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, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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, Suite 300, 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 X No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
As of April 1, 2002, 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. Documents incorporated by reference: None
CONTINENTAL RESOURCES, INC.
Annual Report on Form 10 - K
for the Year Ended December 31, 2001
TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS...........................................................1
ITEM 2. PROPERTIES........................................................13
ITEM 3. LEGAL PROCEEDINGS.................................................20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...............20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS...........................................................20
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA.............................21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.............................................22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE..............................................31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................31
ITEM 11. EXECUTIVE COMPENSATION............................................33
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT....34
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................35
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..36
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 plans for 2002 and
beyond could differ materially from those expressed in forward-looking
statements. All subsequent written and oral forward- looking statements
attributable 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 the 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, six gas gathering systems and two 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 68.4 MMBoe at year-end 2001, and has increased its annual production
from 2.2 MMBoe in 1995 to 4.9 MMBoe in 2001. As of December 31, 2001, the
Company's reserves had a present value of estimated future net cash flows,
discounted at 10% ("PV-10") of $308.6 million calculated in accordance with the
Securities and Exchange Commission (the "Commission" or "SEC") guidelines.
Approximately 87% 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, 2001, the Company had interests in 2,066 producing
wells of which it operated 1,311. 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, 84% of the Company's
estimated proved reserves as of December 31, 2001 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 significantly in the Gulf Coast
region and it is proving to be another core operating area for the Company. To
further expand it's 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. Through development
activities, 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 84% of the Company's estimated proved reserves and 70% of the PV-10
of the Company's proved reserves as of December 31, 2001. The Company owns
approximately 401,000 net leasehold acres, has interests in 629 gross (540 net)
producing wells and is the operator of 91% of these wells, and has identified
110 potential drilling locations in the Rocky Mountain region.
The Williston Basin properties represented 75% of the Company's estimated
proved reserves and 64% of the PV-10 of its proved reserves at December 31,
2001. In the Williston Basin, the Company owns approximately 308,000 net
leasehold acres, has interests in 336 gross (297 net) producing wells and has
identified 107 potential drilling locations. The Company's principal properties
in the Williston Basin include seven high pressure air injection, 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%-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
60% of the proved reserves and 49% of the PV-10 attributable to the Company's
proved reserves at December 31, 2001. Combined, the Company's seven HPAI
secondary recovery projects represent over half 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, 2001. In the Worland Field, the Company owns approximately 85,000 net
leasehold acres and has interests in 293 gross (242 net) producing wells, of
which 256 are operated by the Company. In the Worland Field the Company has
identified three potential drilling locations, 13 potential workovers or
recompletions and has initiated two pilot secondary recovery project 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, 2001, the Company's
estimated proved reserves in the Mid-Continent region represented 16% of the
Company's total estimated proved reserves, 72% of the Company's natural gas
reserves and 28% of the Company's PV-10. In the Mid-Continent region, the
Company owns approximately 139,000 net leasehold acres, has interests in 1,404
gross (906 net) producing wells and has identified 53 potential drilling
locations. The Company operates 57% of the gross wells in which it has interest.
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. 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 at December 31, 2001. In the Gulf Coast,
the Company owns approximately 21,000 net leasehold acres, has interests in 33
gross (20 net) producing wells and has identified 34 potential drilling
locations from 95 square miles of proprietary 3-D data and several hundred miles
of non-proprietary 3-D seismic data. The Company operates 54% 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. (CRII), an Oklahoma corporation. 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. is headquartered in Enid, Oklahoma, with
additional offices in Baker, Montana, Buffalo, South Dakota, Mt. Vernon,
Illinois and field offices located within its various operating areas.
BUSINESS STRENGTHS
The Company believes that it has certain strengths that provide it with
significant 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 157% from 26.6
MMBoe in 1995 to 68.4 MMBoe as of December 31, 2001.
SUBSTANTIAL DRILLING INVENTORY. The Company has identified more than 197
potential drilling locations based on geological and geophysical evaluations. As
of December 31, 2001, the Company held approximately 581,000 net acres, of which
approximately 57% were classified as undeveloped. Management believes that its
current inventory and acreage holdings could support 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, primary and secondary production levels and reserve values.
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, 2001, the
Company participated in 329 gross wells of which 87% were successfully completed
resulting in the addition of 44.5 MMBoe of proved developed reserves at an
average finding cost of $4.42 per barrel of oil equivalent ("Boe"). The Company
acquired 21.2 MMBoe at an average cost of $4.60 per Boe. Including major
revisions of 36.9 MMBoe due primarily to fluctuating prices, the Company added a
total of 65.7 MMBoe at an average cost of $4.48 per Boe during the last five
years.
SIGNIFICANT OPERATIONAL CONTROL. Approximately 95.7% of the Company's PV-10
at December 31, 2001, 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 208 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. Seven senior officers have an average of 23 years of oil and gas industry
experience. Additionally, the Company's technical staff, which includes ten
petroleum engineers and ten geoscientists, have an average of more than 23 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 2002 total $91.3
million. Approximately $61.0 million (66%) is targeted for drilling, $4.2
million (5%) for land and seismic, $2.0 million (2%) for workovers and
recompletions and $24.1 million (27%) for secondary recovery projects and
facilities. Funding for these expenditures will come from a combination of cash
flow and the Company's credit facility.
Preparing the Cedar Hills Field secondary recovery units to begin injection
during the fourth quarter of 2002 will be given top priority and is projected to
account for $65.0 million, or 71%, of the Company's projected capital
expenditures for 2002. This includes $40.9 million for drilling injector wells
and $24.1 million for compressors, equipment and facilities. Approximately $12.0
million and $8.2 million will be spent on development and exploration drilling,
respectively, outside of the Cedar Hills unit. This is approximately 40% below
historical averages but is necessary to accommodate funding the Cedar Hills
development. Expenditures on projects outside of Cedar Hills will remain
flexible 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 2002, the Company expects to invest $52.8
million drilling 58 development drilling projects, representing 86% of the
Company's total 2002 drilling budget. Within the development drilling budget,
77% will be spent drilling injector wells within the Cedar Hills units, 10% on
other projects in the Williston and Big Horn Basins, 9% in the Gulf Coast region
and 4% in the Mid-Continent region. The Company also expects to invest $2.0
million during 2002 on workovers and recompletions and $24.1 million on
secondary recovery projects and related facilities. The following table sets
forth the Company's development inventory as of December 31, 2001.
NUMBER OF DEVELOPMENT PROJECTS
------------------------------
ENHANCED/SECONDARY
DRILLING WORKOVERS AND RECOVERY
LOCATIONS RECOMPLETIONS PROJECTS TOTAL
--------- ------------- -------- -----
ROCKY MOUNTAIN:
Williston Basin........................................ 90 0 4 94
Big Horn Basin......................................... 3 13 3 19
-- -- -- --
Total ROCKY MOUNTAIN.................................... 93 13 7 113
MID-CONTINENT:
Anadarko Basin......................................... 16 0 1 17
Black Warrior Basin.................................... 4 0 0 4
Illinois Basin......................................... 2 20 2 24
-- -- -- --
Total MID-CONTINENT.................................... 22 20 3 45
GULF COAST..................................................
Texas.................................................. 12 15 0 27
Louisiana.............................................. 0 0 0 0
Gulf of Mexico......................................... 0 0 0 0
-- -- -- --
Total GULF COAST....................................... 12 15 0 27
TOTAL....................................................... 127 48 10 185
=== == == ===
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 following table sets forth information pertaining to the Company's
existing exploration project inventory at December 31, 2001:
NUMBER OF EXPLORATION PROJECTS
DRILLING LOCATION 3-D SEISMIC
----------------- -----------
ROCKY MOUNTAIN:
Williston Basin.............................. 17 3
Big Horn Basin............................... 0 0
-- --
Total ROCKY MOUNTAIN.......................... 17 3
MID-CONTINENT
Anadarko Basin............................... 5 1
Black Warrior Basin.......................... 20 0
Illinois Basin............................... 6 0
-- --
Total MID-CONTINENT.......................... 31 1
GULF COAST
Texas........................................ 13 3
Louisiana.................................... 4 1
Gulf of Mexico............................... 5 5
-- --
Total GULF COAST............................. 22 9
TOTAL............................................. 70 13
== ==
The Company will initiate, on a priority basis, as many projects as cash
flow allows. The Company anticipates investing $8.2 million drilling 13
exploratory projects during 2002, representing 14% of the Company's total 2002
drilling budget with 15% to be spent in the Mid-Continent region, 10% in the
Rocky Mountain region and 75% in the Gulf Coast region.
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 and 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 and 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 "Management's
Discussion and Analysis of Financial Condition and Results of Operations".
REPLACEMENT 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 will 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 is 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, 2001, the estimated future net cash
flows of $632.5 million and PV-10 of $308.6 million attributable to the
Company's proved oil and gas reserves are based on prices in effect at that date
($18.67 per barrel ("Bbl") of oil and $1.96 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 integrating
acquired businesses 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 of 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 expand 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 no 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, 2001, on a consolidated basis, the Company and the
Subsidiary Guarantors (defined below) had $183.4 million of indebtedness
(including short-term indebtedness and current maturities of long-term
indebtedness) compared to the Company's stockholders' equity of $135.1 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 of 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 at a relative competitive disadvantage and
make it more vulnerable to changing 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 which the Company could realize therefrom. 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 than liens created pursuant to the Credit
Facility and certain permitted liens;
o Mergers, consolidations and sales of all or a 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 thereunder 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.
At December 31, 2001, the Company had hedging contracts for a term of 15
months, which is in violation of a covenant with the Credit Facility. The
Company asked for and received a waiver from the Credit Facility regarding this
covenant. The Company is required to maintain a minimum current ratio of
1.0:1.0. However, the current ratio at December 31, 2001, was 0.91:1.0, which
created a violation of this covenant. The Company's lenders have also provided a
waiver of this covenant violation.
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 AND 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, 2002, was $69.6 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.
Additional senior debt may be incurred by the Company or the Subsidiary
Guarantors 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 will not be 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
Historically, the Company has derived approximately 10% of its operating
cash flows from its subsidiary, Continental Gas. The holders of the Notes have
no direct claim against the Company's subsidiaries other than 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
holders of the Notes to participate in any distribution of assets of any
Subsidiary Guarantor upon liquidation, bankruptcy, reorganization or otherwise
will, as is the 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 of 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 to 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 date 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 and the Subsidiary Guarantors, the
terms of which may prohibit the purchase of the Notes by 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 AND OIL TRADING ACTIVITIES
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. In July
1998, the Company began entering into 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. Should the Company's purchaser fail to complete the
contracts for purchase, the Company may suffer a loss. The Company's income from
its crude oil marketing activities was $.9 million for the year ended December
31, 2001. The Company's current policy is to limit its exposure from open
positions to $1.0 million at any one time. At December 31, 2001, the Company's
exposure from open positions on forward crude oil contracts was not material.
During the fourth quarter of 2001, the Company discontinued its crude oil
activities.
WRITE DOWN OF CARRYING VALUES
The Company periodically reviews the carrying value of its oil and gas
properties in accordance with SFAS No. 121 "Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed Of". SFAS No. 121
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 an asset 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 charges) is less
than 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.
In August 2001, The FASB issued SFAS No. 144, "Accounting for the
Impairment of Disposal of Long-Lived Assets". SFAS No. 144 requires that an
impairment loss be recognized only if the carrying amount of a long-lived asset
is not recoverable from its undiscounted cash flows and that the measurement of
an impairment loss be the difference between the carrying amount and the fair
value of the assets. Adoption of SFAS No. 144 is required for financial
statements for periods beginning after December 15, 2001. The Company adopted
this new standard effective January 1, 2002. The adoption of this new standard
did not have a material impact on the Company's financial position or results of
operation.
LAWS AND REGULATIONS; ENVIRONMENTAL RISK
Oil and gas operations are subject to various federal, state and local
governmental regulations which 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--Regulation."
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 or 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
groundwater resources, potentially resulting in suspension of operation of the
wells, fines 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 than 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 April 1, 2002, 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. 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".
REGULATION
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 by statute to issue, and have issued, rules and regulations binding
upon the oil and gas industry and its individual members.
REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. The Federal Energy
Regulatory Commission (the "FERC") regulates the transportation and sale for
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 risks 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 wastes, 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 April 1, 2002, the Company employed 267 people, including 97
administrative personnel, 10 geoscientists, 10 engineers and 160 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 employees 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, 2001, the Company's estimated net
proved reserves from all properties totaled 68.4 MMBoe with 84% of the reserves
located in the Rocky Mountains, 16% in the Mid-Continent and 1% in the Gulf
Coast regions. At December 31, 2001, 87% of the Company's net proved reserves
were oil and 13% 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 $70
million, or 77%, of the Company's projected $91.3 million capital expenditures
for 2002 are focused on expansion and development of its oil properties in the
Rocky Mountain region while the remaining $20.5 million, or 23%, 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,
2001:
PRESENT % OF TOTAL
VALUE OF PRESENT
OIL FUTURE CASH VALUE OF
OIL GAS EQUIVALENT FLOWS(1) FUTURE CASH
AREA (MBbl) (MMcf) (MBoe) (M $) FLOWS(1)
- ---- ------ ------ ------ ----- --------
ROCKY MOUNTAINS:
Williston Basin......................... 50,454 4,788 51,252 $197,184 64
Big Horn Basin......................... 4,833 7,415 6,069 $19,004 6
------ ------ ------ -------- --
Total ROCKY MOUNTAINS................... 55,287 12,203 57,321 $216,188 70
MID-CONTINENT:
Anadarko Basin......................... 1,843 36,164 7,870 $67,795 22
Black Warrior Basin................... 0 1,213 202 $1,443 0
Illinois Basin......................... 2,499 357 2,559 $17,062 6
------ ------ ------ -------- --
Total MID-CONTINENT..................... 4,342 37,734 10,631 $86,300 28
GULF COAST
Texas................................... 36 772 165 $1,473 1
Louisiana............................... 13 134 35 $223 0
Gulf of Mexico........................ 53 1,423 290 $4,420 1
------ ------ ------ -------- --
Total GULF COAST........................ 102 2,329 490 $6,116 2
TOTALS.................................... 59,731 52,266 68,442 $308,604 100
====== ====== ====== ======== ===
(1) Future estimated net cash flows 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, 2001, totaled 57.3 MMBoe and represented 70% of the Company's
PV-10. Approximately 52% of these estimated proved reserves are proved
developed. During the twelve months ended December 31, 2001, the average net
daily production was 7,702 Bbls of oil and 4,832 Mcf of natural gas, or 8,514
Boe per day from the Rocky Mountain properties. The Company's leasehold
interests include 164,598 net developed and 237,133 net undeveloped acres, which
represent 30% and 42% 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, 2001, the Company's Rocky Mountain properties included an inventory
of 93 development and 17 exploratory drilling locations.
WILLISTON BASIN
CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994.
During the twelve months ended December 31, 2001, the Cedar Hills Field
properties produced 2,943 net Boe per day to the Company interests and
represented 49% of the PV-10 attributable to the Company's estimated proved
reserves as of December 31, 2001. 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, 2001, the Company drilled or participated in 167 gross (117 net)
horizontal wells, of which 160 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") is 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 49,679 acres. The
Company owns 100% of the working interest in the WCHU and is the unit operator.
The WCHU contains 10 wells and 7,774 acres. An estimated $114.0 million will
need to be invested over the next two years to fully implement the Company's
secondary recovery operations in the Cedar Hills Field. Approximately $65
million will be invested in 2002 of which $41 million is for infill drilling,
$12.9 million for compressors and distribution systems, $6.4 million for
electric facilities, $2.9 million for water injection facilities, and $1.8
million for motor conversions. By year end 2002, the Company expects to have
completed 47 of the 79 required injectors and installed facilities to begin
injection in approximately 60% of the units. Approximately $49.0 million will be
spent in 2003 to finish drilling injectors and add additional compression. With
secondary recovery operations underway, the SEC and independent auditors
approved adding 25.8 MMBoe of proved, undeveloped reserves from the Cedar Hills
to the Company's proved reserves. This represents 38% of the Company's estimated
proved reserves and $67.4 million, or 22%, of the PV-10 of the Company's proved
reserves at December 31, 2001. The Company believes this represents
approximately 56% of the reserves it expects are ultimately recoverable from the
field.
MEDICINE POLE HILLS, MEDICINE POLE HILLS WEST, 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, 2001, these units produced 2,815 Boe per day, net to the
Company's interests, and represented 7.8 MMBoe, or 12% of the PV-10 attributable
to the Company's estimated proved reserves as of December 31, 2001. 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 46 years, demonstrating the long-lived production
characteristic of the Red River "B" formation. There are 133 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 Company expects to have this area
unitized as the Medicine Pole Hills South Unit by the fourth quarter of 2002,
and conceivably under injection 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, 2001,
produced 316 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 38 wells producing
in the two fields. No secondary recovery operations are underway in either field
at this time. The Company currently owns 74,594 net acres in the Lustre and
Midfork Field area.
During 2001, the Company acquired an additional 60 square miles of
proprietary 3-D seismic data coverage over the Lustre Field giving the Company a
total of 100 square miles of 3-D seismic in the area. A significant number of
additional development and exploratory drilling locations have been identified
from this proprietary data for future drilling. The Company also began
researching the application of its HPAI secondary recovery techniques to
increase oil recoveries from the Lustre Field. If supported by the research, the
Company plans to begin the unitization process in 2002. The Company currently
has 12 locations selected for drilling and plans to drill two to four of these
locations in 2002.
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. See "Certain
Relationships and Related Transactions." The Worland Field properties cover
84,905 net leasehold acres in the Worland Field of the Big Horn Basin in
northern Wyoming, of which 29,718 net acres are held by production and 55,187
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 293 producing wells, 256
of which are operated by the Company.
As of December 31, 2001, the estimated net proved reserves attributable to
the Company's Worland Field properties were approximately 6.1 MMBoe, with an
estimated PV-10 of $19.0 million. Approximately 80%, 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 will expire April 1, 2002, and has been renegotiated. The Company
anticipates the spread from NYMEX will increase slightly with the new contract.
The Company believes that secondary and tertiary recovery projects have
significant potential for the addition of reserves in the Worland Field and
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. During 2002, the Company plans to expand its
secondary recovery efforts and begin injecting water in a selected portion of
the field using a pressure control technique it believes will produce the best
secondary results. This secondary operation should effect production in as many
as 20 wells and if successful will be expanded. This secondary operation is
being partially funded by the Department of Energy. In addition to the secondary
recovery operations, the Company has identified three potential development
drilling locations and 13 wells for acid fracture treatment to enhance
production.
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,
2001, the Company's estimated proved reserves in the Mid-Continent totaled 10.6
MMBoe and represented 28% of the Company's PV-10. At December 31, 2001,
approximately 72% of the Company's estimated proved reserves in the
Mid-Continent were natural gas. Net daily production from these properties
during 2001 averaged 1,708 Bbls of oil and 14,172 Mcf of natural gas, or 4,773
Boe to the Company's interests. The Company's Mid-Continent leasehold position
includes 65,622 net developed and 35,203 net undeveloped acres, representing 12%
and 6% of the Company's total leasehold, respectively, at December 31, 2001. As
of December 31, 2001, the Company's Mid-Continent properties included an
inventory of 22 development and 31 exploratory drilling locations.
ANADARKO BASIN. The Anadarko Basin properties contained 70% of the
Company's estimated proved reserves for the Mid-Continent and 21% of the
Company's total PV-10 at December 31, 2001, and represented 65% of the Company's
estimated proved reserves of natural gas. During the twelve months ended
December 31, 2001, net daily production from its Anadarko Basin properties
averaged 999 Bbls of oil and 12,574 Mcf of natural gas, or 3,095 Boe to the
Company's interests from 711 gross (303 nets) producing wells, 339 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, 2001, the Company had identified 16 development and five
exploratory drilling locations 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 24% of the Company's estimated proved
reserves for the Mid-Continent and 6% of the Company's total PV-10 at December
31, 2001. Net daily production during the twelve months ended December 31, 2001,
averaged 1,378 Bbls of oil and 241 Mcf of natural gas, or 1,418 Boe to the
Company's interests from 690 gross (601 net) producing wells, 524 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. During
2001, the Company installed one new project and expanded several others. At year
end the Company was evaluating two properties for acquisition that had secondary
recovery potential. Three new projects are planned for 2002. These properties
are constantly being evaluated and we are continually performing numerous
workovers and making injection enhancements. As of December 31, 2001 the Company
had two development and six exploratory drilling locations in inventory.
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 significant 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. 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,
2001, the Company had acquired 18,664 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 2001, the
Company drilled its first six exploratory wells and established three producers
for a 50% success rate. As of December 31, 2001, the Company had four
development and 20 exploratory drilling locations in inventory and plans on
drilling up to 10 wells in 2002 to continue developing acquired leasehold.
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 Challanger Minerals Inc. to locate and participate in drilling
opportunities on the shallow shelf of the Gulf of Mexico. At December 31, 2001,
the Company's estimated proved reserves in the Gulf Coast totaled .5 MMBoe (79%
gas) representing 2% of the Company's total PV-10 and 4% of the Company's
estimated proved reserves of natural gas. Net daily production from these
properties is 149 Bbls of oil and 4,039 Mcf of natural gas or 822 Boe to the
Company's interests from 33 wells. The Company's leasehold position includes
5,100 net developed and 16,387 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, 12 development and 22 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 sandstones 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' to
13,000 feet. The Company owns 20,017 gross and 13,866 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 12 development and 10
exploratory locations for drilling. During 2002, the Company expects to drill
six to 10 of these locations in the Pebble Beach/Luby projects and plans to
acquire additional leasehold and approximately 25 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 65.3 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 4,910 gross and 3,415 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 commercial
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
encountered pay in sand reservoirs not previously known to produce in the field.
The well is currently being prepared for production tests. The Company has
identified four additional exploratory drilling locations and plans to drill at
least one in 2002.
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 Challanger Minerals Inc. This was part of the Company's
ongoing strategy to build its opportunity base of high rate of return, natural
gas opportunities in the Gulf Coast region. The expansion into the GOM has
proven successful and as of December 31, 2001, the Company has participated in
13 wells which have resulted in seven producers and six dry holes. The Company
plans to continue its activity in the GOM as a non-operator, restricting its
risked investments to approximately $750,000 per project. During 2001, the
Company spent 15% of its drilling budget on opportunities in the GOM and expects
to spend approximately the same percentage during 2002. The Company currently
has five potential wells in inventory for 2002.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and
gas production, prices and costs attributable to all oil and gas property
interests owned by the Company for the periods shown:
YEAR ENDED DECEMBER 31
--------------------------------------------
1999 2000 2001
---- ---- ----
NET PRODUCTION DATA:
Oil and condensate (MBbl).......................... 3,221 3,360 3,489
Natural gas (MMcf)................................. 6,640 7,939 8,411
Total (MBoe)....................................... 4,328 4,684 4,893
UNIT ECONOMICS
Average sales price per Bbl........................$ 16.93 $ 29.02 $ 23.79
Average sales price per Mcf........................ 1.72 2.91 3.41
Average equivalent price (per Boe)(1).............. 15.24 25.81 22.92
Lifting cost (per Boe)(2).......................... 4.47 6.36 7.52
DD&A expense (per Boe)(2).......................... 3.61 3.71 5.92
General and administrative expense (per Boe)(3).... 1.31 1.80 2.12
--------- --------- ---------
Gross margin.......................................$ 5.85 $ 13.94 $ 7.36
========= ========= =========
(1) Calculated by dividing oil and gas revenues, as reflected in the
consolidated financial statements, by production volumes on a Boe basis.
Oil and gas revenues reflected in the consolidated financial statements are
recognized as production is sold and may differ from oil and gas revenues
reflected on the Company's production records which reflect oil and gas
revenues by date of production. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
(2) Related to oil and gas producing properties.
(3) 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, in which the Company owned an interest as of
December 31, 2001:
OIL NATURAL GAS TOTAL
--- ----------- -----
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
ROCKY MOUNTAIN:
Williston Basin................ 335 297 1 1 336 298
Big Horn Basin(1).............. 292 241 1 1 293 242
---- ---- --- --- ---- ----
Total ROCKY MOUNTAIN........... 627 538 2 2 629 540
MID-CONTINENT:
Anadarko Basin................. 401 218 310 85 711 303
Illinois Basin................. 653 567 37 34 690 211
Black Warrior Basin............ 0 0 3 2 3 2
---- ---- --- --- ---- ----
Total MID-CONTINENT............ 1054 785 350 121 1404 906
GULF COAST.......................... 8 8 25 12 33 20
---- ---- --- --- ---- ----
Total.......................... 1689 1331 377 135 2066 1466
==== ==== === === ==== ====
(1) Represents Worland Field properties acquired by the Company in the Worland
Field Acquisition
ACREAGE
The following table sets forth the Company's developed and undeveloped
gross and net leasehold acreage as of December 31, 2001:
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -----
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
ROCKY MOUNTAIN:
Williston Basin......... 156,025 134,880 202,445 173,708 358,470 308,588
Big Horn Basin.......... 30,929 29,718 58,110 55,187 89,039 84,905
Canada.................. 0 0 7,678 7,678 7,678 7,678
New Mexico.............. 0 0 560 560 560 560
------- ------- ------- ------- ------- -------
Total ROCKY MOUNTAIN.... 186,954 164,598 268,793 237,133 455,747 401,731
MID-CONTINENT:
Anadarko Basin.......... 122,688 65,622 33,826 26,489 156,514 92,111
Illinois Basin.......... 35,504 29,079 8,875 8,874 47,379 37,953
Other................... 0 0 8,715 8,714 8,715 8,714
------- ------- ------- ------- ------- -------
Total MID-CONTINENT..... 161,192 94,701 51,416 44,077 212,608 138,778
BLACK WARRIOR BASIN....... 363 274 31,832 18,390 32,195 18,664
GULF COAST................ 8,234 5,100 36,974 16,387 45,208 21,487
------- ------- ------- ------- ------- -------
Grand Total............. 356,743 264,673 389,015 315,987 745,758 580,660
======= ======= ======= ======= ======= =======
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on its
properties for the periods indicated:
YEAR ENDED DECEMBER 31,
-----------------------
1999 2000 2001
---- ---- ----
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
DEVELOPMENT WELLS:
Productive............. 12 6.90 23 19.35 32 25.4
Non-productive......... 1 .16 3 2.92 15 7.3
-- ---- -- ----- -- ----
Total.................. 13 7.06 26 22.27 47 32.7
== ==== == ===== == ====
EXPLORATORY WELLS:
Productive............. 2 .74 15 9.26 11 5.7
Non-productive......... 2 1.25 7 2.99 10 5.5
-- ---- -- ----- -- ----
Total.................. 4 1.99 22 12.25 21 11.2
== ==== == ===== == ====
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, 1999, 83% of the PV-10 at December
31, 2000, and 97.6% of the PV-10 at December 31, 2001. The Company prepared the
reserve and present value data on all other properties.
AS OF DECEMBER 31,
------------------
1999 2000 2001
---- ---- ----
(DOLLARS IN THOUSANDS)
RESERVE DATA:
Proved developed reserves:
Oil (MBbl)..................... 34,432 33,173 31,325
Natural gas (MMcf)............. 65,723 58,438 56,647
Total (MBoe).............. 45,386 42,913 40,766
Proved undeveloped reserves:
Oil (MBbl)..................... 2,192 2,091 28,406
Natural gas (MMcf)............. 10,038 1,435 (4,381)
Total (MBoe).............. 3,865 2,330 27,676
Total proved reserves:
Oil (MBbl)......................... 36,624 35,264 59,731
Natural gas (MMcf)............. 75,761 59,873 52,267
Total (MBoe).............. 49,251 45,243 68,442
PV-10(1) .......................... $ 334,411 $ 491,799 $ 308,604
(1) PV-10 represents the present value of estimated future net cash flows
before income tax discounted at 10% using prices in effect at the end of
the respective periods presented. 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, 1999, 2000 and 2001, were $24.38 per
Bbl of oil and $1.76 per Mcf of natural gas, $26.80 per Bbl of oil and
$9.78 per Mcf of natural gas and $18.67 per Bbl of oil and $1.96 per Mcf of
natural gas, respectively.
Estimated quantities of proved reserves and future net cash flows therefrom
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 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 purchased. 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, 2001,
purchases of the Company's natural gas production by OneOk Field Services
accounted for 12% 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 64% 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 Company is paid by the hedging partner. 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 fourth quarter of 2001, the Company determined that it would
no longer enter into 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 April 1, 2002,
there were three record holders of the Company's common stock. The Company
issued no equity securities during 2001. During 2000, the Company established a
Stock Option Plan with 1,020,000 shares available, of which options to purchase
an aggregate of 144,000 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, 1997, 1998,
1999, 2000 and 2001, and the balance sheet data as of December 31, 1997, 1998,
1999, 2000 and 2001, have been derived from, and should be reviewed in
conjunction with, the consolidated financial statements of the Company, and the
notes thereto, which have been audited by Arthur Andersen LLP, independent
public accountants. The balance sheets as of December 31, 2000, and 2001, and
the statements of operations for the years ended December 31, 1999, 2000 and
2001, 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.
YEAR ENDED DECEMBER 31,
-----------------------
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
(DOLLARS IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales............................. $ 78,599 $ 60,162 $ 65,949 $ 115,478 $ 112,170
Crude oil marketing........................... -- 232,216 241,630 279,834 245,872
Gathering, marketing and processing........... 25,021 17,701 21,563 32,758 44,988
Oil and gas service operations................ 6,405 6,689 6,319 7,656 7,732
--------- ---------- --------- ---------- ---------
Total revenues.................................. 110,025 316,768 335,461 435,726 410,762
Operating costs and expenses:
Production expenses and taxes................. 20,748 22,611 19,368 29,807 36,791
Exploration expenses.......................... 6,806 7,106 7,750 13,321 19,927
Crude oil marketing purchases and expenses.... -- 228,797 236,135 278,809 245,003
Gathering, marketing and processing........... 22,715 15,602 17,850 27,593 35,475
Oil and gas service operations................ 3,654 3,664 3,420 5,582 5,294
Depreciation, depletion and amortization...... 33,354 38,716 20,385 21,945 33,569
General and administrative.................... 8,990 10,002 8,627 10,358 12,075
--------- ---------- --------- ---------- ---------
Total operating costs and expenses.............. 96,267 326,498 313,535 387,415 388,134
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Operating income (loss)......................... 13,758 (9,730) 21,926 48,311 22,628
Interest income................................. 241 967 310 756 630
Interest expense................................ (4,804) (12,248) (16,534) (15,786) (15,140)
Change in accounting principle (1).............. -- -- (2,048) -- --
Other revenue (expense), net(2)................. 8,061 3,031 266 4,499 3,549
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Income (loss) before income taxes............... 17,256 (17,980) 3,920 37,780 11,667
Federal and state income taxes (benefit)(3)..... (8,941) -- -- -- --
--------- ---------- --------- ---------- ---------
Net income (loss)............................... $ 26,197 $ (17,980) $ 3,920 $ 37,780 $ 11,667
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OTHER FINANCIAL DATA:
Adjusted EBITDA(4).............................. $ 54,721 $ 40,090 $ 48,589 $ 88,832 $ 80,304
Net cash provided by operations................. 51,477 25,190 23,904 69,690 58,701
Net cash used in investing...................... (78,359) (112,050) (13,698) (41,674) (101,672)
Net cash provided by (used in) financing........ 24,863 101,376 (15,602) (31,287) 43,045
Capital expenditures(5)......................... 80,937 92,782 55,255 49,339 106,311
RATIOS:
Adjusted EBITDA to interest expense............. 11.4x 3.3x 3.0x 5.6x 5.3x
Total debt to Adjusted EBITDA................... 1.5x 4.2x 3.5x 1.6x 2.2x
Earnings to fixed charges(6).................... 4.6x N/A 1.2x 3.3x 1.7x
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents....................... $ 1,301 $ 15,817 $ 10,421 $ 7,151 $ 7,225
Total assets.................................... 188,386 253,739 282,559 298,623 354,485
Long-term debt, including current maturities.... 79,632 167,637 170,637 140,350 183,395
Stockholders' equity............................ 78,264 60,284 86,666