the change in fair
values. For derivatives that are designated and qualify as a cash flow hedge,
the effective portion of the change in fair value of the derivative instrument
is reported as a component of accumulated other comprehensive income and
recognized into earnings in the same period during which the hedged transaction
affects earnings. The ineffective portion of a derivative's change in fair value
is recognized currently in earnings. Hedge effectiveness is measured at least
quarterly based on relative changes in fair value between the derivative
contract and hedged item during the period of hedge designation. Forecasted
transactions designated as the hedged item in a cash flow hedge are regularly
evaluated to assess whether they continue to be probable of occurring. If the
forecasted transaction is no longer probable of occurring, any gain or loss
deferred in accumulated other comprehensive income is recognized in earnings
currently.
On January 1, 2001, the Company had no outstanding derivatives that had not
been previously marked to market through its accounting for trading activity
(see Crude Oil Marketing below). As a result, the initial adoption of SFAS No.
133 had no significant impact on the Company's financial position or results of
operations.
Crude Oil Marketing
During 1998, the Company began trading crude oil, exclusive of its own
production, with third parties, under fixed and variable priced physical
delivery contracts with terms extending out less than one year. Crude oil
marketing activities are accounted for in accordance with SFAS No. 133 and EITF
98-10, Accounting for Energy Trading and Risk Management Activities. The
adoption of SFAS No. 133 as of January 1, 2001, had no impact on the Company's
accounting for derivative contracts used in its crude oil marketing activities
as such contracts were recorded at fair value under EITF 98-10 which was issued
prior to SFAS No. 133. Under the guidance provided by SFAS No. 133 and EITF
98-10, all energy and energy related contracts are valued at fair value and
recorded as assets or liabilities in the consolidated balance sheet, classified
as current or long-term based on their anticipated settlement. Unrealized gains
and losses from changes in the fair value of open contracts are included in oil
and gas sales in the consolidated income statement. Crude oil marketing
contracts that result in delivery of a commodity and meet the requirements of
EITF 99-19, Reporting Revenues Gross as a Principal or Net as an Agent, are
included as crude oil marketing income or expense in the consolidated income
statement depending on whether the contract relates to the sale or purchase of
the commodity. Effective May 2002, the Company no longer enters into third party
contracts to purchase and resell crude oil, however we did continue to
repurchase our physical production from the Rockies and resell equivalent
barrels at Cushing to take advantage of better pricing and to reduce our credit
exposure from sales to our first purchaser. We have stated these purchases and
sales at gross in crude oil marketing. Also see Recently Issued Accounting
Pronouncements for further discussion of the accounting for the Company's energy
trading activities.
Oil and Gas Sales and Gas Balancing Arrangements
The Company sells oil and natural gas to various customers, recognizing
revenues as oil and gas is produced and sold. The Company uses the sales method
of accounting for gas imbalances in those circumstances were it has
underproduced or overproduced its ownership percentage in a property. Under this
method, a receivable or liability is recognized only to the extent that an
imbalance cannot be recouped from the reserves in the underlying properties. The
Company's aggregate imbalance positions at December 31, 2001 and 2002, were not
material. Changes for gathering and transportation are included in production
expenses.
Significant Customer
During 2000, 2001 and 2002, approximately 22.8%, 17.8% and 42.4%,
respectively, of the Company's total revenues were derived from sales made to a
single customer.
Fair Value of Financial Instruments
The Company's financial instruments consist primarily of cash, trade
receivables, trade payables and bank debt. The carrying value of cash, trade
receivables and trade payables are considered to be representative of their
respective fair values, due to the short maturity of these instruments. The fair
value of long-term debt, less the senior subordinated notes discussed in Note 4,
approximates its carrying value based on the borrowing rates currently available
to the Company for bank loans with similar terms and maturities.
Business Segments
The Company operates in one business segment pursuant to Statement of
Financial Accounting Standards (SFAS) No. 131, "Disclosure About Segments of an
Enterprise and Related Information."
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Of the estimates and assumptions that affect reported results, the estimate of
the Company's oil and natural gas reserves, which is used to compute
depreciation, depletion, amortization and impairment on producing oil and gas
properties, is the most significant.
Stock Based Compensation
The Company applies APB Opinion No. 25 in accounting for its fixed price
stock options. Under APB 25, no compensation expense is recognized relating to
stock options issued under a fixed price plan with a strike price at or above
the fair market value of the underlying shares of common stock at the date of
grant. For stock options issued with a strike price below the fair market value
of the underlying shares of common stock, compensation expense is recognized
over the vesting period equal to the fair market value of the common stock at
the date of grant less the strike price. During 2001 and 2002, compensation
expenses related to in the money options were immaterial.
Had the Company determined compensation expense based on the fair value at
the grant date for its stock options under SFAS No. 123, the Company's net
income (loss) would have been adjusted as indicated below.
- --------------------------------------------------------------------------------
(dollars in thousands except per share amounts) 2001 2002
---- ----
Net Income (Loss):
As Reported $11,667 $(20,032)
Pro Forma $11,575 $(20,117)
Basic Earnings Per Share:
As Reported $ 0.81 $ (1.39)
Pro Forma $ 0.81 $ (1.40)
Diluted Earnings Per Share:
As Reported $ 0.81 $ (1.39)
Pro Forma $ 0.81 $ (1.39)
2. FORWARD SALES CONTRACTS:
We are exposed to market risk in the normal course of our business
operations. Due to the volatility of oil and gas prices, we, from time to time,
have entered into financial contracts to hedge oil and gas prices and may do so
in the future as a means of controlling our exposure to price changes. Most of
our financial contracts settle against either a NYMEX based price or a fixed
price. As the contracts provide for physical delivery of its production, the
Company has deemed these contracts to be sales in the normal course of business
and it does not account for these contracts as derivatives. Revenues from fixed
price sales contracts in the normal course of business are recognized as
production occurs. As of December 31, 2002, we had entered into contracts
covering the notional volumes set forth in the following table for the periods
indicated:
TIME PERIOD BARRELS PER MONTH PRICE PER BARREL
1/03-3/03 60,000 $21.98
1/03-6/03 30,000 $24.01
1/03-1/04 30,000 $24.01
1/03-12/03 30,000 $25.08
1/03-12/03 30,000 $24.85
In August 2002, we elected to convert the fixed price on 200,000 barrels of
crude oil covered under these firm commitments to a variable price by entering
into fixed price purchase contracts at an average price of $25.44 per barrel.
These derivative purchase contracts have been designated as fair value hedges of
a portion of the volumes covered under the firm commitments. As required by SFAS
No. 133, changes in the fair value of the firm commitment occurring subsequent
to the time the hedges were designated have been recorded in the accompanying
balance sheet. As the critical terms of the derivative contracts and firm
commitment coincide, changes in the value of the firm commitment are perfectly
offset by changes in the value of the derivative contracts.
At December 31, 2002, we had a crude oil derivative contract in place,
which is being marked to market under SFAS No. 133 with changes in fair value
being recorded in earnings as such contract does not qualify for special hedge
accounting nor does such contract meet the criteria to be considered in the
normal course of business. The contract provides for a fixed price of $24.25 per
barrel on 360,000 barrels of crude oil through December 2003 when market prices
exceed $19.00 per barrel. However, if the average NYMEX spot crude oil price is
$19.00 per barrel or less, no payment is required to the counterparty. If NYMEX
sport crude oil prices during a month average more than $24.25 per barrel, we
pay the excess to the counterparty. At December 31, 2002, we have recorded a net
unrealized loss of $1.5 million on this contract
3. ACQUISITION OF PRODUCING PROPERTIES:
On July 9, 2001, the Company's subsidiary, CRII, purchased the assets of
Farrar Oil Company, Inc. and Har-Ken Oil Company (collectively "Farrar") for
$33.7 million using funds borrowed under the Company's credit facility. This
purchase was accounted for as a purchase and the cost of the acquisition was
allocated to the acquired assets and liabilities. The allocation of the $33.7
million purchase price on July 9, 2001, was as follows:
Current assets $ 950
Producing properties 30,603
Non-producing properties 1,117
Service properties 1,000
--------
$ 33,670
The unaudited pro forma information set forth below includes the operations
of Farrar assuming the acquisition of Farrar by CRII occurred at the beginning
of the periods presented. The unaudited pro forma information is presented for
information only and is not necessarily indicative of the results of operations
that actually would have achieved had the acquisition been consummated at that
time:
Pro Forma (Unaudited)
For the twelve months ended December 31, 2001
($ in thousands except share data) Farrar CRI Consolidated
- ---------------------------------- ------- ------------ ------------
Revenue $18,219 $263,934 $282,153
Net Income $ 7,700 $ 12,119 $ 19,819
Earnings Per Common Share
Basic $0.54 $0.84 $1.38
Diluted $0.54 $0.84 $1.38
4. LONG-TERM DEBT:
Long-term debt as of December 31, 2001 and 2002, consists of the following
(in thousands):
2001 2002
---- ----
10.25% Senior Subordinated Notes due Aug. 2008 (a) $ 127,150 $ 127,150
Credit Facility due March 28, 2005 (b) 56,245 108,000
Capital Lease Agreement (c) - 11,955
--------- ---------
Outstanding debt 183,395 247,105
Less Current portion 5,400 2,400
--------- ---------
Total long-term debt $ 177,995 $ 244,705
========= =========
- ----------------
<FN>
(a) On July 24, 1998, the Company consummated a private placement of $150.0
million of 10-1/4% Senior Subordinated Notes ("the Notes") due August 1,
2008, in a private placement under Securities Act Rule 144A. Interest on
the Notes is payable semi-annually on each February 1 and August 1. In
connection with the issuance of the Notes, the Company incurred debt
issuance costs of approximately $4.7 million, which has been capitalized as
other assets and is being amortized on a straight-line basis over the life
of the Notes. In May 1998 the Company entered into a forward interest rate
swap contract to hedge exposure to changes in prevailing interest rates on
the Notes. Due to changes in treasury note rates, the Company paid $3.9
million to settle the forward interest rate swap contract. This payment
results in an increase of approximately 0.5% to the Company's effective
interest rate over the term of the Notes. Effective November 14, 1998, the
Company registered the Notes through a Form S-4 Registration Statement
under the Securities Exchange Act of 1933. During 2000, the Company
repurchased $19.9 million principal amount of its Notes at a cost of $18.3
million and during 2001, the Company repurchased $3.0 million principal
amount of its Notes at a cost of $2.7 million.
(b) On March 31, 2002, the Company executed a Fourth Amended and Restated
Credit Agreement in which a group of lenders agreed to provide a $175.0
million senior secured revolving credit facility with a current borrowing
base of $140.0 million. Borrowings under the credit facility are secured by
liens on all oil and gas properties and associated assets of the Company.
Borrowings under the credit facility bear interest, payable quarterly, at
(a) a rate per annum equal to the rate at which eurodollar deposits for
one, two, three or six months are offered by the lead bank plus a margin
ranging from 150 to 250 basis points, or (b) at the lead bank's reference
rate plus an applicable margin ranging from 25 to 50 basis points. The
Company paid approximately $2.2 million in debt issuance fees for the new
credit facility. The credit facility matures on March 28, 2005. The lead
bank's reference rate plus margins at December 31, 2002, was 4.50%. The
Company has $108.0 million outstanding debt on its line of credit at
December 31, 2002.
(c) On December 9, 2002 and December 12, 2002, the Company entered into a
long-term lease arrangement with a related party for $2.1 million and $9.9
million, respectively. These lease arrangements were entered into at rates
equal to, or better than could have been negotiated with a third party.
</FN>
The Company's line of credit agreement contains certain negative financial
and certain information reporting covenants. The Company was in compliance with
all covenants at December 31, 2002.
The annual maturities of long-term debt subsequent to December 31, 2002,
are as follows (in thousands):
2003 $ 2,400
2004 2,400
2005 110,400
2006 2,400
2007 and thereafter 129,505
------------------------------ -----------
Total maturities $247,105
===========
At December 31, 2002, the Company had $1.6 million of outstanding letters
of credit that expire during 2003.
The estimated fair value of long-term debt is approximately $236,933,000
and $164,323,000 at December 31, 2002 and 2001, respectively. The fair value of
long-term debt is estimated based on quoted market prices and managements
estimate of current rates available for similar issues.
5. INCOME TAXES:
The Company follows Statement of Financial Accounting Standards ("SFAS")
No. 109, "Accounting for Income Taxes." As mentioned in Note 1, the Company is
an S-Corporation resulting in the taxable income or loss of the Company being
reported to the stockholders and included in their respective Federal and state
income tax returns. The difference in the taxable income of the stockholders
versus the net income of the Company is due primarily to intangible drilling
costs which are capitalized for book purposes but charged to expense for tax
purposes and accelerated depreciation and depletion methods utilized for tax
purposes.
6. STOCKHOLDER'S EQUITY:
On October 1, 2000, the Company's Board of Directors and shareholders
approved an Agreement and Plan of Recapitalization (the "Recapitalization Plan")
and the Amended and Restated Certificate of Incorporation to be filed with the
Oklahoma Secretary of State. As outlined in the Recapitalization Plan, the
authorized number of shares of capital stock was increased from 75,000 shares of
common stock to 21 million shares consisting of 20 million shares of common
stock and one million shares of $0.01 par value Preferred Stock. In addition,
the par value of common stock was adjusted from $1 per share to $0.01 per share
and 1.02 million shares of the common stock were reserved for issuance under the
2000 incentive Stock Option Plan discussed in Note 7.
Concurrent with the approval of the Recapitalization Plan, the Company
affected an approximate 293: 1 stock split whereby the Company issued new
certificates for 14,368,919 shares of the newly authorized common stock in
exchange for the 49,041 previously outstanding shares of common stock. As a
result of the stock split, additional paid-in capital was reduced by
approximately $95,000, offset by an increase in the common stock at par.
7. STOCK OPTIONS:
The Company has a stock option plan, the Continental Resources, Inc. 2000
Stock Option Plan (the "Plan"), which became effective October 1, 2000.
Under the Plan, the Company may, from time to time, grant options to
directors and eligible employees. These options may be Incentive Stock Options
or Nonqualified Stock Options, or a combination of both. The earliest the
granted options may be exercised is over a five year vesting period at the rate
of 20% each year for the Incentive Stock Options and over a three year period at
the rate of 33 1/3% for the Nonqualified Stock Options, both commencing on the
first anniversary of the grant date. The maximum shares covered by options shall
consist of 1,020,000 shares of the Company's common stock, par value $.01 per
share. The Company granted 144,000 shares during 2000. No options were granted
in 2001 and 28,000 shares were granted during 2002.
Stock options outstanding under the Plan are presented for the periods
indicated.
Number of Shares Option Price Range
- ---------------------------------------------------- ---------------------
Outstanding December 31, 2000 - $ -
Granted 144,000 $7.00 - $14.00
Exercised - $ -
Canceled - $ -
Outstanding December 31, 2001 144,000 $7.00 - $14.00
Granted 28,000 $7.77 - $14.00
Exercised - $ -
Canceled - $ -
Outstanding December 31, 2002 172,000 $7.00 - $14.00
8. COMMITMENTS AND CONTINGENCIES:
The Company maintains a defined contribution pension plan for its employees
under which it makes discretionary contributions to the plan based on a
percentage of eligible employees compensation. During 2000, 2001 and 2002,
contributions to the plan were 5% of eligible employees' compensation. Pension
expense for the years ended December 31, 2000, 2001 and 2002, was approximately
$390,000, $392,000 and $353,590, respectively.
The Company and other affiliated companies participate jointly in a
self-insurance pool (the "Pool") covering health and workers' compensation
claims made by employees up to the first $150,000 and $500,000, respectively,
per claim. Any amounts paid above these are reinsured through third-party
providers. Premiums charged to the Company are based on estimated costs per
employee of the Pool. No additional premium assessments are anticipated for
periods prior to December 31, 2002. Property and general liability insurance is
maintained through third-party providers with a $50,000 deductible on each
policy.
The Company is involved in various legal proceedings in the normal course
of business, none of which, in the opinion of management, will have a material
adverse effect on the financial position or results of operations of the
Company.
Due to the nature of the oil and gas business, the Company is exposed to
possible environmental risks. The Company has implemented various policies and
procedures to avoid environmental contamination and risks from environmental
contamination. The Company is not aware of any material potential environmental
issues or claims.
9. RELATED PARTY TRANSACTIONS:
The Company, acting as operator on certain properties, utilizes affiliated
companies to provide oilfield services such as drilling and trucking. The total
amount paid to these companies, a portion of which was billed to other interest
owners, was approximately $8,713,000, $10,942,000 and $11,679,000 during the
years ended December 31, 2000, 2001 and 2002, respectively. These services were
provided at amounts which management believes approximate the costs that would
have been paid to an unrelated party for the same services. At December 31, 2001
and 2002, the Company owed approximately $266,000 and $919,000, respectively, to
these companies, which are included in accounts, payable and accrued liabilities
in the accompanying consolidated balance sheets. These companies and other
companies, owned by the Company's principal stockholder, also own interests in
wells operated by the Company and provide oilfield related services to the
Company. At December 31, 2001 and 2002, approximately $344,000 and $481,000,
respectively, from affiliated companies is included in accounts receivable in
the accompanying consolidated balance sheets.
The Company leases office space under operating leases directly or
indirectly from the principal stockholder. Rents paid associated with these
leases totaled approximately $313,000, $334,000 and $421,000 for the years ended
December 31, 2000, 2001 and 2002, respectively. See Note 4 for discussion of
related party capital lease transaction.
During 2001, the Company, acting as operator on certain properties began
selling natural gas to a related party. During 2002, the Company sold $1.24
million of natural gas to this related party.
10. IMPAIRMENT OF LONG-LIVED ASSETS:
The Company accounts for impairment of long-lived assets in accordance with
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
During 2000, 2001 and 2002, the Company reviewed its oil and gas properties,
which are maintained under the successful efforts method of accounting, to
identify properties with excess of net book value over projected future net
revenue of such properties. Any such excess net book values identified were
evaluated further considering such factors as future price escalation,
probability of additional oil and gas reserves and a discount to present value.
If an impairment was deemed appropriate, an additional charge was added to
property impairment expense. The Company recognized $1,665,000 additional
property impairment in 2000, $5,303,000 was recognized additional property
impairment in 2001, and $2,300,000 was recognized additional property impairment
in 2002.
11. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, Continental Gas, Inc. ("CGI"),
Continental Resources of Illinois, Inc. ("CRII"), and Continental Crude Co.
("CCC") have guaranteed the Company's outstanding Senior Subordinated Notes and
its bank credit facility. The following is a summary of the condensed
consolidating financial information of CGI and CRII as of December 31, 2000,
2001 and 2002:
Condensed Consolidating Balance Sheet
As of December 31, 2001------------------------------------------------------------------------
- ----------------------------------- Guarantor
($ in thousands) Subsidiaries Parent Eliminations Consolidated
---------------- ---------------- ----------------- ----------------
Current Assets $ 6,310 $ 51,915 $ (25,935) $ 32,290
Property and Equipment 42,051 275,280 0 317,331
Other Assets 12 4,863 (11) 4,864
---------------- ---------------- ----------------- ----------------
Total Assets $ 48,373 $ 332,058 $ (25,946) $ 354,485
Current Liabilities $ 11,039 $ 38,629 $ (8,382) $ 41,286
Long-Term Debt 17,553 178,086 (17,553) 178,086
Other Liabilities 0 91 0 91
Stockholders' Equity 19,781 115,252 (11) 135,022
---------------- ---------------- ----------------- ----------------
Total Liabilities and
Stockholders' Equity $ 48,373 $ 332,058 $ (25,946) $ 354,485
================ ================ ================= ================
As of December 31, 2002
- -----------------------------------
Current Assets $ 6,524 $ 49,308 $ (22,862) $ 32,970
Property and Equipment 42,664 325,239 0 367,903
Other Assets 7 5,811 (14) 5,804
---------------- ---------------- ----------------- ----------------
Total Assets $ 49,195 $ 380,358 $ (22,876) $ 406,677
Current Liabilities $ 11,443 $ 42,258 $ (6,934) $ 46,767
Long-Term Debt 15,928 244,705 (15,928) 244,705
Other Liabilities 0 125 0 125
Stockholders' Equity 21,824 93,270 (14) 115,080
---------------- ---------------- ----------------- ----------------
Total Liabilities and
Stockholders' Equity $ 49,195 $ 380,358 $ (22,876) $ 406,677
================ ================ ================= ================
Condensed Consolidating Balance Sheet
As of December 31, 2001-------------------------------------------------------------------------
- ----------------------------------- Guarantor
($ in thousands) Subsidiaries Parent Eliminations Consolidated
--------------- --------------- ----------------- ----------------
Total Revenue $ 52,051 $ 357,589 $ (563) $ 409,077
Operating Expenses 46,695 339,784 (563) 385,916
Other Income (Expense) (95) (11,400) 0 (11,495)
--------------- --------------- ----------------- ----------------
Net Income $ 5,261 $ 6,405 $ 0 $ 11,666
=============== =============== ================= ================
As of December 31, 2002
- -----------------------------------
Total Revenue $ 48,248 $ 253,624 $ (1,581) $ 300,291
Operating Expenses 44,575 260,089 (1,581) 303,083
Other Income (Expense) (1,632) (15,608) 0 (17,240)
--------------- --------------- ----------------- ----------------
Net Income $ 2,041 $ (22,073) $ 0 $ (20,032)
=============== =============== ================= ================
At December 31, 2001 and 2002, current liabilities payable from the
subsidiaries to CRI totaled approximately $8.2 million and $22.6 million,
respectively. For the years ended December 31, 2000, 2001 and 2002,
depreciation, depletion and amortization, included in operating costs, totaled
approximately $2.1 million, $4.9 million and $5.6 million, respectively.
Since its incorporation, CCC has had no operations, has acquired no assets
and has incurred no liabilities.
12. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
Proved Oil and Gas Reserves
The following reserve information was developed from reserve reports as of
December 31, 1999, 2000, 2001 and 2002, prepared by independent reserve
engineers and by the Company's internal reserve engineers and set forth the
changes in estimated quantities of proved oil and gas reserves of the Company
during each of the three years presented.
Crude Oil and
Natural Gas (MMcf) Condensate (MBbls)
------------------ ------------------
Proved reserves as of December 31, 1999 75,761 36,624
Revisions of previous estimates (10,106) 1,340
Extensions, discoveries and other additions 4,613 664
Production (7,939) (3,360)
Sale of reserves in place (2,456) (4)
Purchase of reserves in place 0 0
-------------- -------------
Proved reserves as of December 31, 2000 59,873 35,264
Revisions of previous estimates (11,766) (2,378)
Extensions, discoveries and other additions 9,319 27,276
Production (8,411) (3,489)
Sale of reserves in place (2,457) (274)
Purchase of reserves in place 5,709 3,332
-------------- -------------
Proved reserves as of December 31, 2001 52,267 59,731
Revisions of previous estimates 21,854 6,195
Extensions, discoveries and other additions 4,948 1,173
Production (9,229) (3,810)
Sale of reserves in place 0 (12)
Purchase of reserves in place 107 4
-------------- -------------
Proved reserves as of December 31, 2002 69,947 63,281
============== =============
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves. Oil and gas reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
precisely measured, and estimates of engineers other than the Company's might
differ materially from the estimates set forth herein. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results of drilling,
testing and production subsequent to the date of the estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
The year-end weighted average oil and gas prices utilized in the
computation of future cash inflows were $10.37 per Bbl and $1.37 per Mcf,
respectively, higher in 2002 than in 2001. This price increase accounts for the
majority of the revisions of previous estimates for 2002.
Gas imbalance receivables and liabilities for each of the three years ended
December 31, 2000, 2001 and 2002, were not material and have not been included
in the reserve estimates.
Proved Developed Oil and Gas Reserves
The following reserve information was developed by the Company and sets
forth the estimated quantities of proved developed oil and gas reserves of the
Company as of the beginning of each year.
Crude Oil and
Proved Developed Reserves Natural Gas (MMcf) Condensate (MBbls)
- ------------------------- ---------------- -----------------
January 1, 2000 65,723 34,432
January 1, 2001 58,438 33,173
January 1, 2002 56,647 31,325
January 1, 2003 69,273 33,626
Proved developed reserves are proved reserves that are expected to be
recovered through existing wells with existing equipment and operating methods.
Costs Incurred in Oil and Gas Activities
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities during the years are shown below (in
thousands of dollars). Amounts are presented in accordance with SFAS No. 19, and
may not agree with amounts determined using traditional industry definitions.
Property acquisition costs: 2000 2001 2002
----------- ------------ -----------
Proved $ - $ 36,535 $ 655
Unproved 5,231 11,386 10,504
----------- ------------ -----------
Total property acquisition costs $ 5,231 $ 47,921 $ 11,159
Exploration costs 6,152 9,170 11,809
Development costs 39,329 47,567 84,219
----------- ------------ -----------
Total $ 50,712 $ 104,658 $ 107,187
Aggregate Capitalized Costs
Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A, as of December 31 (in thousands of
dollars):
2001 2002
----------- -----------
Proved oil and gas properties $425,754 $505,444
Unproved oil and gas properties 20,694 16,769
----------- -----------
Total $446,448 $522,213
Less-Accumulated DD&A (155,703) (182,863)
----------- -----------
Net capitalized costs $290,745 $339,349
=========== ===========
Oil and Gas Operations (Unaudited)
Aggregate results of operations for each period ended December 31, in
connection with the Company's oil and gas producing activities are shown below
(in thousands of dollars):
2000 2001 2002
-------------- ------------- -------------
Revenues $115,478 $112,170 $108,752
Production costs 29,807 36,791 36,112
Exploration expenses 9,965 15,863 10,229
DD&A and valuation provision (1) 17,454 29,003 29,244
-------------- ------------- -------------
Income 58,252 30,513 33,167
Income tax expense (2) - - -
-------------- ------------- -------------
Results of operations from producing activities (3) $58,252 $29,844 $33,167
============== ============= =============
- ---------------
<FN>
(1) Includes $1.6 million in 2000, $5.3 million in 2001 and $2.3 million in
2002 of additional DD&A as a result of SFAS No. 121 impairments
(2) The Company is an S-Corporation; as a result, the income or loss of the
Company is taxable at the stockholder level.
(3) Excluding corporate overhead and interest costs
</FN>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 2000, 2001 and 2002, as required by SFAS No. 69. The Standard
requires the use of a 10% discount rate. This information is not the fair market
value nor does it represent the expected present value of future cash flows of
the Company's proved oil and gas reserves (in thousands of dollars).
2000 2001 2002
------------- ------------- -------------
Future cash inflows $1,403,645 $1,300,078 $2,131,097
Future production and development costs (495,953) (667,533) (827,238)
Future income tax expenses - - -
------------- ------------- -------------
Future net cash flows 907,692 632,545 1,303,859
10% annual discount for estimated timing of cash flows (415,893) (323,941) (670,462)
------------- ------------- -------------
Standardized measure of discounted future net cash flows $491,799 $308,604 $633,397
============= ============= =============
Future cash inflows are computed by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves. The year-end weighted average oil price utilized in the computation of
future cash inflows was approximately $26.80, $18.67, and $29.04 per BBL at
December 31, 2000, 2001 and 2002, respectively. The year-end weighted average
gas price utilized in the computation of future cash inflows was approximately
$9.78, $1.96, and $3.33 per MCF at December 31, 2000, 2001 and 2002,
respectively. Such prices do not include the effect of the Company's fixed price
contracts designated as hedges.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.
Income taxes were not computed at December 31, 2000, 2001 or 2002, as the
Company elected S-Corporation status effective June 1, 1997.
Principal changes in the aggregate standardized measure of discounted
future net cash flows attributable to the Company's proved oil and gas reserves
at year-end are shown below (in thousands of dollars)
2000 2001 2002
------------- ------------- -------------
Standardized measure of discounted future
net cash flows at the beginning of the year $334,411 $491,799 $308,604
Extensions, discoveries and improved recovery, less
related costs 29,915 98,719 21,082
Revisions of previous quantity estimates (3,544) (33,338) 87,325
Changes in estimated future development costs 853 (107,009) 6,748
Purchase (sales) of minerals in place (1,387) 10,755 161
Net changes in prices and production costs 149,400 (136,665) 233,518
Accretion of discount 33,441 49,180 30,860
Sales of oil and gas produced, net of production costs (85,671) (75,379) (73,755)
Development costs incurred during the period 19,196 12,260 52,834
Change in timing of estimated future production, and other 15,185 (1,718) (33,980)
------------- ------------- -------------
Net Change 157,388 (183,195) 324,793
------------- ------------- -------------
Standardized measure of discounted future
net cash flows at the end of the year $491,799 $308,604 $633,397
============= ============= =============
INDEX TO EXHIBITS
Exhibit
No. Description Method of Filing
- --- ----------- ----------------
2.1 Agreement and Plan of Recapitalization Incorporated herein by reference
of Continental Resources, Inc. dated
October 1, 2000.
3.1 Amended and Restated Certificate of Incorporated herein by reference
Incorporation of Continental Resources,
Inc.
3.2 Amended and Restated Bylaws of Incorporated herein by reference
Continental Resources, Inc.
3.3 Certificate of Incorporation of Incorporated herein by reference
Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference
amended and restated.
3.5 Certificate of Incorporation of Incorporated herein by reference
Continental Crude Co.
3.6 Bylaws of Continental Crude Co. Incorporated herein by reference
4.1 Restated Credit Agreement dated April Incorporated herein by reference
21, 2000 between Continental Resources,
Inc. and Continental Gas, Inc., as
Borrowers and MidFirst Bank as Agent
(the "Credit Agreement").
4.1.1 Form of Consolidated Revolving Note Incorporated herein by reference
under the Credit Agreement.
4.1.2 Second Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois, Inc.,
as Borrowers, and MidFirst Bank, dated
July 9, 2001.
4.1.3 Third Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois, Inc.,
as Borrowers, and MidFirst Bank, dated
January 17, 2002.
4.1.4 Fourth Amended and Restated Credit Incorporated herein by reference
Agreement dated March 28, 2002, among
the Registrant, Union Bank of
California, N. A., Guaranty Bank, FSB
and Fortis Capital Corp.
4.2 Indenture dated as of July 24, 1998 Incorporated herein by reference
between Continental Resources, Inc., as
Issuer, the Subsidiary Guarantors named
therein and the United States Trust
Company of New York, as Trustee.
10.1 Unlimited Guaranty Agreement dated March Incorporated herein by reference
28, 2002.
10.2 Security Agreement dated March 28, 2002, Incorporated herein by reference
between Registrant and Guaranty Bank,
FSB, as Agent.
10.3 Stock Pledge Agreement dated March 28, Incorporated herein by reference
2002, between Registrant and Guaranty
Bank, FSB, as Agent.
10.4 Conveyance Agreement of Worland Area Incorporated herein by reference
Properties from Harold G. Hamm, Trustee
of the Harold G. Hamm Revocable
Intervivos Trust dated April 23, 1984,
to Continental Resources, Inc.
10.5 Purchase Agreement signed January 2000, Incorporated herein by reference
effective October 1, 1999, by and
between Patrick Energy Corporation as
Buyer and Continental Resources, Inc. as
Seller.
10.6 Continental Resources, Inc. 2000 Stock Incorporated herein by reference
Option Plan.
10.7 Form of Incentive Stock Option Incorporated herein by reference
Agreement.
10.8 Form of Non-Qualified Stock Option Incorporated herein by reference
Agreement.
10.9 Purchase and Sales Agreement between Incorporated herein by reference
Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental
Resources of Illinois, Inc. as
Purchaser, dated May 14, 2001.
10.10 Collateral Assignment of Contracts dated Incorporated herein by reference
March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent.
12.1 Statement re computation of ratio of Filed herewith electronically
debt to Adjusted EBITDA.
12.2 Statement re computation of ratio of Filed herewith electronically
earning to fixed charges.
12.3 Statement re computation of ratio of Filed herewith electronically
Adjusted EBITDA to interest expense.
21.0 Subsidiaries of Registrant. Incorporated herein by reference
99.1 Letter to the Securities and Exchange Incorporated herein by reference
Commission dated March 28, 2002,
regarding the audit of the Registrant's
financial statements by Arthur Andersen
LLP.