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
====== ====== ====== ======== ===
<FN>
(1) Future estimated net cash flows discounted at 10%
</FN>
ROCKY MOUNTAINS
The Company's Rocky Mountain properties are located primarily in the
Williston Basin of North Dakota, South Dakota and Montana and in the Big Horn
Basin of Wyoming. Estimated proved reserves for its Rocky Mountains properties
at December 31, 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
========= ========= =========
<FN>
(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.
</FN>
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
==== ==== === === ==== ====
<FN>
(1) Represents Worland Field properties acquired by the Company in the Worland
Field Acquisition
</FN>
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
<FN>
(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.
</FN>
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
--------- ---------- --------- ---------- ---------
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
--------- ---------- --------- ---------- ---------
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
========= ========== ======== ========== =========
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 86,666 123,446 135,113
<FN>
(1) Change in accounting principle represents the cumulative effect impact of
adopting EITF 98-10 "Accounting for Energy Trading and Risk Management
Activities."
(2) In 1997, other income includes $7.5 million resulting from the settlement
of certain litigation matters.
(3) Effective June 1, 1997, the Company elected to be treated as a
S-Corporation for federal income tax purposes. The conversion resulted in
the elimination of the Company's deferred income tax assets and liabilities
existing at May 31, 1997 and, after being netted against the then existing
tax provision, resulted in a net income tax benefit to the Company of $8.9
million.
(4) Adjusted EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization and exploration expense, excluding
proceeds from litigation settlements. Adjusted EBITDA is not a measure of
cash flow as determined in accordance with GAAP. Adjusted EBITDA should not
be considered as an alternative to, or more meaningful than, net income or
cash flow as determined in accordance with GAAP or as an indicator of a
company's operating performance or liquidity. Certain items excluded from
adjusted EBITDA are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and
tax structure, as well as historic costs of depreciable assets, none of
which are components of Adjusted EBITDA. The Company's computation of
Adjusted EBITDA may not be comparable to other similarly titled measures of
other companies. The Company believes that Adjusted EBITDA is a widely
followed measure of operating performance and may also be used by investors
to measure the Company's ability to meet future debt service requirements,
if any. Adjusted EBITDA does not give effect to the Company's exploration
expenditures, which are largely discretionary by the Company and which, to
the extent expended, would reduce cash available for debt service,
repayment of indebtedness and dividends.
(5) Capital expenditures include costs related to acquisitions of producing oil
and gas properties and include the contribution of the Worland properties
by the principal stockholder of $22.4 million during the year ended
December 31, 1999 and the purchase of the assets of Farrar Oil Company and
Har-Ken Oil Company for $33.7 million during the year ended December 31,
2001.
(6) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income before taxes from continuing operations, and fixed
charges. Fixed charges consist of interest expense and amortization of
costs incurred in the offering of the Notes. For the year ended December
31, 1998, earnings were insufficient to cover fixed charges by $18.0
million.
</FN>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CRITICAL ACCOUNTING POLICIES AND PRACTICES
The use of estimates is necessary in the preparation of the Company's
consolidated financial statements. The circumstances that make these judgments
difficult, subjective and complex have to do with the need to make estimates
about the effect of matters that are inherently uncertain. The use of estimates
and assumptions affects the reported amounts of assets and liabilities. Such
estimates and assumptions also affect the disclosure of legal reserves,
abandonment reserves, oil and gas reserves and other contingent assets and
liabilities at the date of the consolidated financial statements, as well as
amounts of revenues and expenses recognized during the reporting period. Of the
estimates and assumptions that affect reported results, estimates of the
Company's oil and gas reserves are the most significant. Changes in oil and gas
reserves estimates impact the Company's calculation of depletion and abandonment
expense and is critical in the Company's assessment of asset impairments.
Management believes it is necessary to understand the Company's significant
accounting policies, "Item 8. Financial Statements and Supplementary Data-Note
2-Summary of Significant Accounting Policies" of this form 10-K, in order to
understand the Company's financial condition, changes in financial condition and
results of operations.
The following discussion should be read in conjunction with the Company's
consolidated financial statements and notes thereto and the selected
consolidated financial data included elsewhere herein.
OVERVIEW
The Company's revenue, profitability and cash flow are substantially
dependent upon prevailing prices for oil and gas and the volumes of oil and gas
it produces. The Company produced more oil and gas in 2001 than in 2000 and
experienced a significant decrease in revenues, net income and Adjusted EBITDA
in 2001 compared to 2000 because of lower prevailing oil prices. Average well
head prices during 2001 were $23.79 per Bbl of oil and $3.41 per Mcf of natural
gas compared to $29.02 per Bbl of oil and $2.91 per Mcf of natural gas during
2000. In addition, the Company's proved reserves and oil and gas production will
decline as oil and gas are produced unless the Company is successful in
increasing its reserves by acquiring producing properties or conducting
successful exploration and development drilling activities.
The Company uses the successful efforts method of accounting for its
investment in oil and gas properties. Under the successful efforts method of
accounting, costs to acquire mineral interests in oil and gas properties, to
drill and provide equipment for exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. These costs are amortized
to operations on a unit-of-production method based on petroleum engineering
estimates. Geological and geophysical costs, lease rentals and costs associated
with unsuccessful exploratory wells are expensed as incurred. Maintenance and
repairs are expensed as incurred, except that the cost of replacements or
renewals that expand capacity or improve production are capitalized. Significant
downward revisions of quantity estimates or declines in oil and gas prices that
are not offset by other factors could result in a write down for impairment of
the carrying value of oil and gas properties. Once incurred, a write down of an
oil and gas property is not reversible at a later date, even if oil or gas
prices increase.
The Company is an S-Corporation for federal income tax purposes. The
Company currently anticipates it will pay periodic dividends in amounts
sufficient to enable the Company's stockholders to pay their income tax
obligations with respect to the Company's taxable earnings. Based upon funds
available to the Company under its credit facility and the Company's anticipated
cash flow from operating activities, the Company does not currently expect these
distributions to materially impact the Company's liquidity.
RESULTS OF OPERATIONS
The following tables set forth selected financial and operating information
for each of the three years in the period ended December 31:
YEAR ENDED DECEMBER 31,
-----------------------
1999 2000 2001
---- ---- ----
(Dollars in Thousands, Except Average Price Data)
Revenues................................ $ 335,461 $ 435,726 $ 410,762
Operating expenses...................... 313,535 387,415 388,134
Non-Operating income (expense).......... (15,958) (10,530) (10,961)
Change in accounting principle.......... (2,048) -- --
Net income after tax.................... 3,920 37,780 11,667
Adjusted EBITDA(1)...................... 48,589 88,832 80,304
Production Volumes(2):
Oil and condensate (MBbl)............ 3,221 3,360 3,489
Natural gas (MMcf)................... 6,640 7,939 8,411
Oil equivalents (MBoe)............... 4,328 4,684 4,893
Average Prices(3):
Oil and condensate (per Bbl)......... $ 16.93 $ 29.02 $ 23.79
Natural gas (per Mcf)................ 1.72 2.91 3.41
Oil equivalents (per Boe)............ 15.24 25.81 22.92
<FN>
(1) Adjusted EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization and exploration expense, excluding
proceeds from litigation settlements. Adjusted EBITDA is not a measure of
cash flow as determined in accordance with GAAP. Adjusted EBITDA should not
be considered as an alternative to, or more meaningful than, net income or
cash flow as determined in accordance with GAAP or as an indicator of a
company's operating performance or liquidity. Certain items excluded from
Adjusted EBITDA are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and
tax structure, as well as historic costs of depreciable assets, none of
which are components of Adjusted EBITDA. The Company's computation of
Adjusted EBITDA may not be comparable to other similarly titled measures of
other companies. The Company believes that Adjusted EBITDA is a widely
followed measure of operating performance and may also be used by investors
to measure the Company's ability to meet future debt service requirements,
if any. Adjusted EBITDA does not give effect to the Company's exploration
expenditures, which are largely discretionary by the Company and which, to
the extent expended, would reduce cash available for debt service,
repayment of indebtedness and dividends.
(2) Production volumes of oil and condensate, and natural gas, are derived from
the Company's production records and reflect actual quantities produced
without regard to the time of receipt of proceeds from the sale of such
production. Production volumes of oil equivalents (on a Boe basis) are
determined by dividing the total Mcf of natural gas produced by six and by
adding the resultant sum to barrels of oil and condensate produced.
(3) Average prices of oil and condensate, and of natural gas, are derived from
the Company's production records which are maintained on an "as produced"
basis, which give effect to gas balancing and oil produced and in the
tanks, and, accordingly, may differ from oil and gas revenues for the same
periods as reflected in the financial statements. Average prices of oil
equivalents were calculated by dividing oil and gas revenues, as reflected
in the financial statements, by production volumes on a per Boe basis.
Average sale prices per Boe realized by the Company, according to its
production records which are maintained on an "as produced" basis, for the
years ended December 31, 1999, 2000 and 2001, were $15.31, $25.16 and
$22.86, respectively.
</FN>
YEAR ENDED DECEMBER 31, 2001, COMPARED TO YEAR ENDED DECEMBER 31, 2000
REVENUES
OIL AND GAS SALES
Oil and gas sales revenue for 2001 decreased $3.3 million, or 3%, to $112.2
million from $115.5 million in 2000 due primarily to a decrease of $5.23, or
18%, in oil prices from an average of $29.02/Bbl in 2000 to $23.79/Bbl in 2001.
This decrease in oil prices was offset by a slight increase of $0.50, or 17%, in
average gas sales price from an average of $2.91/Mcf in 2000 to $3.41/Mcf in
2001.
CRUDE OIL MARKETING
The Company recognized a decrease in revenues on crude oil purchased for
resale for 2001 of $33.9 million, or 12%, to $245.9 million from $279.8 million
for 2000. Total volumes decreased approximately 1.1 million barrels along with
the decrease in oil prices resulted in the decrease in crude oil marketing
revenues.
GATHERING, MARKETING AND PROCESSING
The 2001 gathering, marketing and processing revenues increased $12.2
million, or 37%, to $44.9 million compared to $32.7 million for 2000. Of this
increase, $5.3 million was attributable to operations from the south Texas
gathering systems, Driscoll and Arend, $2.2 million was from the Eagle Chief
Plant in Oklahoma and $1.5 million was from the Matli gas gathering system in
Oklahoma. The balance of the increase was due to an increase in annual gas
prices. These increases were offset by the sale of the Rattlesnake and
Enterprise systems in January 2000.
OIL AND GAS SERVICE OPERATIONS
Oil and gas service operations revenues increased less than 1% to $7.7 in
2001 from $7.6 million in 2000.
COSTS AND EXPENSES
PRODUCTION EXPENSES & TAXES
Production expense and taxes were $36.8 million for 2001, a $7.0 million,
or 23% increase over the 2000 expenses of $29.8 million, primarily as a result
of increased production volumes and energy costs. The increase was seen in all
areas of direct costs associated with the Company's operations except taxes.
Taxes decreased by approximately $1.0 million due to lower oil prices.
EXPLORATION EXPENSE
Exploration expenses increased $6.6 million, or 50%, to $19.9 million in
2001 from $13.3 million in 2000. The increase was attributable to a $6.2 million
increase in dry hole expenses and $2.7 million increase in plugging costs
associated with wells that have been uneconomical for the past three years,
offset by a $1.8 million decrease in expired leases and $0.7 million decrease in
other expenses.
CRUDE OIL MARKETING
Expense for crude oil purchased for resale decreased $33.8 million, or 12%,
to $245.0 million in 2001 from $278.8 million in 2000. This decrease was caused
by decreased crude oil prices and reduced volumes of crude oil purchased.
GATHERING, MARKETING AND PROCESSING
Gathering, marketing and processing expense for 2001 was $35.5 million, a
$7.9 million, or 29%, increase from the $27.6 million incurred in 2000 due to
increased system volumes resulting from the expansion of existing facilities and
the construction and operation of our new gathering and compression facilities
in the state of Texas and higher natural gas and liquid prices.
OIL AND GAS SERVICE OPERATIONS
Oil and gas service operations expenses decreased by $0.3 million, or 5%,
to $5.3 million in 2001 from $5.6 million in 2000. The decrease was primarily
due to salt water disposal operating expenses.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
For the year ended December 31, 2001, total DD&A expense was $33.6 million,
an $11.7 million, or 53%, increase over the 2000 expense of $21.9 million. In
2001, lease and well DD&A was $29.0 million, an increase of $11.6 million from
$17.4 million in 2000. The increase was mainly due to the DD&A associated with
the assets of Farrar Oil Company acquired in July 2001 and an increase FASB 121
write-down. 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. There
was a $1.7 million FASB 121 write- down in 2000 and a $5.3 million FASB 121
write-down in 2001. For 2001, DD&A expense amounted to $5.92 per Boe compared to
$3.71 per Boe in 2000.
GENERAL AND ADMINISTRATIVE (G&A)
G & A expense for 2001 was $12.1 million, net of overhead reimbursement of
$2.3 million, or $9.8 million, an increase of $1.3 million, or 16%, from G&A
expenses for 2000 of $10.3 million, net of overhead reimbursement of $1.9
million, or $8.4 million. The increase is primarily attributable to an increase
in employment expenses, legal costs and the acquisition of the assets of Farrar
Oil Company in July 2001.
INTEREST INCOME
Interest income for 2001 was $0.6 million compared to $0.8 million for
2000, a $0.2 million, or 25% decrease. The decrease in the 2001 period is
attributable to lower levels of cash invested during 2001.
INTEREST EXPENSE
Interest expense for 2001 was $15.1 million, a decrease of $0.7 million, or
4%, from $15.8 million in 2000. The decrease in the 2001 expense is attributable
primarily to the reduction in interest rates on the credit facility in the 2001
period and the purchased and retirement of $3.0 million of the outstanding
Notes by $3.0 million.
In May 1998, the Company entered into a forward interest rate swap contract
to hedge its exposure to changes in the prevailing interest rates in connection
with its planned debt offering. Due to the change in treasury note rates, the
Company paid $3.9 million to settle the forward interest rate swap contract,
which will result in an effective increase of approximately 0.5% to the
Company's interest costs on the Notes, or an increase in annual interest expense
of approximately $0.4 million for the term of the Notes. During 2001 and 2000,
the Company purchased $3.0 million and $19.9 million, respectively, of the Notes
which reduced the yearly interest expense attributable to the swap to $0.3
million for the remaining term of the Notes.
OTHER INCOME
Other income decreased $1.0 million, or 21%, to $3.5 million for the year
ended December 31, 2001, from $4.5 million for 2000. This decrease reflects a
$2.4 million gain on the sale of the Arkoma Basin properties and an
extraordinary gain of $0.7 million on the repurchase of the Notes during the
2000 period compared to the sale of 62 uneconomical wells at the Clearinghouse
Auction in 2001, which resulted in a gain of approximately $2.0 million and an
extraordinary gain of $0.1 million on the repurchase of the Notes in 2001.
NET INCOME
Net income for 2001 was $11.7 million, a decrease of $26.1 million,
compared to $37.8 million in 2000. This decrease reflects, among other items,
the lower oil prices which created a decrease in gross oil revenues and net
income of $8.8 million, an increase in DD&A expense of $11.6 million, which
includes an increase in FASB 121 write-down of $3.6 million, and an increase in
exploration expense of $6.6 million, which includes an increase of $6.2 million
of dry hole expenses.
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
OIL AND GAS SALES
Oil and gas sales revenue for 2000 increased $49.6 million, or 75%, to
$115.5 million from $65.9 million in 1999 due primarily to increases in oil
prices from an average of $16.93/Bbl in 1999 to $29.02/Bbl in 2000, or 71%, and
increases in average gas sales price increased from an average of $1.72/Mcf in
1999 to $2.91/Mcf in 2000, or 69%.
CRUDE OIL MARKETING
The Company recognized an increase in revenues on crude oil purchased for
resale for 2000 of $38.2 million, or 16%, to $279.8 million from $241.6 million
for 1999. This was caused by the increase in oil prices even though there was a
decrease in monthly volumes traded.
GATHERING, MARKETING AND PROCESSING
The 2000 gathering, marketing and processing revenues increased $11.1
million, or 51%, to $32.7 million compared to $21.6 million for 1999. Of this
increase, $7.7 million was attributable to operations from the Eagle Chief Plant
in Oklahoma and $2.8 million was from the Matli gas gathering system in Oklahoma
along with $1.7 million from the Badlands Gas Processing Plant in North Dakota.
These increases were offset by the sale of the Rattlesnake and Enterprise
systems in January 2000.
OIL AND GAS SERVICE OPERATIONS
Oil and gas service operations revenues increased $1.3 million, or 21%, to
$7.6 in 2000 from $6.3 million in 1999. The increase was primarily attributable
to increased sales of drilling material and supply items caused by increased
drilling activity in 2000 and increased revenues for reclaimed oil sales because
of higher prices.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Production expense and taxes were $29.8 million for 2000, a $10.4 million,
or 54%, increase over the 1999 expenses of $19.4 million, primarily as a result
of increased production volumes and higher prices. The increase was seen in all
areas of direct costs associated with the Company's operations and taxes. Taxes
increased by $4.9 million due to higher prices and the expiration of drilling
tax credits primarily in the Cedar Hills area of North Dakota.
EXPLORATION EXPENSE
Exploration expenses increased $5.6 million, or 72%, to $13.3 million in
2000 from $7.7 million in 1999. The increase was attributable to a $4.9 million
increase in dry hole expenses and a $2.7 million increase in prospect and other
expense. These increases were partially offset by a decrease in expired leases
and other expenses of $2.1 million.
CRUDE OIL MARKETING
Expense for crude oil purchased for resale increased $42.7 million, or 18%,
to $278.8 million in 2000 from $236.1 million in 1999. This increase was caused
by increased crude oil prices and offset by lower transportation fees.
GATHERING, MARKETING AND PROCESSING
Gathering, Marketing and Processing expense for 2000 was $27.6 million, a
$9.8 million, or 55%, increase from the $17.8 million incurred in 1999 due to
higher natural gas and liquid prices and the increase of volumes in the Badlands
system in North Dakota.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
For the year ended December 31, 2000, total DD&A expense was $21.9 million,
a $1.5 million, or 7%, increase over the 1999 expense of $20.4 million. In 2000,
lease and well DD&A was $17.4 million, an increase of $1.8 million from $15.6
million in 1999. The increase is mainly due to increased production from the
contribution of the Worland properties. There was no FASB 121 write-down in 1999
and a $1.7 million FASB 121 write-down in 2000. The majority of the 2000 amount
is on two wells in the Gulf Coast region that are non-economical along with
various other small amounts for wells in the Mid-Continent region that are
marginal wells which the Company is putting up for sale. For 2000, DD&A expense
amounted to $3.71 per Boe compared to $3.61 per Boe in 1999.
GENERAL AND ADMINISTRATIVE (G&A)
G & A expense for 2000 was $10.3 million, net of overhead reimbursement of
$1.9 million, or $8.4 million, an increase of $1.7 million, or 20%, from G&A
expenses for 1999 of $8.6 million, net of overhead reimbursement of $2.9
million, or $5.7 million. The increase is primarily attributable to an increase
in employment expenses and legal costs.
INTEREST INCOME
Interest income for 2000 was $0.8 million compared to $0.3 million for
1999, a $0.5 million, or 167% increase. The increase in the 2000 period was
attributable to greater levels of cash invested during 2000.
INTEREST EXPENSE
Interest expense for 2000 was $15.8 million, a decrease of $0.7 million, or
4%, from $16.5 million in 1999. The decrease in the 2000 expense is attributable
primarily to the reduction of the outstanding Notes by $19.9 million which the
Company purchased and retired. This will reduce interest expense by
approximately $2.0 million annually.
In May 1998, the Company entered into a forward interest rate swap contract
to hedge its exposure to changes in the prevailing interest rates in connection
with its planned debt offering. Due to the change in treasury note rates, the
Company paid $3.9 million to settle the forward interest rate swap contract,
which will result in an effective increase of approximately 0.5% to the
Company's interest costs on the Notes, or an increase in annual interest expense
of approximately $0.4 million for the term of the Notes. In 2000, the Company
purchased $19.9 million of the Notes which reduced the yearly interest expense
attributable to the swap to $0.3 million for the remaining term of the Notes.
OTHER INCOME
Other income increased $4.2 million, or 1,400%, to $4.5 million for the
year ended December 31, 2000, from $0.3 million for 1999. This increase in other
income compared to 1999 is attributed primarily to the recognition of a $2.4
million gain on the sale of the Arkoma Basin properties and an extraordinary
gain of $0.7 million on the repurchase of the Notes.
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE
Net income before income taxes and change in accounting principle for the
year ended December 31, 2000, was $37.8 million, an increase in net income
before taxes of $31.9 million from $5.9 million before income taxes and
cumulative effect of change in accounting principle for 1999. This increase was
primarily due to the increased revenues caused by higher oil and gas sales
prices.
NET INCOME
Net Income for 2000 was $37.8 million, an increase of $33.9 million
compared to $3.9 million in 1999. The Company adopted EITF 98-10 effective
January 1, 1999. As a result, the Company recorded an expense for the cumulative
effect of change in accounting principle of $2.0 million during the year ended
December 31, 1999.
LIQUIDITY AND CAPITAL ASSETS
The Company's primary sources of liquidity have been its cash flow from
operating activities, financing provided by its credit facility and by the
Company's principal stockholder and a private debt offering. The Company's cash
requirements, other than for operations, are for acquisition, exploration,
exploitation and development of oil and gas properties and debt service
payments.
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $58.7 million for 2001, a 16%
decrease from the $69.7 million in 2000. The decrease was primarily due to the
decrease in net income from operations which was primarily attributable to the
increase in DD&A and exploration expenses and oil price decreases.
RESERVES AND ADDED FINDING COSTS
The Company spent $49.3 million in 2000 and $106.3 million in 2001 on
acquisitions, exploration, exploitation and development of oil and gas
properties. Total estimated proved reserves of natural gas decreased from 59.9
Bcf at year-end 2000 to 52.3 Bcf at December 31, 2001, and estimated total
proved oil reserves increased from 35.3 MMBbls at year-end 2000 to 59.7 MMBbls
at December 31, 2001. The Company sold reserves of approximately 2.5 Bcf and 274
MBbls in May and December 2001 related to the sale of properties at the
Clearinghouse auctions.
FINANCING
Long-term debt at December 31, 2000, was $130.1 million and at December 31,
2001, was $178.0 million. The $47.9 million, or 37%, increase was mainly due to
a $46.0 million increase in the Company's bank debt. We used approximately $34.0
million of this increase for the purchase of the assets of Farrar Oil Company,
and $3.0 million for the repurchase and retirement of some of our Notes.
CREDIT FACILITY
Long-term debt outstanding at December 31, 2000, included $18.6 million of
revolving debt under the credit facility. The Company has $56.2 million
outstanding debt balance under the credit facility at December 31, 2001, of
which $31.9 million of the debt balance was a revolving loan and $24.3 million
was a term loan. We are required to amortize the term loan with quarterly
payments of $1.35 million due at the end of each quarter. The effective rate of
interest under the credit facility was 8.9% at December 31, 2000 and was 4.8% at
December 31, 2001. This credit facility is for borrowings up to $60 million and
bears interest at either the lead bank's prime rate or adjusted LIBOR which
includes the LIBOR rate as determined on a daily basis by the bank adjusted for
a facility fee percentage and non-use fee percentage according to the following
table. The applicable margins are based on a ratio of the outstanding balance to
the borrowing base.
Ratio LIBOR Margin Prime Rate Margin Unused Fee
----- ------------ ----------------- ----------
> 3 :1 2.25% 0.50% 25.00 basic points per annum
> 2 : 1 < 3 :1 2.00% 0.25% 22.50 basic points per annum
>1.50 : 1 < 2 :1 1.75% 0.00% 20.00 basic points per annum
1.49 : 1 1.50% 0.00% 18.75 basic points per annum
The LIBOR rate can be locked in for thirty, sixty or ninety days as
determined by the Company through the use of various principal tranches; or the
Company can elect to leave the interest rate based on the prime interest rate.
Interest is payable monthly with all outstanding principal and interest due at
maturity on May 31, 2003 on the revolving loan. A payment of $1.3 million is due
quarterly with interest due monthly with a maturity date of June 30, 2006.
Subsequent to December 31, 2001, the credit facility has been renegotiated and
the revolving loan was increase to $70 million. As of April 1, 2002, the Company
has borrowed $69.6 million against this credit facility.
At December 31, 2001, the Company had hedging contracts for a term of 15
months, which is a violation of a covenant of 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 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 also received a waiver of this covenant
violation. The Company does not expect to be in violation of these covenants in
the future.
SENIOR NOTES
On July 24, 1998, the Company consummated a private placement of $150.0
million of its 10-1/4% Senior Subordinated Notes due August 1, 2008, in a
private placement. Interest on the Notes is payable semi-annually on each
February 1 and August 1. In connection with the issuance of the Notes, the
Company incurred debt issuance costs of approximately $4.7 million, which has
been capitalized as other assets and is being amortized on a straight-line basis
over the life of the Notes. In May 1998 the Company entered into a forward
interest rate swap contract to hedge exposure to changes in prevailing interest
rates on the Notes. Due to changes in treasury note rates, the Company paid $3.9
million to settle the forward interest rate swap contract. This payment resulted
in an increase of approximately 0.5% to the Company's effective interest rate or
an increase of approximately $0.4 million per year over the term of the Notes.
During 2000, the Company repurchased $19.9 million principal amount of its
Notes at a cost of $18.3 million. The Company wrote off $0.9 million of the
issuance costs associated with the repurchase of the Notes.
During 2001, the Company repurchased $3.0 million principal amount of its
Notes at a cost of $2.7 million. The Company wrote off $0.1 million of the
issuance costs associated with the repurchase of the Notes.
CAPITAL EXPENDITURES
In 2001 the Company incurred $68.8 million of capital expenditures,
exclusive of acquisitions. The Company will initiate, on a priority basis, as
many projects as cash flow allows. It is anticipated that approximately 83
projects will be initiated in 2002 for projected capital expenditures of $91.3
million. The Company expects to fund the 2002 capital budget through cash flow
from operations and its credit facility.
STOCKHOLDER DISTRIBUTION
During 2002 the Company made no dividend distributions to its stockholders.
However, the Company may be required to dividend the stockholders an amount
sufficient to cover the taxes on the taxable income passed through to the
stockholders of record.
HEDGING
From time to time, the Company and its subsidiaries utilize energy
derivative contracts to hedge the price or basis risk associated with the
specifically identified purchase or sales contracts, oil and gas production or
operational needs. Prior to January 1, 2001, the Company accounted for changes
in the market value of derivative instruments used for hedging as a deferred
gain or loss until the production month of the hedged transaction, at which time
the gain or loss on the derivative instruments was recognized in earnings.
Effective January 1, 2001, the Company accounts for derivative instruments in
accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities." The specific accounting treatment for changes in the market value
of the derivative instruments used in hedging activities is determined based on
the designation of the derivative instruments as either a cash flow, fair value,
or foreign currency exposure hedge, and effectiveness of the derivative
instruments.
Additionally, in the normal course of business, the Company will enter into
fixed price forward sales contracts related to its oil and gas production to
reduce its sensitivity to oil and gas price volatility. Forward sales contracts
that will result in physical delivery of the Company's production are deemed to
be in the normal course of business and are not accounted for as derivatives.
In connection with the offering of the Notes, the Company entered into an
interest rate hedge on which it experienced a $3.9 million loss. The loss that
was incurred will result in an effective increase of approximately 0.5% to the
Company's interest costs on the Notes, or an increase in annual interest expense
of approximately $0.4 million over the term of the Notes. The Company has no
present plans to engage in further interest rate hedges.
OTHER
The Company follows the "sales method" of accounting for its gas revenue,
whereby the Company recognizes sales revenue on all gas sold, regardless of
whether the sales are proportionate to the Company's ownership in the gas
produced. A liability is recognized only to the extent that the Company has a
net imbalance in excess of its share of the reserves in the underlying
properties. The Company's historical aggregate imbalance positions have been
immaterial. The Company believes that any future periodic settlements of gas
imbalances will have little impact on its liquidity.
The Company has sold a number of non-strategic oil and gas properties and
other properties over the past three years, recognizing pretax gains of
approximately $151,400, $3,726,000 and $3,460,000 in 1999, 2000 and 2001
respectively. Total amounts of oil and gas reserves associated with these
dispositions during 1999, 2000 and 2001 were 281 MBbls of oil and 5,291 MMcf of
natural gas.
On May 15, 1998, the Company and Burlington Resources Oil & Gas Company,
Inc. ("Burlington") entered into an agreement ("Trade Agreement") to exchange
undivided interests in approximately 65,000 gross (59,000 net) leasehold acres
in the northern half of the Cedar Hills Field in North Dakota. On August 19,
1998, the Company instituted a declaratory judgment action against Burlington in
the District Court of Garfield County, Oklahoma. The Company sought a
declaratory judgment determining that it was excused from further performance
under the Trade Agreement. On December 22, 1999, the Court issued an Order
requiring the parties to proceed in accordance with terms of the Trade Agreement
and instructing them to use their best efforts to consummate the Trade
Agreement. Continental complied with the Order of the Court and attempted to
proceed with the terms of the Trade Agreement. However, substantial title
defects arose with respect to the interests to be received by Continental from
Burlington under the terms of the Trade Agreement. As a result of the title
defects which could result in the cancellation of Burlington's leases,
Continental filed a Motion to Dismiss seeking a determination by the Court that
Continental was excused from performance under the Trade Agreement. A hearing
was held the week of June 19, 2000. On October 11, 2000, the Court issued its
Findings of Fact, Conclusions of Law and Order holding that the Company was
excused from further performance under the Trade Agreement. The Court also
dismissed Burlington's claim for damages against the Company. On December 13,
2000, the Court entered a Final Order granting the Company's Motion to Dismiss
and denying Burlington's claim for damages. Burlington appealed the Final Order
entered by the Court. On January 22, 2001, the Company and Burlington entered
into an agreement finally resolving the litigation involving the Cedar Hills
Field and pleadings were filed with the Court which resulted in the dismissal
with prejudice of all claims between the Company and Burlington.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk in the normal course of its business
operations. Management believes that the Company is well positioned with its mix
of oil and gas reserves to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to impact the
domestic oil and gas industry. Due to the volatility of oil and gas prices, the
Company, from time to time, has used derivative hedging and may do so in the
future as a means of controlling its exposure to price changes. During 1998, the
Company began marketing crude oil. Most of the Company's purchases and sales
related to crude oil trading are made at either a NYMEX based price or a fixed
price.
RISK MANAGEMENT
The risk management process established by the Company is designed to
measure both quantitative and qualitative risks in its businesses. The Company
is exposed to market risk, including changes in interest rates and certain
commodity prices.
To manage the volatility relating to these exposures, periodically the
Company enters into various derivative transactions pursuant to the Company's
policies on hedging practices. Derivative positions are monitored using
techniques such as mark-to-market valuation and value-at-risk and sensitivity
analysis.
COMMODITY PRICE EXPOSURE
The market risk inherent in the Company's market risk sensitive instruments
and positions is the potential loss in value arising from adverse changes in the
Company's commodity prices.
The prices of crude oil, natural gas, and natural gas liquids are subject
to fluctuations resulting from changes in supply and demand. To partially reduce
price risk caused by these market fluctuations, the Company may hedge (through
the utilization of derivatives) a portion of the Company's production and sale
contracts. Because the commodities covered by these derivatives are
substantially the same commodities that the Company buys and sells in the
physical market, no special studies other than monitoring the degree of
correlation between the derivative and cash markets, are deemed necessary.
A sensitivity analysis has been prepared to estimate the price exposure to
the market risk of the Company's crude oil, natural gas and natural gas liquids
commodity positions. The Company's daily net commodity position consists of
crude inventories, commodity purchase and sales contracts and derivative
commodity instruments. The fair value of such position is a summation of the
fair values calculated for each commodity by valuing each net position at quoted
futures prices. Market risk is estimated as the potential loss in fair value
resulting from a hypothetical 10 percent adverse change in such prices over the
next 12 months. Based on this analysis, the Company has no significant market
risk related to its crude trading or hedging portfolios. During the fourth
quarter of 2001, the Company entered into forward fixed price sales contracts in
accordance with its hedging policy, to mitigate its exposure to the price
volatility associated with its crude oil production. The contracts total 60,000
barrels monthly through March 2003 at $21.98 per barrel. At December 31, 2001,
the Company had open fixed price sales contracts covering approximately 900,000
barrels.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and for Hedging Activities", with an effective date for
periods beginning after June 15, 1999. In July 1999 the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133". As a result of SFAS No. 137,
adoption of SFAS No. 133 was required for financial statements for periods
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities",
which amends the accounting and reporting standards of SFAS No. 133 for certain
derivative instruments and hedging activities. SFAS No. 133 sweeps in a broad
population of transactions and changes the previous accounting definition of a
derivative instrument. Under SFAS No. 133 every derivative instrument is
recorded on the balance sheet as either an asset or liability measured at its
fair value. SFAS No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. During 2000, management reviewed all contracts throughout the Company to
identify both freestanding and embedded derivatives which meet the criteria set
forth in SFAS No. 133 and SFAS No. 138. The Company adopted the new standards
effective January 1, 2001. The Company had no outstanding hedges or derivatives
which had not been previously marked to market through its accounting for
trading activity. As a result, the adoption of SFAS No. 133 and SFAS No. 138 had
no significant impact.
INTEREST RATE RISK
The Company's exposure to changes in interest rates relates primarily to
long-term debt obligations. The Company manages its interest rate exposure by
limiting its variable-rate debt to a certain percentage of total capitalization
and by monitoring the effects of market changes in interest rates. The Company
may utilize interest rate derivatives to alter interest rate exposure in an
attempt to reduce interest rate expense related to existing debt issues.
Interest rate derivatives are used solely to modify interest rate exposure and
not to modify the overall leverage of the debt portfolio. The fair value of
long-term debt is estimated based on quoted market prices and management's
estimate of current rates available for similar issues. The following table
itemizes the Company's long-term debt maturities and the weighted-average
interest rates by maturity date.
- -------------------------------------------------------------------------------------------------------------------
2001
Year-end
(dollars in millions) 2002 2003 2004 2005 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Principal amount 127,150 127,150 108,078
Weighted-average
interest rate 10.25% 10.25% --
Variable-rate debt:
Principal amount $5,400 $37,345 $5,400 $5,400 $2,700 $56,245 $56,245
Weighted-average
interest rate 4.8% 4.8% 4.8% 4.8% 4.8% 4.8% --
- -------------------------------------------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on Page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth names, ages and titles of the directors and
executive officers of the Company.
NAME AGE POSITION
- ----------------------------- --- ----------------------------------------------------------------------
Harold Hamm(1)(2)............ 56 Chairman of the Board of Directors, President, Chief Executive Officer
and Director
Jack Stark(1)(3)............. 47 Senior Vice President--Exploration and Director
Jeff Hume.................... 51 Senior Vice President--Drilling Operations
Randy Moeder................. 41 Secretary; President - Continental Gas, Inc.
Roger Clement(1)(4).......... 57 Senior Vice President, Chief Financial Officer, Treasurer and Director
Mark Monroe(3)............... 47 Director
Robert Kelley(2)............. 56 Director
H. R. Sanders(4)............. 69 Director
<FN>
(1) Member of the Executive, Compensation and Audit Committees.
(2) Term expires in 2002.
(3) Term expires in 2003.
(4) Term expires in 2004.
</FN>
HAROLD HAMM, LL.M. has been President and Chief Executive Officer and a
Director of the Company since its inception in 1967. Mr. Hamm has served as
President of the Oklahoma Independent Petroleum Association Wildcatter's Club
since 1989 and was the founder and is Chairman of the Oklahoma Natural Gas
Industry Task Force. He has served as a member of the Interstate of Oil and Gas
Compact Commission and is a founding board member of the Oklahoma Energy
Resources Board. Mr. Hamm serves on the Tax Steering Committee of the
Independent Petroleum Association of America and is a director of the Rocky
Mountain Oil and Gas Association. The Oklahoma Independent Petroleum Association
named Mr. Hamm Member of the Year in 1992. He is currently President of the
National Stripper Well Association.
JACK STARK joined the Company as Vice President of Exploration in June 1992
and was promoted to Senior Vice President in May 1998. Mr. Stark has been a
Director of the Company since September 1996. He holds a Masters degree in
Geology from Colorado State University and has 20 years of exploration
experience in the Mid-Continent, Gulf Coast and Rocky Mountain regions. Prior to
joining the Company, Mr. Stark was the exploration manager for the Western
Mid-Continent Region for Pacific Enterprises from August 1988 to June 1992. From
1978 to 1988, he held various staff and middle management positions with Cities
Service Co. and TXO Production Corp. Mr. Stark is a member of the American
Association of Petroleum Geologists, Oklahoma Independent Petroleum Association,
Rocky Mountain Association of Geologists, Houston Geological Society and
Oklahoma Geological Society.
JEFF HUME has been Vice President of Drilling Operations and a Director of
the Company since September 1996 and was promoted to Senior Vice President in
May 1998. From May 1983 to September 1996, Mr. Hume was Vice President of
Engineering and Operations. Prior to joining the Company, Mr. Hume held various
engineering positions with Sun Oil Company, Monsanto Company and FCD Oil
Corporation. Mr. Hume is a Registered Professional Engineer and member of the
Society of Petroleum Engineers, Oklahoma Independent Petroleum Association, and
the Oklahoma and National Professional Engineering Societies.
RANDY MOEDER has been President of Continental Gas, Inc. since January 1995
and was Vice President of Continental Gas, Inc. from November 1990 to January
1995. Mr. Moeder has served as Secretary of the Company since February 1994. Mr.
Moeder was Senior Vice President and General Counsel of the Company from May
1998 to August 2000 and was Vice President and General Counsel from November
1990 to April 1998. From January 1988 to summer 1990, Mr. Moeder was in private
law practice. From 1982 to 1988, Mr. Moeder held various positions with Amoco
Corporation. Mr. Moeder is a member of the Oklahoma Independent Petroleum
Association and the Oklahoma and American Bar Associations. Mr. Moeder is also a
Certified Public Accountant.
ROGER CLEMENT became Vice President, Chief Financial Officer, Treasurer and
a Director of the Company in March 1989 and was promoted to Senior Vice
President in May 1998. He holds a Bachelor of Business Administration degree
from the University of Oklahoma and is a Certified Public Accountant. Prior to
joining the Company, Mr. Clement was a partner in the accounting firm of Hunter
and Clement in Oklahoma City for 17 years. The firm provided accounting, tax,
audit and consulting services for various industries. Mr. Clement's clients were
primarily involved in oil and gas and real estate. He was also a 50% partner in
a construction company from 1973 to 1984 that constructed residential real
estate and small commercial properties. He is a member of the Oklahoma
Independent Petroleum Association, the American Institute of Certified Public
Accountants and the Oklahoma Society of Certified Public Accountants..
MARK MONROE was the Chief Executive Officer and President of Louis Dreyfus
Natural Gas prior to its merger with Dominion Resources in October 2001. Prior
to the formation of Louis Dreyfus Natural Gas in 1990, he was the Chief
Financial Officer of Bogert Oil Company. He currently serves as the President of
the Oklahoma Independent Petroleum Association and is a Board member of the
Petroleum Club of Oklahoma City. Previously Mr. Monroe served on the Domestic
Petroleum Council and the Board of the Independent Petroleum Association of
America. Mr. Monroe is a Certified Public Accountant and received his Bachelor
of Business Administration degree from the University of Texas at Austin.
ROBERT KELLEY served as Chairman of the Board of Noble Affiliates, Inc.,
from 1992 until he retired in 2000. Noble Affiliates, Inc. is an independent
energy company with exploration and production operations throughout the United
States, the Gulf of Mexico, and international operations in Argentina, China,
Ecuador, Equatorial Guinea, the Mediterranean Sea, the North Sea, and Vietnam.
Prior to October 2000 he also served as President and Chief Executive Officer of
Noble Affiliates, Inc. and its three subsidiaries, Samedan Oil Corporation,
Noble Gas Marketing, Inc., and Noble Trading, Inc. He is a Director of OG&E
Energy Corporation, a public utility headquartered in Oklahoma; Prize Energy
Corporation, an independent energy company located in Texas; and Lone Star
Technologies, Inc., a leading manufacturer of oilfield tubular goods also
located in Texas. Mr. Kelley attended the University of Oklahoma and received a
Bachelor of Business Administration degree and he is a Certified Public
Accountant.
H. R. SANDERS, JR. served as a Director of Devon Energy Corporation from
1981 through 2000. In addition, he held the position of Executive Vice President
of Devon from 1981 until his retirement in 1997. Prior to joining Devon, Mr.
Sanders served RepublicBank of Dallas, N.A. from 1970 to 1981 as the bank's
Senior Vice President with direct responsibility for independent oil, gas and
mining loans. Mr. Sanders is a former member of the Independent Petroleum
Association of America, Texas Independent Producers and Royalty owners
Association and Oklahoma Independent Petroleum Association. He currently is a
Director on the Board of Torreador Resources Corporation and is also a past
Director of Triton Energy Corporation.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
Securities
Underlying
Annual Compensation Other Annual Option All Other
------------------------- Compensation Awards Compensation
Name Year Salary($) Bonus($) ($)(1) (# of shares)(2) ($)(3)
- ---- ---- --------- -------- ------ ---------------- ------
Harold Hamm 2001(4).... $ -- $ -- $ -- -- $ --
2000....... 500,000 -- -- -- --
1999(4).... -- -- -- -- --
Jack Stark 2001....... 151,384 17,996 -- -- 11,244
2000....... 139,456 16,850 -- 32,000 10,648
1999....... 131,616 5,000 -- -- 8,942
Jeff Hume 2001....... 125,580 15,747 -- -- 22,029
2000....... 119,226 15,820 -- 32,000 21,711
1999....... 125,456 5,000 -- -- 12,094
Roger Clement 2001....... 127,500 15,883 -- -- 12,068
2000....... 120,376 15,406 -- 40,000 7,558
1999....... 106,008 5,000 -- -- 3,756
Randy Moeder 2001....... 124,208 25,197 -- -- 21,217
2000....... 121,335 16,024 -- 25,000 11,817
1999....... 102,313 20,000 -- -- 8,200
<FN>
(1) Represents the value of perquisites and other personal benefits in excess
of the lesser of $50,000 or 10% of annual salary and bonus. For the years
ended December 31, 1999, 2000 and 2001, the Company paid no other annual
compensation to its named executive officers.
(2) The Company adopted its 2000 Stock Option Plan effective October 1, 2000,
and allocated a maximum of 1,020,000 shares of Common Stock to this plan.
Effective October 1, 2000, the Company granted Incentive Stock Options to
purchase 90,000 shares and Non-qualified Options to purchase 54,000 shares.
(3) Represents contributions made by the Company to the accounts of executive
officers under the Company's profit sharing plan and under the Company's
nonqualified compensation plan.
(4) Received no compensation during the calendar year 1999 and 2001.
</FN>
2001 Year-End Option Value
Number of Securities Underlying Value of Unexercised In-the-Money
Unexercised Options at 12/31/01(#) Options at 12/31/01($)
Name Exercisable/Unexercisable Exercisable/Unexercisable(1)
- ---- -------------------------- -----------------------------
Jack Stark 8,000/24,000 $28,000/$56,000
Jeff Hume 8,000/24,000 $28,000/$56,000
Roger Clement 10,666/29,334 $47,000/$93,000
Randy Moeder 5,667/19,333 $12,000/$23,000
<FN>
(1) The value of unexercised in-the-money options at December 31, 2001 is
computed as the product of the stock value at December 31, 2001, assumed to
be $14.00 per share, less the stock option exercise price, and the number
of underlying securities at December 31, 2001.
</FN>
Employment Agreements
The Company does not have formal employment agreements with any of its
employees.
Stock Option Plan
The Company adopted its 2000 stock option plan to encourage its key
employees by providing opportunities to participate in its ownership and future
growth through the grant of incentive stock options and nonqualified stock
options. The plan also permits the grant of options to the Company's directors.
The plan is presently administered by the Company's Board of Directors.
2000 Stock Incentive Plan
The Company adopted the 2000 stock incentive plan effective October 1,
2000. The maximum number of shares for which it may grant options under the plan
is 1,020,000 shares of common stock, subject to adjustment in the event of any
stock dividend, stock split, recapitalization, reorganization or certain defined
change of control events. Shares subject to previously expired, canceled,
forfeited or terminated options become available again for grants of options.
The shares that the Company will issue under the plan will be newly issued
shares.
The Board of Directors determines the number of shares and other terms of
each grant. Under its plan, the Company may grant either incentive stock options
or nonqualified stock options. The price payable upon the exercise of an
incentive stock option may not be less than 100% of the fair market value of the
Company's common stock at the time of grant, or in the case of an incentive
stock option granted to an employee owning stock possessing more than 10% of the
total combined voting power of all classes of the Company's common stock, 110%
of the fair market value on the date of grant. The Company may grant incentive
stock options to an employee only to the extent that the aggregate exercise
price of all such options under all of its plans becoming exercisable for the
first time by the employee during any calendar year does not exceed $100,000.
The committee may not grant a nonqualified stock option at an exercise price
which is less than 50% of the fair market value of the Company's common stock on
the date of grant.
Each option that the Company has granted or will grant under the plan will
expire on the date specified by the committee, but not more than ten years from
the date of grant or, in the case of a 10% shareholder, not more than five years
from the date of grant. Unless otherwise agreed, an incentive stock option will
terminate not more than 90 days, or twelve months in the event of death or
disability, after the optionee's termination of employment.
An optionee may exercise an option by giving writing notice to the Company,
accompanied by full payment:
o in cash or by check, bank draft or money order payable to us;
o by delivering shares of the Company's common stock or other equity
securities having a fair market value equal to the exercise price; or
o a combination of the foregoing.
Outstanding options become nonforfeitable and exercisable in full
immediately prior to certain defined change of control events. Unless otherwise
determined by the committee, outstanding options will terminate on the effective
date of the Company's dissolution or liquidation.
The plan may be terminated or amended by the board of directors at any time
subject, in the case of certain amendments, to shareholder approval. If not
earlier terminated, the plan expires on September 30, 2010.
With certain exceptions, Section 162(m) of the Internal Revenue Code denies
a deduction to publicly-held corporations for compensation paid to certain
executive officers in excess of $1.0 million per executive per taxable year
(including any deduction with respect to the exercise of an option). An
exception exists, however, for amounts received upon exercise of stock options
pursuant to certain grand fathered plans. Options granted under the Company's
plan are expected to satisfy this exception.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
PRINCIPAL STOCKHOLDERS
The following table sets forth certain information regarding the beneficial
ownership of the Company's common stock as of April 1, 2002 held by:
o each of the Company's directors who owns common stock;
o each of the Company's executive officers who owns common stock;
o each person known or believed by the Company to own beneficially 5% or more
of the Company's common stock; and
o all of the Company's directors and executive officers as a group.
Unless otherwise indicated, each person has sole voting and dispositive
power with respect to such shares. The number of shares of common stock
outstanding for each listed person includes any shares the individual has the
right to acquire within 60 days of this prospectus.
Shares of Ownership
Name of Beneficial Owner Common Stock Percentage
- ------------------------ ------------ ----------
Harold Hamm (1)(2) 13,037,328 90.7%
302 North Independence
Enid, Oklahoma 73702
All executive officers and
directors as a group 13,037,328 90.7%
(5 persons)
<FN>
(1) Director
(2) Executive officer
</FN>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Set forth below is a description of transactions entered into between the
Company and certain of its officers, directors, employees and stockholders
during 2001. Certain of these transactions will continue in the future and may
result in conflicts of interest between the Company and such individuals, and
there can be no assurance that conflicts of interest will always be resolved in
favor of the Company.
OIL AND GAS OPERATIONS. In its capacity as operator of certain oil and gas
properties, the Company obtains oilfield services from related companies. These
services include leasehold acquisition, well location, site construction and
other well site services, saltwater trucking, use of rigs for completion and
workover of oil and gas wells and the rental of oil field tools and equipment.
Harold Hamm is the chief executive officer and principal stockholder of each of
these related companies. The aggregate amounts paid by Continental to these
related companies during 2001 was $10.9 million and at December 31, 2001, the
Company owed these companies approximately $0.3 million in current accounts
payable. The services discussed above were provided at costs and upon terms that
management believes are no less favorable to the Company than could have been
obtained from unrelated parties. In addition, Harold Hamm and certain companies
controlled by him own interests in wells operated by the Company. At December
31, 2001, the Company owed such persons an aggregate of $0.1 million,
representing their shares of oil and gas production sold by the Company. During
2001, in its capacity as operator of certain oil and gas properties located in
Wyoming, the Company began selling natural gas produced from the Worland Field
to a related party. During 2001, the Company sold natural gas valued at $1.77
million to this third party.
OFFICE LEASE. The Company leases office space under operating leases
directly or indirectly from the principal stockholder and an affiliate of the
principal stockholder. In 2001, the Company paid rents associated with these
leases of approximately $334,000. The Company believes that the terms of its
lease are no less favorable to the Company than those which would be obtained
from unaffiliated parties.
PARTICIPATION IN WELLS. Certain officers and directors of the Company have
participated in, and may participate in the future in, wells drilled by the
Company, or as in the principal stockholder's case the acquisition of
properties. At December 31, 2001, the aggregate unpaid balance owed to the
Company by such officers and directors was $4,734, none of which was past due.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following financial statements of the Company and the Report of the
Company's Independent Public Accountants thereon are included on pages F-1
through F-21 of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 2000 and 2001
Consolidated Statement of Operations for the three years in the period ended
December 31, 2001
Consolidated Statement of Cash Flows for the three years in the period ended
December 31, 2001
Consolidated Statement of Stockholder's Equity for the three years in the period
ended December 31, 2001
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
None.
3. EXHIBITS:
2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc.
dated October 1, 2000.[2.1](4)
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc.[3.1](1)
3.2 Amended and Restate Bylaws of Continental Resources, Inc. [3.2] (1)
3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3] (1)
3.4 Bylaws of Continental Gas, Inc., as amended and restated. [3.4] (1)
3.5 Certificate of Incorporation of Continental Crude Co. [3.5] (1)
3.6 Bylaws of Continental Crude Co. [3.6] (1)
4.1 Restated Credit Agreement dated April 21, 2000 among Continental
Resources, Inc. and Continental Gas, Inc., as Borrowers and MidFirst
Bank as Agent (the "Credit Agreement") [4.4] (3)
4.1.1 Form of Consolidated Revolving Note under the Credit Agreement [4.4]
(3)
4.1.2 Second Amended and Restated Credit Agreement among Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and MidFirst Bank, dated July 9,
2001.[10.1](5)
4.1.3* Third Amended and Restated Credit Agreement among Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and MidFirst Bank, dated January 17,
2002.
4.3 Indenture dated as of July 24, 1998 between Continental Resources,
Inc., as Issuer, the Subsidiary Guarantors named therein and the
United States Trust Company of New York, as Trustee [4.3] (1)
10.4 Conveyance Agreement of Worland Area Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April
23, 1984 to Continental Resources, Inc. [10.4](2)
10.5 Purchase Agreement signed January 2000, effective October 1, 1999, by
and between Patrick Energy Corporation as Buyer and Continental
Resources, Inc. as Seller [10.5](2)
10.6+ Continental Resources, Inc. 2000 Stock Option Plan. [10.6](4)
10.7+ Form of Incentive Stock Option Agreement. [10.7](4)
10.8+ Form of Non-Qualified Stock Option Agreement. [10.8](4)
10.9 Purchase and Sales Agreement between Farrar Oil Company and Har-Ken
Oil Company, as Sellers, and Continental Resources of Illinois, Inc.
as Purchaser, dated May 14, 2001.[2.1](5)
12.1* Statement re computation of ratio of debt to Adjusted EBITDA
12.2* Statement re computation of ratio of earning to fixed charges
12.3* Statement re computation of ratio of Adjusted EBITDA to interest
expense
21.0 Subsidiaries of Registrant. [21] (6)
99.1* Letter to the Securities and Exchange Commission dated March 28, 2002,
regarding the audit of the Registrant's financial statements by Arthur
Andersen LLP.
_________________________
+ Represents management compensatory plan
* Filed herewith
(1) Filed as an exhibit to the Company's Registration Statement on Form S-4, as
amended (No. 333-61547) which was filed with the Securities and Exchange
Commission. The exhibit number is indicated in brackets and is incorporated
herein by reference.
(2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1999. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended March 31, 2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(4) Filed as an exhibit to the Company's Quarterly Report on Form 10 for the
fiscal quarter ended December 31, 2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current report on Form 8-K dated July 18, 2001. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) Filed as an exhibit to the Company's Quarterly Report on Form 10 for the
fiscal quarter ended June 30, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(b) REPORTS ON FORM 8-K
On July 18, 2001, the Registrant filed a current report on Form K
describing the purchase of certain oil and gas properties from Farrar Oil
Company and Har-Ken Oil Company, and the Second Amended and Restated Credit
Agreement with MidFirst Bank.
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
April 1, 2002 Continental Resources Inc.
By HAROLD HAMM
Harold Hamm
Chairman of the Board, President
And Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in capacities and on the date indicated.
Signatures Title Date
- ---------- ----- ----
HAROLD HAMM
Harold Hamm Chairman of the Board, April 1, 2002
President, Chief Executive
Officer (principal executive
officer) and Director
ROGER V. CLEMENT
Roger V. Clement Senior Vice President and April 1, 2002
Chief Financial Officer
(Principal financial officer
and principal accounting
officer), Treasurer,
and Director
JACK STARK
Jack Stark Senior Vice President and April 1, 2002
Director
MARK MONROE
Mark Monroe Director April 1, 2002
RANDY MOEDER
Randy Moeder Secretary; President of April 1, 2002
Continental Gas, Inc.
JEFF HUME
Jeff Hume Senior Vice President April 1, 2002
Supplemental Information to be Furnished With Reports Pursuant to Section
15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to
Section 12 of the Act.
The Company has not sent, and does not intend to send, an annual report to
security holders covering its last fiscal year, nor has the Company sent a proxy
statement, form of proxy or other proxy soliciting material to its security
holders with respect to any annual meeting of security holders.
INDEX OF FINANCIAL STATEMENTS
Report of Independent Public Accountants ..................................F - 2
Consolidated Balance Sheets as of December 31, 2000 and 2001 ..............F - 3
Consolidated Statements of Operations for the Years Ended December 31
1999, 2000 and 2001 .......................................................F - 4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 2000 and 2001 ..........................................F - 5
Consolidated Statements of Cash Flows for the Years Ended December 31
1999, 2000 and 2001 .......................................................F - 6
Notes to Consolidated Financial Statements ................................F - 8
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Continental
Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31,
2000 and 2001, and the related consolidated statements of income, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2001. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Continental
Resources, Inc. and subsidiaries as of December 31, 2000 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
February 15, 2002
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share information)
ASSETS
December 31,
------------
2000 2001
---- ----
CURRENT ASSETS:
Cash..................................................$ 7,151 $ 7,225
Accounts receivable-
Oil and gas sales................................ 15,778 7,731
Joint interest and other, net.................... 9,839 10,526
Inventories........................................... 4,988 6,321
Prepaid expenses...................................... 209 487
---------- -----------
Total current assets...................... 37,965 32,290
---------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)-
Producing properties............................. 321,197 395,559
Nonproducing leaseholds.......................... 44,544 50,889
Gas gathering and processing facilities............... 25,051 28,176
Service properties, equipment and other............... 15,917 17,427
---------- -----------
Total property and equipment.............. 406,709 492,051
Less--Accumulated depreciation, depletion
and amortization....................... (151,899) (174,720)
---------- -----------
Net property and equipment................ 254,810 317,331
---------- -----------
OTHER ASSETS:
Debt issuance costs, net.............................. 5,842 4,851
Other assets.......................................... 6 13
---------- -----------
Total other assets........................ 5,848 4,864
---------- -----------
Total assets..............................$ 298,623 $ 354,485
========== ===========
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share information)
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31,
------------
2000 2001
---- ----
CURRENT LIABILITIES:
Accounts payable......................................... $ 17,164 $ 22,576
Current portion of long-term debt........................ 10,200 5,400
Revenues and royalties payable........................... 7,181 3,404
Accrued liabilities and other............................ 10,375 9,906
---------- ----------
Total current liabilities........................... 44,920 41,286
---------- ----------
LONG-TERM DEBT, net of current portion....................... 130,150 177,995
OTHER NONCURRENT LIABILITIES................................. 107 91
COMMITMENTS AND CONTINGENCIES (Note 8).......................
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 1,000,000 shares authorized,
0 shares issued and outstanding at December 31, 2000 and
2001.
Common stock, $0.01 par value, 20,000,000 shares authorized,
14,368,919 shares issued and outstanding at December 31,
2000 and 2001........................................ 144 144
Additional paid-in capital................................ 25,087 25,087
Retained earnings......................................... 98,215 109,882
---------- ----------
Total stockholders' equity...................... 123,446 135,113
---------- ----------
Total liabilities and stockholders' equity...... $ 298,623 $ 354,485
========== ==========
The accompanying notes are an integral part of these consolidated balance
sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share information)
December 31,
------------
1999 2000 2001
---- ---- ----
REVENUES:
Oil and gas sales .......................... $ 65,949 $ 115,478 $ 112,170
Crude oil marketing.......................... 241,630 279,834 245,872
Gas gathering, marketing and processing...... 21,563 32,758 44,988
Oil and gas service operations............... 6,319 7,656 7,732
--------- --------- ---------
Total revenues.......................... 335,461 435,726 410,762
--------- --------- ---------
OPERATING COSTS AND EXPENSES:
Production expenses .......................... 14,796 20,301 28,406
Production taxes .......................... 4,572 9,506 8,385
Exploration expenses.......................... 7,750 13,321 19,927
Crude oil marketing purchases and expenses.... 236,135 278,809 245,003
Gas gathering, marketing and processing....... 17,850 27,593 35,475
Oil and gas service operations................ 3,420 5,582 5,294
Depreciation, depletion and amortization...... 20,385 21,945 33,569
General and administrative.................... 8,627 10,358 12,075
--------- --------- ---------
Total operating costs and expenses....... 313,535 387,415 388,134
--------- --------- ---------
OPERATING INCOME.................................. 21,926 48,311 22,628
--------- --------- ---------
OTHER INCOME ( EXPENSE):
Interest income .......................... 310 756 630
Interest expense .......................... (16,534) (15,786) (15,140)
Other income, net .......................... 266 4,499 3,549
--------- --------- ---------
Total other income (expense)............ (15,958) (10,531) (10,961)
--------- --------- ---------
INCOME BEFORE
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.............................. 5,968 37,780 11,667
CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE .............. (2,048) -- --
--------- --------- ---------
NET INCOME $ 3,920 $ 37,780 $ 11,667
========= ========= =========
EARNING PER COMMON SHARE:
Before cumulative effect of change in
accounting principle
Basic .......................... $ .42 $ 2.63 $ .81
========= ========= =========
Diluted .......................... $ .42 $ 2.62 $ .81
========= ========= =========
After cumulative effect of change in
accounting principle
Basic .......................... $ .27 $ 2.63 $ .81
========= ========= =========
Diluted .......................... $ .27 $ 2.62 $ .81
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
(in thousands)
Additional Total
Shares Common Paid-in Retained Stockholders'
Outstanding Stock Capital Earnings Equity
----------- ----- ------- -------- ------
BALANCE, December 31, 1999 14,368,919 $ 144 $ 25,087 $ 61,435 $ 86,666
Net income -- -- -- 37,780 37,780
Dividends paid -- -- -- (1,000) (1,000)
---------- -------- -------- --------- ---------
BALANCE, December 31, 2000 14,368,919 $ 144 $ 25,087 $ 98,215 $ 123,446
Net income -- -- -- 11,667 11,667
Dividends paid -- -- -- -- --
---------- -------- -------- --------- ---------
BALANCE, December 31, 2001 14,368,919 $ 144 $ 25,087 $ 109,882 $ 135,113
========== ======== ======== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
(in thousands)
1999 2000 2001
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,920 $ 37,780 $ 11,667
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation, depletion and amortization 20,385 21,945 33,569
Gain on sale of assets (151) (3,719) (3,460)
Dry hole costs and impairment of undeveloped leases 5,978 7,667 9,575
Other non-current assets and liabilities 338 1,373 435
Changes in current assets and liabilities-
Decrease (increase) in accounts receivable (5,037) (5,591) 7,360
Decrease (increase) in inventories 515 (876) (1,333)
Decrease (increase) in prepaid expenses (1,522) 1,481 (278)
Increase (decrease) in accounts payable (2,084) 8,716 5,411
Increase (decrease) in revenues and royalties payable 1,010 315 (3,776)
Increase (decrease) in accrued liabilities and other 552 599 (469)
----------- ----------- -----------
Net cash provided by operating activities 23,904 69,690 58,701
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (12,233) (48,139) (63,411)
Gas gathering and processing facilities and service
properties, equipment and other (266) (1,200) (6,365)
Purchase of producing and non-producing properties (1,695) -- (36,535)
Proceeds from sale of assets 496 7,665 4,639
----------- ----------- -----------
Net cash used in investing activities (13,698) (41,674) (101,672)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 4,600 37,000 52,245
Repayment of Senior Subordinated Notes -- (19,850) (3,000)
Repayment of line of credit and other (10,202) (47,436) (6,200)
Repayment of short-term debt due to stockholder (10,000) -- --
Payment of cash dividend -- (1,000) --
----------- ----------- -----------
Net cash provided by (used in) financing activities (15,602) (31,286) 43,045
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH (5,396) (3,270) 74
CASH, beginning of year 15,817 10,421 7,151
----------- ----------- -----------
CASH, end of year $ 10,421 $ 7,151 $ 7,225
=========== =========== ==========
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 16,583 $ 16,615 $ 15,269
NONCASH INVESTING AND FINANCING ACTIVITIES:
Contribution of interest in oil and gas properties by
stockholder
Oil and gas properties $ 41,061 $ -- $ --
Assumption of note payable $ 18,600 $ -- $ --
Paid-in capital $ 22,461 $ -- $ --
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION:
Continental Resources, Inc. ("CRI") was incorporated in Oklahoma on
November 16, 1967, as Shelly Dean Oil Company. On September 23, 1976, the name
was changed to Hamm Production Company. In January 1987, the Company acquired
all of the assets and assumed the debt of Continental Trend Resources, Inc.
Affiliated entities, J.S. Aviation and Wheatland Oil Co. were merged into Hamm
Production Company, and the corporate name was changed to Continental Trend
Resources, Inc. at that time. In 1991, the Company's name was changed to
Continental Resources, Inc.
CRI has three wholly-owned subsidiaries, Continental Gas, Inc. ("CGI"),
Continental Resources of Illinois, Inc. ("CRII") and Continental Crude Co.
("CCC"). CGI was incorporated in April 1990, CRII was incorporated in June 2001
for the purpose of acquiring the assets of Farrar Oil Company and Har-Ken Oil
Company and CCC was incorporated in May 1998. Since its incorporation, CCC has
had no operations, has acquired no assets and has incurred no liabilities.
CRI and CRII's principal business is oil and natural gas exploration,
development and production. CRI and CRII have interests in approximately 2,066
wells and serve as the operator in the majority of these wells. CRI and CRII's
operations are primarily in Oklahoma, North Dakota, South Dakota, Montana,
Wyoming, Texas, Illinois, Mississippi and Louisiana. In July 1998, CRI began
entering into third party contracts to purchase and resell crude oil at prices
based on current month NYMEX prices, current posting prices or at a stated
contract price.
CGI is engaged principally in natural gas marketing, gathering and
processing activities and currently operates six gas gathering systems and two
gas processing plants in its operating areas. In addition, CGI participates with
CRI in certain oil and natural gas wells.
All per share amounts for the Company's common stock have been
retroactively adjusted to reflect the Company's stock split, discussed in Note
6.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Basis of Presentation
The accompanying consolidated financial statements include the accounts and
operations of CRI, CRII, CGI and CCC (collectively the "Company"). All
significant intercompany accounts and transactions have been eliminated in the
consolidated financial statements.
Accounts Receivable
In June 1998, the Financial Accounting Standards Board ("FASB") issued
statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and for Hedging Activities", with an effective date for
periods beginning after June 15, 1999. In July 1999, the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133". As a result of SFAS No. 137,
adoption of SFAS No.133 was required for financial statements for periods
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities",
which amends the accounting and reporting standards of SFAS No. 133 for certain
derivative instruments and hedging activities. SFAS No. 133 sweeps in a broad
population of transactions and changes the previous accounting definition of a
derivative instrument. Under SFAS No. 133, every derivative instrument is
recorded on the balance sheet as either an asset or liability measured at its
fair value. SFAS No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. During 2000, management reviewed all contracts throughout the Company to
identify both freestanding and embedded derivatives which meet the criteria set
forth in SFAS No. 133 and SFAS No. 138. The Company adopted the new standards
effective January 1, 2001. On January 1, 2001, the Company had no outstanding
hedges or derivatives which had not been previously marked to market through its
accounting for trading activity. As a result, the adoption of SFAS No. 133 and
SFAS No. 138 had no significant impact on the Company's financial position or
results of operations.
In June 2001 the FASB issued SFAS No. 141, "Business Combinations," and No.
142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires all business
combinations initiated after June 30, 2001, to be accounted for using the
purchase method. With the adoption of SFAS No. 142, goodwill is no longer
subject to amortization but will be subject to at least an annual assessment for
impairment by applying a fair-value-based test. Under the new rules, an acquired
intangible asset should be separately recognized if the benefit of the
intangible asset is obtained through contractual or other legal rights, or if
the intangible asset can be sold, transferred, licensed, rented, or exchanged,
regardless of the acquirer's intent to do so. The Company's acquisition of the
assets of Farrar Oil Company in July 2001 is subject to these new standards. The
Company does not anticipate recognizing goodwill in connection with this
acquisition.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No.143 will affect the Company's accrued
abandonment costs for oil and gas properties and will require that the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. If a reasonable estimate of fair value cannot be made in the period the
asset retirement is incurred, the liability shall be recognized when a
reasonable estimate of fair value can be made. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Adoption of SFAS No. 143 is required for financial statements for periods
beginning after June 15, 2002. The Company will adopt this new standard
effective January 1, 2003. Management has not yet determined what the impact of
this new standard will be on its financial position or results of operation.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or 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 fair value
of the asset. 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.
Accounts Receivable
The Company operates exclusively in the oil and natural gas exploration and
production, gas gathering and processing and gas marketing industries. The
Company's joint interest receivables at December 31, 2000 and 2001, are recorded
net of an allowance for doubtful accounts of approximately $383,000 and
$359,000, respectively, in the accompanying consolidated balance sheets.
Inventories
Inventories consist primarily of tubular goods, production equipment and
crude oil in tanks, which are stated at the lower of average cost or market. At
December 31, 2000 and 2001, tubular goods and production equipment totaled
approximately $4,311,000 and $5,072,000, respectively and crude oil in tanks
totaled approximately $677,000 and $1,250,000, respectively.
Property and Equipment
The Company utilizes the successful efforts method of accounting for oil
and gas activities whereby costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. These costs are amortized
to operations on a unit-of-production method based on proved developed oil and
gas reserves, allocated property by property, as estimated by petroleum
engineers. Geological and geophysical costs, lease rentals and costs associated
with unsuccessful exploratory wells are expensed as incurred. Nonproducing
leaseholds are periodically assessed for impairment, based on exploration
results and planned drilling activity. Maintenance and repairs are expensed as
incurred, except that the cost of replacements or renewals that expand capacity
or improve production are capitalized. Gas gathering systems and gas processing
plants are depreciated using the straight-line method over an estimated useful
life of 14 years. Service properties and equipment and other is depreciated
using the straight-line method over estimated useful lives of 5 to 40 years.
Income Taxes
The Company filed a consolidated income tax return based on a May 31 fiscal
tax year end through May 31, 1997, and deferred income taxes were provided for
temporary differences between financial reporting and income tax bases of assets
and liabilities. Effective June 1, 1997, the Company converted to an
"S-Corporation" under Subchapter S of the Internal Revenue Code. As a result,
income taxes attributable to Federal taxable income of the Company after May 31,
1997, if any, will be payable by the stockholders of the Company.
Earnings per Common Share
Earnings per common share is computed by dividing income available to
common stockholders by the weighted-average number of shares outstanding for the
period. The weighted-average number of shares used to compute earnings per
common share was 14,368,919 in 1999, 2000 and 2001. The weighted-average number
of shares used to compute diluted EPS for 2001 and 2000 was 14,393,132. There
are no common stock equivalents or securities outstanding during 1999 which
would result in material dilution.
Derivatives
From time to time the Company and its subsidiaries utilize energy
derivative contracts to hedge the price or basis risk associated with the
specifically identified purchase or sales contracts, oil and gas production or
operational needs. Prior to January 1, 2001, the Company accounted for changes
in the market value of derivative instruments used for hedging as a deferred
gain or loss until the production month of the hedged transaction, at which time
the gain or loss on the derivative instruments was recognized in earnings.
Effective January 1, 2001, the Company accounts for derivative instruments in
accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities" which requires the Company to record all derivatives on the balance
sheet at fair value. Changes in the fair value of derivatives not designated as
hedges, as well as the ineffective portion of hedge derivatives, are recognized
as a derivative fair value gain or loss in the income statement. Changes in fair
value of effective cash flow hedges are recorded as a component of Accumulated
Other Comprehensive Income, which is reclassified to earnings when the hedged
transactions occur. Changes in fair value of effective fair value hedges are
recorded as adjustments to the carrying amount of the hedged item. At December
31, 2000 and 2001, the Company had no outstanding derivatives and no derivatives
were entered into during 2001. Net gains and losses on gas futures contracts are
included are included in gas gathering, marketing and processing revenues in the
accompanying consolidated statements of operations and were immaterial for the
years ended December 31, 1999, 2000 and 2001.
Additionally, in the normal course of business, the Company will enter into
fixed price forward sales contracts related on its oil and gas production to
reduce its sensitivity to oil and gas price volatility. Forward sales contracts
that will result in physical delivery of the Company's production are deemed to
be in the normal course of business and are not accounted for as derivatives.
Crude Oil Marketing
During 1998 CRI began trading crude oil, exclusive of its own production,
with third parties, under fixed and variable priced physical delivery contracts
extending out less than one year. CRI accounted for these contracts utilizing
the settlement method of accounting in the month of physical delivery through
December 31, 1998.
In December 1998 the Emerging Issues Task Force ("EITF") released their
consensus on EITF 98-10 "Accounting for Energy Trading and Risk Management
Activities." This statement requires that contracts for the purchase and sale of
energy commodities which are entered into for the purpose of speculating on
market movements or otherwise generating gains from market price differences to
be recorded at their market value, as of the balance sheet date, with any
corresponding gains or losses recorded as income from operations. The Company
adopted EITF 98-10 effective January 1, 1999. As a result, the Company recorded
an expense for the cumulative effect of change in accounting principle of
$2,048,000. At December 31, 2001, the market value of the Company's open energy
trading contracts resulted in an unrealized loss of $0.1 million which is
recorded in crude oil marketing revenues in the accompanying consolidated
statement of operations and accrued liabilities in the accompanying consolidated
balance sheet. During the fourth quarter of 2001, the Company discontinued crude
oil trading activities.
Forward Sales Contracts
During the third quarter of 2001, the Company entered into forward fixed
price sales contracts in accordance with its hedging policy, to mitigate its
exposure to the price volatility associated with its crude oil production. The
monthly contracts total 60,000 barrels through March 2003 at $21.98 per barrel.
At December 31, 2001, the Company had open fixed price sales contracts covering
approximately 900,000 barrels. As the contracts provide for physical delivery of
its production, the Company has deemed these contracts to be sales in the normal
course of business and it does not account for these contracts as derivatives.
Revenues from fixed price sales contracts in the normal course of business are
recognized as production occurs.
Gas Balancing Arrangements
The Company follows the "sales method" of accounting for its gas revenue
whereby the Company recognizes sales revenue on all gas sold to its purchasers,
regardless of whether the sales are proportionate to the Company's ownership in
the property. A liability is recognized only to the extent that the Company has
a net imbalance in excess of their share of the reserves in the underlying
properties. The Company's aggregate imbalance positions at December 31, 2000 and
2001, were not material.
Significant Customer
During 1999, 2000 and 2001, approximately 25.2%, 22.8% and 17.8%,
respectively, of the Company's total revenues were derived from sales made to a
single customer.
Fair Value of Financial Instruments
The Company's financial instruments consist primarily of cash, trade
receivables, trade payables and bank debt. The carrying value of cash, trade
receivables and trade payables are considered to be representative of their
respective fair values, due to the short maturity of these instruments. The fair
value of long-term debt less the senior subordinated notes discussed in Note 4,
approximates its carrying value based on the borrowing rates currently available
to the Company for bank loans with similar terms and maturities.
Business Segments
The Company operates in one business segment pursuant to Statement of
Financial Accounting Standards (SFAS) No. 131, "Disclosure About Segments of an
Enterprise and Related Information."
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Of the estimates and assumptions that affect reported results, the estimate of
the Company's oil and natural gas reserves, which is used to compute
depreciation, depletion, amortization and impairment on producing oil and gas
properties, is the most significant.
3. ACQUISITION OF PRODUCING PROPERTIES:
On December 31, 1999, the Company's principal stockholder contributed the
undivided 50% interest in the Worland properties to the Company along with an
outstanding debt balance of $18.6 million. The Company recorded the properties
at the stockholder's cost less amortization of such cost on a unit-of-production
method from the stockholder's acquisition date through December 31, 1999. The
contribution resulted in an addition to paid-in capital of $22.4 million.
On July 9, 2001, the Company's subsidiary, CRII, purchased the assets of
Farrar Oil Company, Inc. and Har-Ken Oil Company for $33.7 million using funds
borrowed under the Company's credit facility. This purchase was accounted for as
a purchase and the cost of the acquisition was allocated to the acquired assets
and liabilities. The allocation of the $33.7 million of purchase price on July
9, 2001, was as follows:
Current assets $ 950
Producing properties 30,603
Non-producing properties 1,117
Service properties 1,000
-------
$33,670
The unaudited pro forma information set forth below includes the operations
of Farrar Oil Company, Inc. assuming the acquisition of Farrar Oil Company, Inc.
and Har-Ken Oil Company by CRII occurred at the beginning of the periods
presented. The pro forma information for 1999 also includes the results of
operations as if the contribution from the principal stockholder had been
consummated as of January 1, 1999. The unaudited pro forma information is
presented for information only and is not necessarily indicative of the results
of operations that actually would have achieved had the acquisition been
consummated at that time:
Pro Forma (Unaudited)
---------------------
($ in thousands except per share data) 1999 2000 2001
- -------------------------------------- ---- ---- ----
Revenues $ 355,473 $ 455,190 $ 422,281
=========== =========== ===========
Net Income(Loss) $ 82 $ 37,406 $ 18,654
=========== =========== ===========
Earnings Per Common Share
Basic $ 0.01 $ 2.60 $ 1.30
=========== =========== ===========
Diluted $ 0.01 $ 2.59 $ 1.30
=========== =========== ===========
4. LONG-TERM DEBT:
Long-term debt as of December 31, 2000 and 2001, consists of the following
(in thousands):
2000 2001
---- ----
Senior Subordinated Notes (a) $ 130,150 $ 127,150
Line of credit agreement (b) 10,200 56,245
----------- ---------
Outstanding debt 140,350 183,395
Less- Current portion 10,200 5,400
----------- ---------
Total long-term debt $ 130,150 $ 177,995
=========== =========
<FN>
(a) On July 24, 1998, the Company consummated a private placement of $150.0
million of 10 1/4% Senior Subordinated Notes ("the Notes") due August 1,
2008, in a private placement under Securities Act Rule 144A. Interest on
the Notes is payable semi-annually on each February 1 and August 1. In
connection with the issuance of the Notes, the Company incurred debt
issuance costs of approximately $4.7 million, which has been capitalized as
other assets and is being amortized on a straight-line basis over the life
of the Notes. In May 1998 the Company entered into a forward interest rate
swap contract to hedge exposure to changes in prevailing interest rates on
the Notes. Due to changes in treasury note rates, the Company paid $3.9
million to settle the forward interest rate swap contract. This payment
results in an increase of approximately 0.5% to the Company's effective
interest rate or an increase of approximately $0.4 million per year over
the term of the Notes. Effective November 14, 1998, the Company registered
the Notes through a Form S-4 Registration Statement under the Securities
Exchange Act of 1933. During 2000, the Company repurchased $19.9 million
principal amount of its Notes at a cost of $18.3 million and During 2001,
the Company repurchased $3.0 million principal amount of its Notes at a
cost of $2.8 million.
(b) On April, 2000, the Company replaced its previous credit facility with a
$25.0 million line of credit facility under terms substantially similar to
the previous credit agreement. The agreement was amended August 1, 2000 to
add a correspondent bank and other minor changes were made. The Company has
collateralized the line of credit with substantially all of its oil and
natural gas interests, and gathering, marketing and processing properties.
This loan bears interest at either MidFirst prime or adjusted LIBOR, which
includes the LIBOR rate as determined on a daily basis by the bank adjusted
for a facility fee percentage and non-use fee percentage. The LIBOR rate
can be locked in for thirty, sixty, or ninety days as determined by the
Company through the use of various principal tranches; or the Company can
elect to leave the interest rate based on the prime interest rate. The
MidFirst prime interest rate at December 31, 2001, was 4.75%. Interest is
payable monthly with all outstanding principal and interest due at maturity
on May 31, 2003. The Company has $56.2 million outstanding debt on its line
of credit at December 31, 2001. The credit agreement was renegotiated and
the line was increased to $70 million on January 17, 2002.
</FN>
The Company's line of credit agreement contains certain negative financial
and certain information reporting covenants. The Company was not in compliance
with two negative covenants at December 31, 2001. One of the covenants required
lender approval prior to entering into hedging contracts in excess of 12 months.
The other covenant requires the Company to maintain a minimum current ratio of
1.0:1.0, however, the current ratio at December 31, 2001, was 0.91:1.0. The
Company received waivers from the bank on both of these violations and expects
to be in compliance through the loan maturity date.
The annual maturities of long-term debt subsequent to December 31, 2001,
are as follows (in thousands):
2002 $ 5,400
2003 37,345
2004 5,400
2005 5,400
2006 and thereafter 129,850
------------
Total maturities $ 183,395
============
At December 31, 2001, the Company had $0.4 million of outstanding letters
of credit which expire during 2002.
The estimated fair value of long term debt is approximately $164,323.000
and $140,350,000 at December 31, 2001 and 2000, respectively. The fair value of
long term debt is estimated based on quoted market prices and managements
estimate of current rates available for similar issues.
5. INCOME TAXES:
The Company follows Statement of Financial Accounting Standards ("SFAS")
No. 109, "Accounting for Income Taxes." As mentioned in Note 2, the Company is
an S-Corporation resulting in the taxable income or loss of the Company being
reported to the stockholders and included in their respective Federal and state
income tax returns. The difference in the taxable income of the stockholders
versus the net income of the Company is due primarily to intangible drilling
costs which are capitalized for book purposes but charged to expense for tax
purposes and accelerated depreciation and depletion methods utilized for tax
purposes.
6. STOCKHOLDER'S EQUITY
On October 1, 2000, the Company's Board of Directors and shareholders
approved an Agreement and Plan of Recapitalization (the "Recapitalization Plan")
and the Amended and Restated Certificate of Incorporation to be filed with the
Oklahoma Secretary of State. As outlined in the Recapitalization Plan, the
authorized number of shares of capital stock were increased from 75,000 shares
of common stock to 21 million shares consisting of 20 million shares of common
stock and one million shares of $0.01 par value Preferred Stock. In addition,
the par value of common stock was adjusted from $1 per share to $0.01 per share
and 1.02 million shares of the common stock were reserved for issuance under the
2000 incentive Stock Plan discussed in Note 7.
Concurrent with the approval of the Recapitalization Plan, the Company
effected an approximate 293:1 stock split whereby the Company issued new
certificates for 14,368,919 shares of the newly authorized common stock in
exchange for the 49,041 previously outstanding shares of common stock. As a
result of the stock split, additional paid-in capital was reduced by
approximately $95,000, offset by an increase in the common stock at par.
7. STOCK OPTIONS
The Company has a stock option plan, the Continental Resources, Inc. 2000
Stock Option Plan (the "Plan"), which became effective October 1, 2000.
Under the Company's Plan, a committee may, from time to time, grant options
to directors and eligible employees. These options may be Incentive Stock
Options or Nonqualified Stock Options, or a combination of both. The earliest
the granted options may be exercised is over a five year vesting period at the
rate of 20% each year for the Incentive Stock Options and over a three year
period at the rate of 33-1/3% for the Nonqualified Stock Options, both
commencing on the first anniversary of the grant date. The maximum shares
covered by options shall consist of 1,020,000 shares of the Company's common
stock, par value $.01 per share. The Company granted 144,000 shares during 2000.
No options were granted in 2001.
Stock options outstanding under the Plan are presented for the periods
indicated.
Number of Shares Option Price Range
---------------- ------------------
Outstanding December 31, 1999 -- --
Granted 144,000 $7.00 - $14.00
Exercised -- --
Canceled -- --
Outstanding December 31, 2000 144,000 $7.00 - $14.00
Granted -- --
Exercised -- --
Canceled -- --
Outstanding December 31, 2001 144,000 $7.00 - $14.00
The Company applies APB Option No. 25 ("APB25") in accounting for its fixed
price stock options. Under APB 25, no compensation costs are recognized relating
to stock options issued under a fixed plan with a strike price at or above the
fair market value of the underlying shares of common stock at the date of grant.
For stock options issued with a strike price below the fair market value of the
underlying shares of common stock, compensation costs is recognized over the
vesting period equal to the fair market value of the common stock at the date of
grant less the strike price. Under APB 25, any compensation expense will be
recognized in the income statement with a corresponding increase in additional
paid-in capital. During 2000 and 2001, compensation expense related to in the
money options was immaterial.
The SFAS No. 123, "Accounting for Stock-Based Compensation", method of
accounting is based on several assumptions and should not be viewed as
indicative of the operations of the Company in future periods. The fair value of
each option grant is estimated on the date of grant using the Black-Scholes
option pricing model with the following weighted-average assumptions used for
grants in 2000.
(Amounts expressed in percentages) 2000
- ---------------------------------- ----
Interest Rate 5.88%
Dividend Yield 0%
Expected Volatility 0%
Expected Life (years) 6.25
The weighted average fair value of options granted using the Black-Scholes
option pricing model for 2000 was $4.90.
The chart below sets forth the Company's net income and earnings per share
as reported and on a pro forma basis as if the compensation cost of stock
options had been determined consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation."
(In thousands except per share amounts) 2000 2001
- --------------------------------------- ---- ----
Net Income:
As Reported $ 37,780 $ 11,667
Pro Forma $ 37,765 $ 11,575
Basic Earnings Per Share:
As Reported $ 2.63 $ 0.81
Pro Forma $ 2.63 $ 0.81
Diluted Earnings Per Share:
As Reported $ 2.62 $ 0.81
Pro Forma $ 2.62 $ 0.81
8. COMMITMENTS AND CONTINGENCIES:
The Company maintains a defined contribution pension plan for its employees
under which it makes discretionary contributions to the plan based on a
percentage of eligible employees compensation. During 1999, 2000 and 2001,
contributions to the plan were 5% of eligible employees' compensation. However,
the Company suspended its 5% contribution from January 1, 1999, to April 1,
1999, due to low commodity prices. Pension expense for the years ended December
31, 1999, 2000 and 2001, was approximately $252,000, $390,000 and $392,000,
respectively.
The Company and other affiliated companies participate jointly in a
self-insurance pool (the "Pool") covering health and workers' compensation
claims made by employees up to the first $50,000 and $500,000, respectively, per
claim. Any amounts paid above these are reinsured through third-party providers.
Premiums charged to the Company are based on estimated costs per employee of the
Pool. No additional premium assessments are anticipated for periods prior to
December 31, 2001. Property and general liability insurance is maintained
through third-party providers with a $50,000 deductible on each policy.
The Company is involved in various legal proceedings in the normal course
of business, none of which, in the opinion of management, will have a material
adverse effect on the financial position or results of operations of the
Company.
On May 15, 1998, the Company and Burlington Resources Oil & Gas Company,
Inc. ("Burlington") entered into an agreement ("Trade Agreement") to exchange
undivided interests in approximately 65,000 gross (59,000 net) leasehold acres
in the northern half of the Cedar Hills Field in North Dakota. On August 19,
1998, the Company instituted a declaratory judgment action against Burlington in
the District Court of Garfield County, Oklahoma. The Company sought a
declaratory judgment determining that it was excused from further performance
under the Trade Agreement. On December 22, 1999, the Court issued an Order
requiring the parties to proceed in accordance with terms of the Trade Agreement
and instructing them to use their best efforts to consummate the Trade
Agreement. Continental complied with the Order of the Court and attempted to
proceed with the terms of the Trade Agreement. However, substantial title
defects arose with respect to the interests to be received by Continental from
Burlington under the terms of the Trade Agreement. As a result of the title
defects which could result in the cancellation of Burlington's leases,
Continental filed a Motion to Dismiss seeking a determination by the Court that
Continental was excused from performance under the Trade Agreement. A hearing
was held the week of June 19, 2000. On October 11, 2000, the Court issued its
Findings of Fact, Conclusions of Law and Order holding that the Company was
excused from further performance under the Trade Agreement. The Court also
dismissed Burlington's claim for damages against the Company. On December 13,
2000, the Court entered a Final Order granting the Company's Motion to Dismiss
and denying Burlington's claim for damages. Burlington timely appealed the Final
Order entered by the Court. On January 22, 2001, the Company and Burlington
entered into a settlement agreement of the litigation involving the Cedar Hills
Field. As a result of the settlement, pleadings were filed with the Court which
resulted in the dismissal with prejudice of all claims between the Company and
Burlington.
Due to the nature of the oil and gas business, the Company is exposed to
possible environmental risks. The Company has implemented various policies and
procedures to avoid environmental contamination and risks from environmental
contamination. The Company is not aware of any material potential environmental
issues or claims.
9. RELATED PARTY TRANSACTIONS:
The Company, acting as operator on certain properties, utilizes affiliated
companies to provide oilfield services such as drilling and trucking. The total
amount paid to these companies, a portion of which is billed to other interest
owners, was approximately $7,418,000, $8,713,000 and $10,942,000 during the
years ended December 31, 1999, 2000 and 2001, respectively. These services are
provided at amounts which management believes approximate the costs which would
have been paid to an unrelated party for the same services. At December 31, 2000
and 2001, the Company owed approximately $502,000 and $266,000, respectively, to
these companies which is included in accounts payable and accrued liabilities in
the accompanying consolidated balance sheets. These companies and other
companies owned by the Company's principal stockholder also own interests in
wells operated by the Company and provide oilfield related services for the
Company. At December 31, 2000 and 2001, approximately $131,000 and $344,000,
respectively, from affiliated companies is included in accounts receivable in
the accompanying consolidated balance sheets.
The Company leases office space under operating leases directly or
indirectly from the principal stockholder. Rents paid associated with these
leases totaled approximately $369,000, $313,000 and $334,000 for the years ended
December 31, 1999, 2000 and 2001, respectively.
Effective June 1, 1998, The Company sold an undivided 50% interest in the
70,000 net leasehold acres it acquired in the Worland Field Acquisition to its
principal stockholder. The Worland Field sale did not include inventory and
certain items of equipment which the Company had acquired in the Worland Field
Acquisition. The $42.6 million purchase price paid by the principal stockholder
equals the Company's cost basis in such leasehold acres. In December 1999 the
principal stockholder contributed his interests in the purchased properties
along with debt of $18,600,000. The properties were recorded at the
stockholder's cost less amortization of such cost on a unit-of-production method
from the stockholder's acquisition date through the date contributed to the
Company. The contribution was recorded as an addition to paid-in capital.
During 2001, the Company, acting as operator on certain properties located
in Wyoming, began selling natural gas produced from the Worland Field to a
related party. During 2001, the Company sold $1.77 million of natural gas to
this related party.
10. IMPAIRMENT OF LONG-LIVED ASSETS:
The Company accounts for impairment of long-lived assets in accordance with
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of." During 1999, 2000 and 2001, the Company
reviewed its oil and gas properties which are maintained under the successful
efforts method of accounting, to identify properties with excess of net book
value over projected future net revenue of such properties. Any such excess net
book values identified were evaluated further considering such factors as future
price escalation, probability of additional oil and gas reserves and a discount
to present value. If an impairment was deemed appropriate, an additional charge
was added to depreciation, depletion and amortization ("DD&A") expense. The
Company recognized no additional DD&A impairment in 1999, $1,665,000 was
recognized additional DD&A impairment in 2000, and $5,303,000 was recognized
additional DD&A impairment in 2001.
11. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, Continental Gas, Inc. (CGI),
Continental Resources of Illinois, Inc. (CRII), and Continental Crude Col. (CCC)
have guaranteed the Company's outstanding Senior Subordinated Notes and its bank
credit facility. The following is a summary of the condensed consolidating
financial information of CGI and CRII as of December 31, 1999, 2000 and 2001:
Condensed Consolidating Balance Sheet
as of December 31, 1999
($ in thousands)
Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Current Assets $ 3,392 $ 44,001 $ (11,145) $ 36,248
Noncurrent Assets 21,643 224,678 (11) 246,310
--------- --------- --------- ---------
Total Assets $ 25,035 $ 268,679 $ (11,156) $ 282,558
========= ========= ========= =========
Current Liabilities $ 3,688 $ 23,402 $ (1,645) $ 25,445
Noncurrent Liabilities 9,500 170,447 (9,500) 170,447
Stockholder's Equity 11,847 74,830 (11) 86,666
--------- --------- --------- ---------
Total Liabilities and
Stockholder's Equity $ 25,035 $ 268,679 $ (11,156) $ 282,558
========= ========= ========= =========
Condensed Consolidating Statements of Operations
as of December 31, 1999
($ in thousands)
Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenues $ 25,037 $ 313,448 $ (3,024) $ 335,461
Operating Expenses 24,185 294,424 (3,024) 315,585
Other Income(Expense) (758) (15,197) -- (15,955)
--------- --------- --------- ---------
Net Income $ 94 $ 3,827 $ -- $ 3,921
========= ========= ========= =========
Condensed Consolidating Balance Sheet
as of December 31, 2000
($ in thousands)
Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Current Assets $ 5,836 $ 38,118 $ (5,989) $ 37,965
Noncurrent Assets 19,467 241,202 (11) 260,658
--------- --------- --------- ---------
Total Assets $ 25,303 $ 279,320 $ (6,000) $ 298,623
========= ========= ========= =========
Current Liabilities $ 5,133 $ 39,936 $ (149) $ 44,920
Noncurrent Liabilities 5,840 130,257 (5,840) 130,257
Stockholder's Equity 14,330 109,127 (11) 123,446
--------- --------- --------- ---------
Total Liabilities and
Stockholder's Equity $ 25,303 $ 279,320 $ (6,000) $ 298,623
========= ========= ========= =========
Condensed Consolidating Statements of Operations
as of December 31, 2000
($ in thousands)
Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenues $ 36,928 $ 402,021 $ (3,223) $ 435,726
Operating Expenses 34,439 356,199 (3,223) 387,415
Other Income(Expense) (6) (10,525) -- (10,531)
--------- --------- --------- ---------
Net Income $ 2,483 $ 35,297 $ -- $ 37,780
========= ========= ========= =========
Condensed Consolidating Balance Sheet
as of December 31, 2001
($ in thousands)
Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Current Assets $ 6,310 $ 51,915 $ (25,935) $ 32,290
Noncurrent Assets 42,063 280,143 (11) 322,195
--------- --------- --------- ---------
Total Assets $ 48,373 $ 332,058 $ (25,946) $ 354,485
========= ========= ========= =========
Current Liabilities $ 11,039 $ 38,629 $ (8,382) $ 41,286
Noncurrent Liabilities 17,553 178,086 (17,553) 178,086
Stockholder's Equity 19,781 115,343 (11) 135,113
--------- --------- --------- ---------
Total Liabilities and
Stockholder's Equity $ 48,373 $ 332,058 $ (25,946) $ 354,485
========= ========= ========= =========
Condensed Consolidating Statements of Operations
as of December 31, 2001
($ in thousands)
Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenues $ 52,051 $ 359,274 $ (563) $ 410,762
Operating Expenses 46,695 356,512 (563) 402,644
Other Income(Expense) 95 3,454 -- 3,549
--------- --------- --------- ---------
Net Income $ 5,451 $ 6,216 $ -- $ 11,667
========= ========= ========= =========
At December 31, 2000 and 2001, current liabilities payable from the
subsidiaries to CRI totaled approximately $5,839,000 and $8,181,000,
respectively. For the years ended December 31, 1999, 2000 and 2001,
depreciation, depletion and amortization, included in operating costs, totaled
approximately $2,063,000, $2,107,000 and $4,938,000, respectively.
Since its incorporation, CCC has had no operations, has acquired no assets
and has incurred no liabilities.
12. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
Proved Oil and Gas Reserves
The following reserve information was developed from reserve reports as of
December 31, 1998, 1999, 2000 and 2001, prepared by independent reserve
engineers and by the Company's internal reserve engineers and set forth the
changes in estimated quantities of proved oil and gas reserves of the Company
during each of the three years presented.
Crude Oil and
Natural Gas Condensate
(MMcf) (MBbls)
------ -------
Proved reserves as of December 31, 1998 55,219 19,930
Revisions of previous estimates 14,602 12,462
Extensions, discoveries and other additions 2,174 326
Production (6,640) (3,221)
Sale of minerals in place (97) (3)
Purchase of minerals in place 10,503 7,130
------ -----
Proved reserves as of December 31, 1999 75,761 36,624
Revisions of previous estimates (9,547) 1,680
Extensions, discoveries and other additions 4,054 324
Production (7,939) (3,360)
Sale of minerals in place (2,456) (4)
Purchase of minerals in place 0 0
------ -----
Proved reserves as of December 31, 2000 59,873 35,264
Revisions of previous estimates (11,331) 24,581
Extensions, discoveries and other additions 8,884 317
Production (8,411) (3,489)
Sale of minerals in place (2,457) (274)
Purchase of minerals in place 5,709 3,332
------ -----
Proved reserves as of December 31, 2001 52,267 59,731
====== ======
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves. Oil and gas reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
precisely measured, and estimates of engineers other than the Company's might
differ materially from the estimates set forth herein. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results of drilling,
testing and production subsequent to the date of the estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
Gas imbalance receivables and liabilities for each of the three years ended
December 31, 1999, 2000 and 2001, were not material and have not been included
in the reserve estimates.
Proved Developed Oil and Gas Reserves
The following reserve information was developed by the Company and set
forth the estimated quantities of proved developed oil and gas reserves of the
Company as of the beginning of each year.
Crude Oil and
Natural Gas Condensate
Proved Developed Reserves (MMcf) (MBbls)
------------------------- ------ -------
January 1, 1999 54,901 19,095
January 1, 2000 65,723 34,432
January 1, 2001 58,438 33,173
January 1, 2002 56,647 31,325
Proved developed reserves are proved reserves which are expected to be
recovered through existing wells with existing equipment and operating methods.
Costs Incurred in Oil and Gas Activities
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities during the year are shown below (in
thousands of dollars). Amounts are presented in accordance with SFAS No. 19, and
may not agree with amounts determined using traditional industry definitions.
1999 2000 2001
---- ---- ----
Property acquisition costs:
Proved Purchased $19,745 $ -- $42,526
Proved Contributed 22,461 -- --
Unproved 1,274 5 231 11,386
------- ------- -------
Total property acquisition costs $43,480 $ 5,231 $53,912
Exploration costs 379 6,152 9,170
Development costs 10,945 36,756 35,456
------- ------- -------
Total $54,804 $48,139 $98,538
======= ======= =======
Aggregate Capitalized Costs
Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A, as of December 31 (in thousands of
dollars):
2000 2001
---- ----
Proved oil and gas properties $351,391 $425,754
Unproved oil and gas properties 14,350 20,694
-------- --------
Total 365,741 446,448
Less- Accumulated DD&A 136,115 155,703
-------- --------
Net capitalized costs $229,625 $290,745
======== ========
Oil and Gas Operations (Unaudited)
Aggregate results of operations for each period ended December 31, in
connection with the Company's oil and gas producing activities are shown below
(in thousands of dollars):
1999 2000 2001
---- ---- ----
Revenues $ 65,949 $115,478 $112,171
Production costs 19,368 29,807 36,791
Exploration expenses 7,750 13,321 19,927
DD&A and valuation provision(1) 16,778 17,454 29,003
-------- -------- --------
Income (loss) 22,053 54,896 26,450
Income tax expense(2) -- -- --
-------- -------- --------
Results of operations from producing activities
(excluding corporate overhead and interest costs) $ 22,053 $ 54,896 $ 26,450
======== ======== ========
<FN>
(1) Includes $1.6 million in 2000 and $5.3 million in 2001 of additional DD&A
as a result of SFAS No. 121 impairments.
(2) The Company is an S-Corporation, as a result the income or loss of the
Company is taxable at the stockholder level.
</FN>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 1999, 2000 and 2001, as required by SFAS No. 69. The Standard
requires the use of a 10% discount rate. This information is not the fair market
value nor does it represent the expected present value of future cash flows of
the Company's proved oil and gas reserves (in thousands of dollars).
1999 2000 2001
---- ---- ----
Future cash inflows $ 1,069,436 $ 1,403,645 $ 1,300,078
Future production and development costs (422,558) (495,953) (667,533)
Future income tax expenses -- -- --
----------- ----------- -----------
Future net cash flows 646,878 907,692 632,545
10% annual discount for estimated timing of cash flows (312,467) (415,893) (323,941)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 334,411 $ 491,799 $ 308,604
========== =========== ===========
Future cash inflows are computed by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves. The year-end weighted average oil price utilized in the computation of
future cash inflows was approximately $24.38, $26.80, and $18.67 per BBL at
December 31, 1999, 2000 and 2001, respectively. The year-end weighted average
gas price utilized in the computation of future cash inflows was approximately
$1.76, $9.78, and $1.96 per MCF at December 31, 1999, 2000 and 2001,
respectively.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.
Income taxes were not computed at December 31, 1999, 2000 or 2001, as the
Company elected S-Corporation status effective June 1, 1997.
Principal changes in the aggregate standardized measure of discounted
future net cash flows attributable to the Company's proved oil and gas reserves
at year-end are shown below (in thousands of dollars):
1999 2000 2001
---- ---- ----
Standardized measure of discounted future net cash
flows at the beginning of the year $ 107,670 $ 334,411 $ 491,799
Extensions, discoveries and improved recovery, less
related costs 5,370 24,923 26,267
Revisions of previous quantity estimates 128,280 910 134,197
Changes in estimated future development costs (25,914) 853 (107,009)
Purchases(sales) of minerals in place 49,984 (1,387) 10,755
Net changes in prices and production costs 135,803 149,123 (211,057)
Accretion of discount 10,767 33,441 49,180
Sales of oil and gas produced, net of production costs (46,581) (85,671) (75,379)
Development costs incurred during the period 1,246 19,196 12,260
Change in timing of estimated future production, and
other (32,214) 16,000 (22,409)
--------- --------- ---------
Standardized measure of discounted future net cash
flows at the end of the year $ 334,411 $ 491,799 $ 308,604
========= ========= =========
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
- ------- ----------- ----------------
2.1 Agreement and Plan of Incorporated herein by reference
Recapitalization of Continental
Resources, Inc. dated October 1,
2000.
3.1 Amended and Restated Certificate of Incorporated herein by reference
Incorporation of Continental
Resources, Inc.
3.2 Amended and Restate Bylaws of Incorporated herein by reference
Continental Resources, Inc.
3.3 Certificate of Incorporation of Incorporated herein by reference
Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference
amended and restated.
3.5 Certificate of Incorporation of Incorporated herein by reference
Continental Crude Co.
3.6 Bylaws of Continental Crude Co. Incorporated herein by reference
4.1 Restated Credit Agreement dated Incorporated herein by reference
April 21, 2000 among Continental
Resources, Inc. and Continental Gas,
Inc., as Borrowers and MidFirst Bank
as Agent (the "Credit Agreement")
4.1.1 Form of Consolidated Revolving Note Incorporated herein by reference
under the Credit Agreement
4.1.2 Second Amended and Restated Credit Incorporated herein by reference
Agreement among Continental
Resources, Inc., Continental Gas,
Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and
MidFirst Bank, dated July 9,
2001
4.1.3 Third Amended and Restated Credit Filed herewith electronically
Agreement among Continental
Resources, Inc., Continental Gas,
Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and
MidFirst Bank, dated January 17,
2002.
4.3 Indenture dated as of July 24, 1998 Incorporated herein by reference
between Continental Resources, Inc.,
as Issuer, the Subsidiary Guarantors
named therein and the United States
Trust Company of New York, as
Trustee
10.4 Conveyance Agreement of Worland Area Incorporated herein by reference
Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm
Revocable Intervivos Trust dated
April 23, 1984 to Continental
Resources, Inc.
10.5 Purchase Agreement signed January Incorporated herein by reference
2000, effective October 1, 1999, by
and between Patrick Energy
Corporation as Buyer and Continental
Resources, Inc. as Seller
10.6 Continental Resources, Inc. 2000 Incorporated herein by reference
Stock Option Plan. [10.6](4)
10.7 Form of Incentive Stock Option Incorporated herein by reference
Agreement
10.8 Form of Non-Qualified Stock Option Incorporated herein by reference
Agreement
10.9 Purchase and Sales Agreement between Incorporated herein by reference
Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental
Resources of Illinois, Inc. as
Purchaser, dated May 14,
2001
12.1 Statement re computation of ratio of Filed herewith electronically
debt to Adjusted EBITDA
12.2 Statement re computation of ratio of Filed herewith electronically
earning to fixed charges
12.3 Statement re computation of ratio of Filed herewith electronically
Adjusted EBITDA to interest expense
21.0 Subsidiaries of Registrant Incorporated herein by reference
99.1 Letter to the Securities and Filed herewith electronically
Exchange Commission dated March 28,
2002, regarding the audit of the
Registrant's financial statements by
Arthur Andersen LLP.