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%
================== ================ ============== ================= ================
(1) Future estimated net revenues discounted at 10%
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
- ---------------
(1) Related to oil and gas producing properties.
(2) Related to oil and gas producing properties, net of operating overhead income.
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
- ---------------
(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.
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