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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, 2000
[ ]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
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 practible date:
As of March 28, 2001, 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, 2000
TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
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 2001 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") 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 750 miles of natural gas pipelines, five 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 45.2 MMBoe at year-end 2000, and
has increased its annual production from 2.2 MMBoe in 1995 to 4.7 MMBoe in 2000.
As of December 31, 2000, the Company's reserves had a present value of estimated
future net cash flows, discounted at 10% ("PV-10") of $491.8 million calculated
in accordance with the Securities and Exchange Commission (the "Commission" or
"SEC") guidelines. Approximately 78% of the Company's estimated proved reserves
were oil and approximately 95% of its total estimated reserves were classified
as proved developed. At December 31, 2000, the Company had interests in 1,291
producing wells of which it operated 972. The Company was originally formed in
1967 to explore, develop and produce oil and gas properties 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, 78% of the
Company's estimated proved reserves as of December 31, 2000, 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 its rapid growth in the Rocky Mountain region,
but its activity in the Gulf Coast region significantly increased during 1999
and 2000. Management expects that the Gulf Coast region will develop into
another key operating area for the Company.
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 the Big Horn Basin in Wyoming. These properties represented
78% of the Company's estimated proved reserves and 51% of the PV-10 of the
Company's proved reserves as of December 31, 2000. The Company owns
approximately 331,000 net leasehold acres, has interest in 566 gross (461 net)
producing wells and is the operator of 95% of these wells, and has identified
187 potential drilling locations in the Rocky Mountain region. The Company's
principal properties in the Williston Basin include the Cedar Hills Field and
five secondary recovery projects located in the Medicine Pole Hills and Buffalo
Fields. The Company's five secondary recovery projects represent one-half of the
high pressure air injection projects in North America. The Company's Williston
Basin properties represented 51% of its estimated proved reserves and 37% of the
Company's PV-10 of its proved reserves at December 31, 2000. In the Williston
Basin, the Company owns approximately 259,000 net leasehold acres; has interest
in 322 gross (264 net) producing wells and has identified 30 potential drilling
locations. The Company expects to add significant reserves in the Williston
Basin in the upcoming years as it commences secondary recovery operations in the
Cedar Hills Field. Secondary recovery methods increase the reserves recovered
from existing fields through the injection and withdrawal of fluids. The
combination of injection and withdrawal recovers additional oil from the
reservoir that cannot be recovered by primary recovery methods. The Company's
estimated proved reserves, estimated future net revenues and PV-10 at December
31, 2000, did not include any reserves expected to be recovered through
secondary recovery operations but the Company believes that up to three barrels
of oil may be recovered by secondary recovery methods for each barrel of oil
produced by primary recovery. Accordingly, the Company believes that secondary
recovery operations could recover an aggregate of an additional 60 million
barrels of oil from the Cedar Hills Field. Secondary recovery operations are
scheduled to begin in 2001. The Cedar Hills Field represented approximately 29%
of the proved reserves and 22% of the PV-10 attributable to the Company's proved
reserves at December 31, 2000. In 1998 the Company expanded its activities into
the Big Horn Basin through the acquisition of producing and non-producing
properties in the Worland Field. The Worland Field represents 27% of the
Company's estimated proved reserves and 14% of the PV-10 of the Company's proved
reserves at December 31, 2000. In the Worland Field, the Company owns
approximately 73,000 net leasehold acres; has interests in 256 gross (228 net)
producing wells, of which 244 are operated by the Company. In the Worland Field
the Company has identified 157 potential drilling locations, 101 potential
workovers or recompletions and has initiated one 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 and in
the Texas Panhandle. At December 31, 2000, the Company's estimated proved
reserves in the Mid-Continent region represented 20% of the Company's total
estimated proved reserves, 68% of the Company's natural gas reserves and 42% of
the Company's PV-10. In the Mid-Continent region, the Company owns approximately
87,000 net leasehold acres, has interest in 693 gross (301 net) producing wells
and has identified 15 potential drilling locations. The Company operates 60% 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. This includes the
Pebble Beach and Luby projects in Nueces County, Texas and the Jefferson Island
project in Iberia Parish, Louisiana. During 2000, the Company acquired and
drilled offshore leasehold in the Gulf of Mexico as part of the Company's
ongoing expansion in the Gulf Coast region. The Company's Gulf Coast properties
represented 2% of the Company's total estimated proved reserves, 9% of its
estimated proved gas reserves and 7% PV- 10 of the Company's proved reserves at
December 31, 2000. In the Gulf Coast, the Company owns approximately 17,000 net
leasehold acres; has interests in 20 gross (14 net) producing wells and has
identified 12 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 90% 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. 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 and Buffalo, South Dakota and field offices
located within its various operating areas.
BUSINESS STRENGTHS
The Company believes that it has certain strengths that provide it with
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 from 26.6 MMBoe
in 1995 to 45.2 MMBoe as of December 31, 2000.
SUBSTANTIAL DRILLING INVENTORY. The Company has identified more than 214
potential drilling locations based on geological and geophysical evaluations. As
of December 31, 2000, the Company held approximately 435,000 net acres, of which
approximately 50% 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 low rate, 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 9.7
years.
SUCCESSFUL DRILLING AND ACQUISITION RECORD. The Company has maintained a
successful drilling record. During the five years ended December 31, 2000, the
Company participated in 258 gross (165 net) wells of which 93% were successfully
completed resulting in the addition of 25.3 MMBoe of proved developed reserves
at an average finding cost of $7.50 per barrel of oil equivalent ("Boe")
excluding the potential secondary recovery in the Williston Basin. During the
same five-year period, the Company acquired 17.2 MMBoe at an average cost of
$3.39 per Boe. Including major revisions of 14.3 MMBoe due primarily to
fluctuating prices and additional volumes of up to 100,000 Bbls per well added
to primary production in the Cedar Hills Field by Ryder Scott engineers, the
Company added a total of 42.5 MMBoe at an average cost of $5.84 per Boe during
the last five years.
SIGNIFICANT OPERATIONAL CONTROL. Approximately 91.6% of the Company's PV-10
at December 31, 2000, 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 ("HPAI")
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 190 horizontal wells
in the Rocky Mountains and Mid-Continent. 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 22 years of oil and gas industry
experience. Additionally, the Company's technical staff, which includes eight
petroleum engineers and eight geoscientists, have an average of more than 22
years experience in the industry.
DEVELOPMENT, EXPLOITATION AND EXPLORATION ACTIVITIES
CAPITAL EXPENDITURES. The Company's projected capital expenditures for
development, exploitation and exploration activities in 2001 total $70.7
million. Approximately $31.1 million (44%) is targeted for drilling, $5.0
million (7%) for land and seismic, $4.8 million (7%) for workovers and
recompletions and $29.8 million (42%) for secondary recovery related activities.
Drilling expenditures for 2001 include a projected $17.6 million in development
drilling and $13.5 million in exploratory drilling.
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 2001, the Company projects that development
drilling will represent 56% of its drilling budget. Development drilling will be
conducted in all three regions with a projected 12% in the Mid-Continent region,
22% in the Gulf Coast region and 66% in the Rocky Mountain region. The Company
will continue to seek opportunities to increase production from its inventory of
109 workovers and recompletions in the Rocky Mountain region as well as the 41
in the Mid-Continent and Gulf Coast regions. Several secondary recovery projects
will also be initiated during 2001, including three in the Mid-Continent region,
and five in the Rocky Mountain region. During 2001, the Company will commence
secondary recovery operations in the Cedar Hills Field and the Medicine Pole
Hills West Field. The Cedar Hills Field was unitized March 1, 2001, which will
allow secondary recovery operations to begin in the second quarter of 2001. The
unitization process for the Medicine Pole Hills West Field has been completed
and the installation of HPAI facilities and initial injection was started
November 22, 2000. The following table sets forth the Company's development
inventory as of December 31, 2000.
NUMBER OF DEVELOPMENT PROJECTS
ENHANCED/SECONDARY
DRILLING WORKOVERS AND RECOVERY
LOCATIONS RECOMPLETIONS PROJECTS TOTAL
--------- ------------- -------- -----
ROCKY MOUNTAIN:
Williston Basin........................................ 30 8 4 42
Big Horn Basin......................................... 157 101 1 259
--- --- -- ---
Total ROCKY MOUNTAIN.................................... 187 109 5 301
MID-CONTINENT:
Anadarko Basin......................................... 15 26 3 44
GULF COAST.................................................. 12 15 - 27
--- --- -- ---
TOTAL....................................................... 214 150 8 372
=== === == ===
The Company will initiate, on a priority basis, as many projects as cash
flow and rig availability allow. Based on forecasted cash flow, the Company
anticipates initiating 34 development drilling projects, 62 workover projects
and five secondary recovery projects during 2001. The Company expects to expend
approximately $17.6 million drilling, $4.8 million on workovers and
recompletions and $29.8 million on secondary recovery related to these projects
in 2001.
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, 2000:
NUMBER OF EXPLORATION PROJECTS
DRILLING LOCATION 3-D SEISMIC
ROCKY MOUNTAIN:
Williston Basin............................................................ 4 3
Big Horn Basin............................................................. 2 1
-- --
Total ROCKY MOUNTAIN........................................................ 6 4
MID-CONTINENT................................................................... 21 -
GULF COAST...................................................................... 30 1
-- --
TOTAL........................................................................... 57 5
== ==
The Company will initiate, on a priority basis, as many projects as cash
flow and rig availability allow. The Company anticipates initiating 30
exploratory drilling projects during 2001 and projects the drilling investment
in these exploratory projects will represent approximately 43% of its drilling
budget for 2001 with 10% in the Mid-Continent, 17% in the Rocky Mountain region
and 73% in the Gulf Coast region.
ACQUISITION ACTIVITIES
The Company seeks to acquire properties, which have the potential to be
immediately accretive 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 hedging arrangements
from time to time to reduce its exposure to price risks in the sale of its oil
and gas, the Company's hedging 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 the 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, 2000, the estimated future net cash
flows of $907.7 million and PV-10 of $491.8 million attributable to the
Company's proved oil and gas reserves are based on prices in effect at that date
($26.80 per barrel ("Bbl") of oil and $9.78 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, 2000, on a consolidated basis, the Company and the
Subsidiary Guarantors had $140.4 million of indebtedness (including short term
debt and current maturities of long-term indebtedness) compared to the Company's
stockholders' equity of $123.4 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
Consolidated Financial Data," "Capitalization" 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
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" and "Description of Credit Facility."
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
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.
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 Guarantor 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, 2001, was $12.7 million
exclusive of $12.3 million of unused commitments under the Credit Facility. The
Subsidiary Guarantees are subordinated to Guarantor 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 such 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 Assets." 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 (as defined herein) 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. If the Company enters into 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 derivative instruments will be reported as other comprehensive income and
reclassified to earnings in the same period as the hedged production takes
place. 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 $1.0
million for the year ended December 31, 2000. The Company's current policy is to
limit its exposure from open positions to $1.0 million at any one time. At
December 31, 2000, the Company's exposure from open positions on forward crude
oil contracts was not material.
WRITE DOWN OF CARRYING VALUES
The Company periodically reviews the carrying value of its oil and gas
properties in accordance with Statement of Financial Accounting Standards No.
121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of" ("SFAS No. 121"). 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.
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 March 28, 2001, 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. See
"Risk Factors-Laws and Regulations; Environmental Risks"
EMPLOYEES
As of March 28, 2001, the Company employed 209 people, including 80
administrative personnel, eight geoscientists, eight of which were engineers and
114 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, 2000, the Company's estimated net
proved reserves from all properties totaled 45.2 MMBoe with 78% of the reserves
located in the Rocky Mountains, 20% in the Mid-Continent and 2% in the Gulf
Coast regions. At December 31, 2000, 78% of the Company's net proved reserves
were oil and 22% 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 45% of
the Company's projected drilling expenditures for 2001 are focused on expansion
and development of its oil properties in the Rocky Mountain region while the
remaining 55% is focused 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,
2000:
PRESENT % OF TOTAL
VALUE OF PRESENT
OIL FUTURE CASH VALUE OF
OIL GAS EQUIVALENT FLOWS FUTURE CASH
AREA (MBbl) (MMcf) (MBoe) (M $) FLOWS(2)
- ---- ----- -------- ---------- ---------- -----------
ROCKY MOUNTAINS:
Williston Basin......................... 22,268 3,823 22,906 $183,507 37%
Big Horn Basin.......................... 10,603 10,229 12,308 68,986 14
MID-CONTINENT:
Anadarko Basin.......................... 2,256 40,419 8,992 205,035 42
Arkoma Basin........................ - 19 3 49 0
GULF COAST................................... 137 5,383 1,034 34,222 7
------ ------ ------ -------- -------
TOTALS....................................... 35,264 59,873 45,243 $491,799 100.0%
====== ====== ====== ======== =======
These non-core assets were sold in January 2000 for $5.8 million.
Future estimated net cash flows discounted at 10%
ROCKY MOUNTAINS
The Company's Rocky Mountain properties are located primarily in the
Williston Basin of North Dakota, South Dakota and Montana and in the Big Horn
Basin of Wyoming. Estimated proved reserves for its Rocky Mountains properties
at December 31, 2000, totaled 35.2 MMBoe and represented 51% of the Company's
PV-10. Approximately 94% of these estimated proved reserves are proved
developed. During the twelve months ended December 31, 2000, the average net
daily production was 8,039 Bbls of oil and 5,440 Mcf of natural gas, or 8,950
Boe per day from the Rocky Mountain properties. The Company's leasehold
interests include 158,000 net developed and 173,000 net undeveloped acres, which
represent 36% and 40% 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, 2000, the Company's Rocky Mountain properties included an inventory
of 187 development and six exploratory drilling locations.
WILLISTON BASIN
CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994.
During the twelve months ended December 31, 2000, the Cedar Hills Field
properties produced 3,772 net Boe per day to the Company interests and
represented 22% of the PV-10 attributable to the Company's estimated proved
reserves as of December 31, 2000. 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, 2000, the Company drilled or participated in 158 gross (108 net)
horizontal wells, of which 151 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 proven successful
for increasing oil recoveries from the Red River "B" Formation by 200% to 300%
over primary recovery. The Company is proficient using both technologies and is
planning to utilize both to maximize the recovery of oil from the reservoir. The
Company believes that secondary recovery operations could increase total
recovery from the Cedar Hills Field by as much as 60 million barrels. Drilling
has successfully defined the limits of the field and secondary recovery
operations are scheduled to begin during the second quarter of 2001. The
secondary recovery operations will require a significant investment over the
next three years to drill up to 70 infill wells to be used as injectors to
facilitate secondary water flood operations.
The Company has obtained approval of 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. 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 West Cedar Hills Unit ("WCHU") is
located in Fallon County, Montana. 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. The CHNRRU and the WCHU both became effective on March 1, 2001.
On January 22, 2001, the Company entered into a Mutual Release and
Settlement Agreement ("Agreement") with Burlington Resources ("Burlington"). The
Agreement provided for the Company to make an even exchange of interests with
Burlington, whereby the Company obtained all of Burlington's working interest
and operated wells within the Cedar Hills North - Red River "B" Unit and the
West Cedar Hills Unit, in exchange for the Company transferring to Burlington
its working interests and operated wells in the Burlington operated Cedar Hills
South - Red River "B" Unit. The exchange of interest was effective February 1,
2001. The Agreement provided for the Company and Burlington to support one
another in obtaining regulatory approval of the respective units. Also, as part
of the Agreement, the Company and Burlington agreed to dismiss pending
litigation in the District Court of Garfield County, Oklahoma and also resolved
several outstanding accounting and land disputes between the Company and
Burlington.
MEDICINE POLE HILLS, MEDICINE POLE HILLS WEST, BUFFALO, WEST BUFFALO AND
SOUTH BUFFALO UNITS. In 1995, the Company acquired the following interests in
five 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, 2000, these units produced 1,658 Boe per day, net to the
Company's interests, and represented 3.4 MMBoe or 6% of the PV-10 attributable
to the Company's estimated proved reserves as of December 31, 2000. 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 45 years, demonstrating the long-lived production
characteristic of the Red River "B" Formation. There are 89 producing wells in
these units and current estimates of remaining reserve life range from four to
13 years. As planned, the Company has expanded the Medicine Pole Hills Unit
through horizontal drilling into its newly formed 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. This represents the first in a two-phase expansion of the Medicine
Pole Hills Unit. Secondary injection at the MPHWU began November 22, 2000, and
will expand throughout the field in 2001. The Company owns approximately 80% of
the MPHWU. During 2001, the Company plans to drill up to eight horizontal wells
as part of phase two to further expand and develop these units. There are
currently 12 development drilling locations identified in these units.
Approximately 11 square miles of new proprietary 3-D data will be acquired in
key areas of both the Medicine Pole Hills and MPHWU to define additional infill
drilling locations and to guide secondary recovery efforts.
LUSTRE AND MIDFORK FIELDS. In January 1992, the Company acquired the Lustre
and Midfork Fields which, during the twelve months ended December 31, 2000,
produced 266 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 34 wells producing
in the two fields, and no secondary recovery is underway in either field. The
Company currently owns 59,000 net acres in the Lustre and Midfork Field area.
The Company plans to acquire 25 - 50 square miles of proprietary 3-D seismic
data in these areas during 2001 to further develop the Charles "C" reservoirs
and deeper objectives underlying the Lustre and Midfork Fields as well as guide
exploration for new fields on its substantial undeveloped leasehold. The Company
currently has three locations identified to drill in the Lustre and Mid Fork
areas during 2001, and expects additional drilling opportunities to be
identified from the scheduled 3-D seismic.
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
73,000 net leasehold acres in the Worland Field of the Big Horn Basin in
northern Wyoming, of which 30,000 net acres are held by production and 43,000
net acres are non-producing or prospective. Approximately two-thirds of the
Company's producing leases in the Worland Field are within five federal units,
the largest of which the Cottonwood Creek Unit has been producing for more than
40 years. All of the units produce principally from the Phosphoria formation,
which is the most prolific oil producing formation in the Worland Field. Four of
the units are unitized as to all depths, with the Cottonwood Creek Field
Extension (Phosphoria) Unit being unitized only as to the Phosphoria formation.
The Company is the operator of all five of the federal units. The Company also
operates 38 producing wells located on non-unitized acreage. The Company's
Worland Field properties include interests in 256 producing wells, 244 of which
are operated by the Company.
As of December 31, 2000, the estimated net proved reserves attributable to
the Company's Worland Field properties were approximately 12.3 MMBoe, with an
estimated PV-10 of $69.0 million. Approximately 86%, 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 October
1, 1998, through March 31, 1999, to sell crude oil produced from its Worland
Field properties at an average price of $3.19 per Bbl less than the NYMEX price.
Subsequent to these contracts, and effective February 1, 1999, the Company
entered into a contract to sell the Worland Field production at a gravity
adjusted price of $1.67 per barrel less than the monthly NYMEX average price.
This contract will expire April 1, 2001, and is currently being renegotiated.
The Company anticipates the spread from NYMEX will increase with the new
contract.
In addition to the proved reserves, the Company has identified 157
potential development drilling locations on its Worland Field properties, to
further develop and exploit the undeveloped portion of the Worland Field. More
than 101 wells have been identified for acid fracture stimulation and other
workovers and recompletions, most of which have been classified as having proved
developed non-producing reserves. The Company believes that secondary and
tertiary recovery projects will have significant potential for the addition of
reserves. In addition, two exploratory drilling prospects have been identified
on the Company's Worland Field properties in which prospects the Company has a
majority leasehold position, allowing for further exploration for and
exploitation of the Phosphoria, Tensleep, Frontier and Muddy formations and
other prospective formations for additional reserves.
MID-CONTINENT
The Company's Mid-Continent properties are located primarily in the
Anadarko Basin of western Oklahoma, southwestern Kansas and the Texas Panhandle,
and to a lesser extent, in the Arkoma Basin of southeastern Oklahoma ("Arkoma
Basin"). At December 31, 2000, the Company's estimated proved reserves in the
Mid-Continent totaled 9 MMBoe and represented 42% of the Company's PV-10. At
December 31, 2000, approximately 75% of the Company's estimated proved reserves
in the Mid-Continent were natural gas. Net daily production from these
properties during 2000 averaged 1,125 Bbls of oil and 12,465 Mcf of natural gas,
or 3,202 Boe to the Company's interests. The Company's Mid- Continent leasehold
position includes 55,607 net developed and 33,115 net undeveloped acres,
representing 13% and 7% of the Company's total leasehold, respectively, at
December 31, 2000. As of December 31, 2000, the Company's Mid- Continent
properties included an inventory of 15 development and 21 exploratory drilling
locations.
ANADARKO BASIN. The Anadarko Basin properties contained 100% of the
Company's estimated proved reserves for the Mid-Continent and 42% of the
Company's total PV-10 at December 31, 2000, and represented 75% of the Company's
estimated proved reserves of natural gas. During the twelve months ended
December 31, 2000, net daily production from its Anadarko Basin properties
averaged 1,125 Bbls of oil and 12,465 Mcf of natural gas, or 3,202 Boe to the
Company's interest from 693 gross (301 nets) producing wells, 418 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 are continually being evaluated for further development drilling and
workover potential.
ARKOMA BASIN. As part of the Company's strategic plan to divest of non-core
assets for the purpose of allocating resources to higher reserve growth
projects, all oil and gas properties in the Arkoma Basin, along with the
Rattlesnake and Enterprise Gas Gathering System, were sold in January 2000 for
$5.8 million.
GULF COAST
The Company's Gulf Coast activities are located primarily in the Pebble
Beach Project in Nueces County, Texas and the Jefferson Island Project in Iberia
Parish, Louisiana. In July 1999, the Company entered into a joint venture
arrangement with Challanger Minerals to expand its drilling activities into the
shallow shelf area of the Gulf of Mexico. At December 31, 2000, the Company's
estimated proved reserves in the Gulf Coast totaled 1 MMBoe (87% gas)
representing 7% of the Company's total PV-10 and 9% of the Company's estimated
proved reserves of natural gas. Net daily production from these properties is 41
Bbls of oil and 3,845 Mcf of natural gas or 682 Boe to the Company's interest
from 20 wells. The Company's leasehold position includes 4,986 net developed and
11,547 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 30 exploratory locations have been identified for
drilling on these projects to date.
PEBBLE BEACH. The Pebble Beach project targets the prolific Frio and
Vicksburg sands underlying and surrounding the Clara Driscoll field. These
sandstones are found at depths ranging from 5000' to 9500' and produce on
structures readily defined by seismic. During 2000, an additional 15 square
miles of proprietary 3-D seismic was acquired to expand the project, bringing
the total seismic available across the project to 35 square miles. During 2000
the Company completed five development wells as producers and had one new field
discovery. The Company has identified six development and seven exploratory
drilling locations for drilling in 2001. The Company continues to expand its
leasehold in the Pebble Beach project and plans to acquire another 10 square
miles of proprietary 3-D seismic to evaluate this acreage in 2001. The Company
owns 18,050 gross and 11,450 net acres in the project. During 2000 the Company
also acquired ownership of the nearby Luby field at no cost, for plugging
liability and a small override. The Company believes the potential for
production from deeper objectives also exists in and around the Luby field and
plans to begin developing these opportunities in 2001.
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 has acquired 35 square miles of proprietary 3-D
seismic covering the property and has identified three potential development and
five exploratory drilling locations. During 2000, a third party completed its
3-D seismic and drilling commitment to earn 50% of the project. To earn 50%, the
third party had to pay 100% of costs for 3-D seismic and was obligated to drill
five wells in which the Company owned 16% working interest at no cost. Out of
the five wells drilled by the third party, two are commercial wells, two non
commercial and one was a dry hole. To date, results have not met expectations
and during 2001, the Company has plans to drill up to three exploratory wells in
the project seeking higher reserve potential. The Company controls 4,513 gross
and 3,475 net acres in the project.
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. 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, 2000, the Company has participated in
eight wells which resulted in five producers and three dry holes. The Company
plans to continue its expansion in the GOM as a non- operator and plans to
restrict investments to approximately $500,000 per project as it continues to
gain experience in this new area. During 2000, the Company spent 14% of its
drilling budget on opportunities in the GOM and expects to spend up to 20% of
its drilling budget in the GOM during 2001. The Company currently has five wells
in inventory for 2001.
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
---------------------------------
1998 1999 2000
-------- -------- --------
NET PRODUCTION DATA:
Oil and condensate (MBbl) 3,981 3,221 3,360
Natural gas (MMcf) 6,755 6,640 7,939
Total (MBoe) 5,107 4,328 4,684
UNIT ECONOMICS
Average sales price per Bbl $ 12.38 $ 16.93 $ 29.02
Average sales price per Mcf 1.61 1.72 2.91
Average equivalent price (per Boe) 11.78 15.24 25.81
Lifting cost (per Boe) 4.43 4.47 6.36
DD&A expense (per Boe) 6.78 3.61 3.71
General and administrative expense (per Boe) 1.40 1.31 1.80
------- -------- --------
Gross margin $ (0.83) $ 5.85 $ 13.94
======= ======== ========
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 Starements 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."
Related to oil and gas producing properties.
Related to oil and gas producing properties, net of operating overhead
income.
PRODUCING WELLS
The following table sets forth the number of productive wells, exclusive of
injection wells and water wells, in which the Company owned an interest as of
December 31, 2000:
OIL NATURAL GAS TOTAL
--- ----------- -----
GROSS NET GROSS NET GROSS NET
ROCKY MOUNTAIN:
Williston Basin 322 264 - - 322 264
Big Horn Basin(1) 255 227 1 1 256 228
--- --- --- --- --- ---
Total ROCKY MOUNTAIN 577 491 1 1 578 492
MID-CONTINENT:
Anadarko Basin 399 216 294 85 693 301
GULF COAST 6 5 14 9 20 14
--- --- --- --- --- ---
Total 982 712 309 95 1291 807
=== === === === === ===
Represents Worland Field properties acquired by the Company in the Worland
Field Acquisition
ACREAGE
The following table sets forth the Company's developed and undeveloped
gross and net leasehold acreage as of December 31, 2000:
DEVELOPED UNDEVELOPED TOTAL
----------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
------- --------- ------- ------- ------- -------
ROCKY MOUNTAIN:
Williston Basin........ 167,911 128,582 160,442 130,191 328,353 258,773
Big Horn Basin......... 30,189 29,379 44,467 43,292 74,656 72,671
------ ------ ------ ------ ------ ------
Total ROCKY MOUNTAIN.... 198,100 157,961 204,909 173,483 403,009 331,444
MID-CONTINENT:
Anadarko Basin......... 93,049 55,607 18,853 13,153 111,902 68,760
Other.................. 0 0 20,478 17,962 20,478 17,962
------- ------- ------ ------ ------ ------
Total MID-CONTINENT.... 93,049 55,607 39,331 31,115 132,380 86,722
GULF COAST.................. 10,653 4,986 20,385 11,547 31,038 16,533
------- ------- ------- ------- ------- -------
Grand Total............ 301,802 218,554 264,625 216,145 566,427 434,699
======= ======= ======= ======= ======= =======
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on its
properties for the periods indicated:
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1998 1999 2000
---------------- ------------------ -----------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
DEVELOPMENT WELLS:
Productive........ 32 22 12 6.90 23 19.35
Non-productive.... - - 1 .16 3 2.92
--- ----- --- ----- -- -----
Total............. 32 22 13 7.06 26 22.27
=== ===== === ===== === =====
EXPLORATORY WELLS:
Productive........ 5 4.23 2 .74 15 9.26
Non-productive.... - - 2 1.25 7 2.99
--- ----- --- ----- -- -----
Total............. 5 4.23 4 1.99 22 12.25
=== ===== === ===== == =====
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, 1998, 83% of the PV-10 at December
31, 1999, and 83% of the PV-10 at December 31, 2000. The Company prepared the
reserve and present value data on all other properties.
AS OF DECEMBER 31,
----------------------------------
1998 1999 2000
-------- -------- --------
(DOLLARS IN THOUSANDS)
RESERVE DATA:
Proved developed reserves:
Oil (MBbl)......................... 19,097 34,432 33,173
Natural gas (MMcf)................. 54,905 65,723 58,438
Total (MBoe).................. 28,248 45,386 42,913
Proved undeveloped reserves:
Oil (MBbl)......................... 833 2,192 2,091
Natural gas (MMcf)................. 314 10,038 1,435
Total (MBoe).................. 885 3,865 2,330
Total proved reserves:
Oil (MBbl)......................... 19,930 36,624 35,264
Natural gas (MMcf)................. 55,219 75,761 59,873
Total (MBoe).................. 29,133 49,251 45,243
PV-10.............................. $ 107,670 $ 334,411 $ 491,799
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, 1998, 1999 and 2000, were $10.84 per
Bbl of oil and $1.64 per Mcf of natural gas, $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, respectively.
Estimated quantities of proved reserves and future net cash flows therefrom
are affected by oil and gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating oil and gas
reserves and their values, including many factors beyond the control of the
producer. The reserve data set forth in this annual report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil andgas 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 of 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, 2000,
purchases of the Company's natural gas production by ENCINA Gas Pipeline
accounted for 7% 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 63% 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 hedging strategies to hedge 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.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is party to litigation or other legal proceedings
that it considers to be a part of the ordinary course of its business. The
Company is not involved in any legal proceedings nor is it party to any pending
or threatened claims that could reasonably be expected to have a material
adverse effect on its financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
There is no established trading market for the Company's common stock. The
Company authorized an approximate 293:1 stock split during 2000. As a result all
amounts are presented retroactive to account for the split. As of March 28,
2001, there were three record holders of the Company's common stock. The Company
issued no equity securities during 2000. During 2000, the Company established a
Stock Option Plan with 1,020,000 shares available, of which, 144,000 shares were
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, 1996, 1997,
1998, 1999 and 2000, and the balance sheet data as of December 31, 1996, 1997,
1998, 1999 and 2000, 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, 1999, and 2000, and
the statements of operations for the years ended December 31, 1998, 1999 and
2000, 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,
----------------------------------------------------
1996 1997 1998 1999 2000
-------- -------- -------- -------- --------
(DOLLARS IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales............................ $ 75,016 $ 78,599 $ 60,162 $ 65,949 $ 115,478
Crude oil marketing.......................... - - 232,216 241,630 279,834
Gathering, marketing and processing.......... 25,766 25,021 17,701 21,563 32,757
Oil and gas service operations............... 6,491 6,405 6,689 6,319 7,656
--------- --------- --------- --------- ----------
Total revenues................................. 107,273 110,025 316,768 335,461 435,726
Operating costs and expenses:
Production expenses and taxes................ 19,338 20,748 22,611 19,368 29,807
Exploration expenses......................... 4,512 6,806 7,106 7,750 13,321
Crude oil marketing purchases and expenses... - - 228,797 236,135 278,809
Gathering, marketing and processing.......... 21,790 22,715 15,602 17,850 27,593
Oil and gas service operations............... 4,034 3,654 3,664 3,420 5,582
Depreciation, depletion and amortization..... 22,876 33,354 38,716 20,385 21,945
General and administrative................... 9,155 8,990 10,002 8,627 10,358
---------- --------- --------- --------- ----------
Total operating costs and expenses............. 81,705 96,267 326,498 313,535 387,415
---------- --------- --------- --------- ----------
Operating income (loss)........................ 25,568 13,758 (9,730) 21,926 48,311
Interest income................................ 312 241 967 310 756
Interest expense............................... (4,550) (4,804) (12,248) (16,534) (15,786)
Change in accounting principle............. 0 0 0 (2,048) 0
Other revenue (expense), net............... 233 8,061 3,031 266 4,499
---------- -------- --------- --------- ----------
Income (loss) before income taxes.............. 21,563 17,256 (17,980) 3,920 37,780
Federal and state income taxes (benefit)... 8,238 (8,941) - - -
---------- --------- --------- --------- ----------
Net income (loss).............................. $ 13,325 $ 26,197 $(17,980) $ 3,920 $ 37,780
========== ========= ========= ========= ==========
OTHER FINANCIAL DATA:
Adjusted EBITDA............................ $ 53,502 $ 54,721 $ 40,090 $ 48,589 $ 88,832
Net cash provided by operations................ 41,724 51,477 25,190 23,904 69,690
Net cash used in investing..................... (50,619) (78,359) (112,050) (13,698) (41,674)
Net cash provided by (used in) financing....... 10,494 24,863 101,376 (15,602) (31,287)
Capital expenditures....................... 50,341 80,937 92,782 55,255 49,339
RATIOS:
Adjusted EBITDA to interest expense............ 11.8x 11.4x 3.3x 3.0x 5.6x
Total debt to Adjusted EBITDA.................. 1.0x 1.5x 4.2x 3.5x 1.6x
Earnings to fixed charges.................. 5.7x 4.6x N/A 1.2x 3.3x
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents...................... $ 3,320 $ 1,301 $ 15,817 $ 10,421 $ 7,151
Total assets................................... 145,693 88,386 253,739 282,559 298,623
Long-term debt, including current maturities... 54,759 79,632 167,637 170,637 140,350
Stockholders' equity........................... 52,077 78,264 60,284 86,666 123,446
In 1997, other income includes $7.5 million resulting from the settlement
of certain litigation matters.
Effective June 1, 1997, the Company elected to be treated as an
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.
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. The Company's Adjusted EBITDA for the 2000 period was greater than
in 1999 due to the increase in the volume of oil and gas produced and the
increases in oil and gas prices. 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.
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.
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.
Cumulative effect represents the impact of adopting EITF 98-10 "Accounting
for Energy Trading and Risk Management Activities."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF 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 2000 than in 1999 and
experienced a significant increase in revenues, net income and Adjusted EBITDA
in 2000 compared to 1999 because of higher prevailing oil and gas prices.
Average well head prices during 2000 were $29.02 per Bbl of oil and $2.91 per
Mcf of natural gas compared to $16.93 per Bbl of oil and $1.72 per Mcf of
natural gas during 1999. 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 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,
----------------------------------------
1998 1999 2000
---------- ---------- ----------
(Dollars in Thousands, Except Average Price Data)
Revenues.............................. $ 316,768 $ 335,461 $ 435,726
Operating expenses.................... 326,498 313,535 387,415
Non-Operating income (expense)........ (8,250) (15,958) (10,530)
Change in accounting principle........ -- (2,048) -
Net income after tax.................. (17,980) 3,920 37,780
Adjusted EBITDA................... 40,090 48,589 88,832
Production Volumes:
Oil and condensate (MBbl).......... 3,981 3,221 3,360
Natural gas (MMcf)................. 6,755 6,640 7,939
Oil equivalents (MBoe)............. 5,107 4,328 4,684
Average Prices:
Oil and condensate (per Bbl)....... $ 12.52 $ 16.93 $ 29.02
Natural gas (per Mcf).............. 1.61 1.72 2.91
Oil equivalents (per Boe).......... 11.78 15.24 25.81
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. Even though the volume of oil and gas produced by the Company
during 1999, on an actual basis, was less than in the comparable period in
1998, the Company's Adjusted EBITDA for the 1999 period was greater than in
1998. The increase in Adjusted EBITDA for the 1999 period was attributable
to increases in oil and gas prices. The increase in Adjusted EBITDA for the
2000 period was also attributable mainly to the increase in oil and gas
prices. 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.
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 Mcfs of natural gas produced by six and by
adding the resultant sum to barrels of oil and condensate produced.
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, 1998, 1999 and 2000, were $11.88, $15.31 and
$25.16, respectively.
YEAR ENDED DECEMBER 31, 2000, COMPARED TO YEAR ENDED DECEMBER 31, 1999
REVENUES
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 & 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 $2.7 million 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 Senior Subordinated 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 1400%, 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 Senior Subordinated 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 $2,048,000 during the year ended
December 31, 1999.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
OIL AND GAS SALES
Oil and gas sales revenue for 1999 increased $5.8 million, or 10%, to $65.9
million from $60.1 million in 1998. Oil prices increased from an average of
$12.38/Bbl in 1998 to $16.93/Bbl in 1999 which resulted in a $14.7 million
increase in revenues. The effects of the price increase were partially offset by
a 760 MBbl decrease in oil production in 1999 compared to 1998. The decreased
production was due to the natural production declines for new wells and to low
drilling activities in 1999. During 1999 the Company chose to reduce debt rather
than drill due to the instability of oil prices. The Company's average gas sales
prices increased from $1.61 per Mcf in 1998 to $1.72 per Mcf in 1999.
CRUDE OIL MARKETING
The Company recognized an increase in revenues on crude oil purchased for
resale for 1999 of $9.4 million, or 4% to $241.6 million from $232.2 million for
1998. This was caused by increases in oil prices and was also due to only a
partial year of activity in 1998 compared to a full year in 1999 and is offset
by a decrease in monthly volumes traded.
GATHERING, MARKETING AND PROCESSING
The 1999 gathering, marketing and processing revenues increased $3.9
million, or 22%, to $21.6 million compared to $17.7 million for 1998. $1.7
million of the increase was attributable to operations from the Eagle Chief
Plant in Oklahoma and $0.9 million was from the addition of the Matli gas
gathering system and $0.7 million from the Badlands Gas Processing Plant.
OIL AND GAS SERVICE OPERATIONS
Oil and gas service operations revenues decreased $0.4 million, or 6%, to
$6.3 million in 1999 from $6.7 million in 1998. The decrease was primarily
attributable to reduced sales of inventory caused by lower drilling activity in
1999.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Production expense and taxes were $19.4 million for the 1999, a $3.2
million, or 14% decrease over the 1998 expenses of $22.6 million, primarily as a
result of lower production volumes and greater operating efficiencies. The
decrease was seen in all areas of direct costs associated with the Company's
operations, except for taxes. Taxes increased by $0.9 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 $0.6 million, or 8%, to $7.7 million in 1999
from $7.1 million in 1998. The increase was attributable to a $3.2 million
increase in expired leases partially offset by a decrease in dry hole costs and
other expenses of $2.6 million.
CRUDE OIL MARKETING
Expenses for crude oil purchased for resale increased $7.2 million, or 3%, to
$235.3 million in 1999 from $228.1 million in 1998. Marketing expenses increased
$0.1 million, or 22%, to $0.8 million in 1999 from $0.7 million in 1998. The
increase was caused by increased crude oil prices and was also due to only a
partial year of activity in 1998 compared to a full year in 1999 and is offset
by a decrease in monthly volumes traded.
GATHERING, MARKETING AND PROCESSING
Gathering, Marketing and Processing expense for 1999 was $17.8 million, a
$2.2 million, or 14%, increase from the $15.6 million incurred in 1998 due to
higher natural gas and liquid prices and the addition of the Matli gas gathering
system and the increase in the Badlands system in North Dakota.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
For the year ended December 31, 1999, total DD&A Expense was $20.4 million,
a $18.3 million, or 47%, decrease over the 1998 expense of $38.7 million. In
1999, lease and well DD&A was $15.6 million, a decrease of $19.0 million from
$34.6 million in 1998. The decrease is due to favorable adjustments to reserve
volumes caused by higher oil and gas prices resulting in a decline in the DD&A
rate per Boe and due to the non recurring $7.9 million write-down associated
with FASB 121 in 1998. There was no FASB 121 write-down in 1999. In 1998, the
FASB 121 write-down contributed $1.55 per Boe, or 23%, of the lease and well
DD&A expense of $6.78 per Boe. For 1999 DD&A expense amounted to $3.61 per Boe.
GENERAL AND ADMINISTRATIVE (G&A)
G&A expense for 1999 was $8.6 million, net of overhead reimbursement of
$2.9 million, or $5.7 million, a decrease of $1.4 million, or 21%, from G&A
expenses for 1998 of $10.0 million, net of overhead reimbursement of $2.9
million, or $7.1 million. The decrease is primarily attributable to a decrease
in employment expenses, including a temporary decrease in the payroll and
benefits costs as described below.
On January 6, 1999, as part of its objective of focusing on cash margins
and profitability, the Company initiated a cost restructuring plan which
included personnel cost reductions which were included in G&A expense. This
reduction was accomplished through a combination of personnel and payroll
reductions and the temporary suspension of the Company's contribution to the
Company's 401K plan. Permanent savings due to staff reductions were
approximately $0.5 million in 1999. An additional $0.3 million in savings was
recognized in other employee expenses. Various other office expenses decreased
by $0.7 million. The Company reinstated its contribution to the Company 401K
plan effective April 1, 1999, and salaries were returned to their previous level
effective May 1, 1999.
INTEREST INCOME
Interest income for 1999 was $0.3 million compared to $1.0 million for
1998, a $0.7 million, or 68% decrease. The decrease in the 1999 period is
attributable to lower levels of cash invested during 1999.
INTEREST EXPENSE
Interest expense for 1999 was $16.5 million, an increase of $4.3 million,
or 35%, from $12.2 million in 1998. The increase in the 1999 expense was
attributable primarily to interest on the Senior Subordinated Notes which had
only accrued five months of interest expense in 1998 compared to 12 months in
1999.
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.
OTHER INCOME
Other income decreased $2.7 million, or 91%, to $0.3 million for the year
ended December 31, 1999, from $3.0 million for 1998. This decrease in other
income compared to 1998 is attributed primarily to the recognition in 1998 of a
$2.5 million gain on the sale of the Illinois properties.
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE
Income before income taxes and change in accounting principle for the year
ended December 31, 1999, was $5.9 million, an increase of $23.8 million from a
$17.9 million loss before taxes and cumulative effect of change in accounting
principle for 1998. This increase was primarily due to the increased revenues
caused by higher oil and gas sales prices and lower operating and general and
administrative costs.
NET INCOME
The 1999 Net Income was $3.9 million, including a charge resulting from a
cumulative effect of change in accounting principle of $2.0 million, an increase
in net income of $21.9 million compared to a loss of $17.9 million in 1998. 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.
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 and
development of oil and gas properties and debt service payments.
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $69.7 million for 2000 a 192%
increase from the $23.9 million in 1999. The increase was primarily due to the
increase in net income from operations which was primarily attributable to oil
and gas price increases. Cash decreased to $7.2 million at December 31, 2000,
from $10.4 million at year-end 1999 primarily due to repayment of indebtedness.
RESERVES AND ADDED FINDING COSTS
During 1999 and 2000, the Company spent $32.5 million and $49.3 million,
respectively on acquisitions, exploration, exploitation and development of oil
and gas properties. The 1999 amount includes the assumption of the loan of $18.6
million from the principal stockholder. Total estimated proved reserves of
natural gas decreased from 75.8 Bcf at year-end 1999 to 59.9 Bcf at December 31,
2000, and estimated total proved oil reserves decreased from 36.6 MMBbls at
year-end 1999 to 35.3 MMBbls at December 31, 2000. The Company sold reserves of
approximately 2.4 Bcf and 2,000 Bbls in January 2000 related to the sale of
properties in the Arkoma Basin. The balance of the decline in natural gas
reserves was primarily due to downward revisions of reserve volumes in the Big
Horn Basin and the non-drilling of PUDs in the Big Horn Basin due to
reallocation of drilling resources to the Gulf Coast region.
FINANCING
Long-term debt at December 31, 1999 and December 31, 2000, was $170.2
million and $130.1 million, respectively. The $40.1 million, or 24% decrease was
mainly due to the purchase and retirement of $19.9 million of the Senior
Subordinate Notes, a reduction in the Company's bank debt of $18.6 million and
other debt reductions of $2.0 million.
CREDIT FACILITY
Long-term debt outstanding at December 31, 1999 included $18.6 million of
revolving debt under the Credit Facility. The Company has $10.2 million
outstanding debt balance under the Credit Facility at December 31, 2000. The
effective rate of interest under the Credit Facility was 8.5% at December 31,
1999 and was 8.9% at December 31, 2000. This Credit Facility is for borrowings
up to $25 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
---------- ------------ ----------------- -----------
> 75% 2.00% 0.00% 25.00 basic points per annum
> 50% < 75% 1.75% 0.00% 22.50 basic points per annum
> 25% < 50% 1.50% 0.00% 20.00 basic points per annum
< 25% 1.25% 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, 2001. The Credit Agreement is currently being renegotiated to be
extended for two years and the line is expected to increase to $35 million. As
of March 28, 2001, the Company has borrowed $12.7 million against this Credit
Facility.
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.
CAPITAL EXPENDITURES
In 2000 the Company incurred $49.3 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 62
projects will be initiated in 2001 for projected capital expenditures of $70.7
million. The Company expects to fund the 2001 capital budget through cash flow
from operations and its Credit Facility.
PURCHASE OF WORLAND FIELD
On May 18, 1998, the Company consummated the purchase for approximately
$86.5 million of producing and non- producing oil and gas properties and certain
other related assets in the Worland Properties effective as of June 1, 1998,
which the Company funded through borrowings on its Credit Facility.
Subsequently, and effective June 1, 1998, the Company sold an undivided 50%
interest in the Worland Properties (excluding inventory and certain equipment)
to the Company's principal stockholder for approximately $42.6 million. Of the
total sale price to the stockholder, approximately $23.0 million plus interest
of approximately $0.3 million was offset against the outstanding balance of
notes payable to the stockholder and approximately $19.6 million was applied to
the outstanding balance on the Credit Facility on July 24, 1998. In December
1999 the principal stockholder contributed his interest in the purchased
properties to the Company, subject to debt of $18.6 million. The contribution
was recorded based on the stockholder's cost less DD&A from the date acquired to
the date contributed which was $41.4 million.
STOCKHOLDER DISTRIBUTION
During 2000 the Company made dividend distributions to its stockholders for
$1.0 million to cover the taxes on the taxable income passed through to the
stockholders of record.
HEDGING
From time to time, the Company may use energy swap and forward sale
arrangements to reduce its sensitivity to oil and gas price volatility. In July
1998, the Company began engaging in oil trading arrangements as part of its oil
and gas marketing activities.
The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119 "Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments". The Company's objective is
to hedge a portion of its exposure to price volatility from producing oil and
natural gas. These arrangements expose the Company to the credit risk of its
counterparties and to basis risk.
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 property.
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 $2,614,000, $151,400 and $3,726,000 in 1998, 1999 and 2000
respectively. Total amounts of oil and gas reserves associated with these
dispositions during 1998, 1999 and 2000 were 184 MBbls of oil and 2,718 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 have been filed with the Court which will result 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 had no oil or gas hedging transactions for its production, however, the
Company did begin marketing crude oil. Most of the Company's purchases 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. The Company has no oil
or gas hedging transactions for its production or net long or short fixed price
positions in respect to its crude oil marketing activities as of December 31,
2000.
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 is now 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.
- -------------------------------------------------------------------------------------------------------------------
2000
Year-end
(dollars in millions) 2001 2002 2003 2004 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Principal amount 130,150 130,150 130,150
Weighted-average
interest rate 10.25% 10.25% --
Variable-rate debt:
Principal amount 10,200 -- -- -- -- $10,200 $10,200
Weighted-average
interest rate 8.9% -- -- -- 8.9% 8.9% --
- -------------------------------------------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX OF FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 1999 and 2000
Consolidated Statements of Operations for the Years Ended December 31,
1998, 1999 and 2000
Consolidated Statements of Stockholders' Equity
for the Years Ended December 31, 1998, 1999 and 2000
Consolidated Statements of Cash Flows for the Years Ended December 31,
1998, 1999 and 2000
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Continental
Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31,
1999 and 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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, 1999 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
February 16, 2001
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share information)
ASSETS
December 31,
-----------------------
1999 2000
---------- ----------
CURRENT ASSETS:
Cash $ 10,421 $ 7,151
Accounts receivable-
Oil and gas sales 11,508 15,778
Joint interest and other, net 8,517 9,839
Inventories 4,112 4,988
Prepaid expenses 1,690 209
--------- ---------
Total current assets 36,248 37,965
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)-
Producing properties 293,467 321,197
Nonproducing leaseholds 43,083 44,544
Gas gathering and processing facilities 25,740 25,051
Service properties, equipment and other 14,884 15,917
--------- ---------
Total property and equipment 377,174 406,709
Less--Accumulated depreciation, depletion
and amortization (138,872) (151,899)
--------- ---------
Net property and equipment 238,302 254,810
--------- ---------
OTHER ASSETS:
Debt issuance costs, net 7,847 5,842
Other assets 162 6
--------- ---------
Total other assets 8,009 5,848
--------- ---------
Total assets $ 282,559 $ 298,623
========= =========
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share information)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 8,448 $ 17,164
Current debt 356 10,200
Revenues and royalties payable 6,865 7,181
Accrued liabilities and other 9,776 10,375
----------- -----------
Total current liabilities 25,445 44,920
----------- -----------
LONG-TERM DEBT, net of current portion 170,281 130,150
OTHER NONCURRENT LIABILITIES 167 107
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, 1999 and 2000
Common stock, $0.01 par value, 20,000,000 shares authorized,
14,368,919 shares issued and outstanding at December 31,
1999 and 2000 144 144
Additional paid-in capital 25,087 25,087
Retained earnings 61,435 98,215
----------- -----------
Total stockholders' equity 86,666 123,446
----------- -----------
Total liabilities and stockholders' equity $ 282,559 $ 298,623
=========== ===========
The accompanying notes are an integral part of these consolidated balance
sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share information)
December 31,
------------------------------------
1998 1999 2000
---------- ---------- ----------
REVENUES:
Oil and gas sales $ 60,162 $ 65,949 $ 115,478
Crude oil marketing 232,216 241,630 279,834
Gas gathering, marketing and processing 17,701 21,563 32,758
Oil and gas service operations 6,689 6,319 7,656
--------- --------- ----------
Total revenues 316,768 335,461 435,726
--------- --------- ----------
OPERATING COSTS AND EXPENSES:
Production expenses 19,028 14,796 20,301
Production taxes 3,583 4,572 9,506
Exploration expenses 7,106 7,750 13,321
Crude oil marketing purchases and expenses 228,797 236,135 278,809
Gas gathering, marketing and processing 15,602 17,850 27,593
Oil and gas service operations 3,664 3,420 5,582
Depreciation, depletion and amortization 38,716 20,385 21,945
General and administrative 10,002 8,627 10,358
--------- --------- ----------
Total operating costs and expenses 326,498 313,535 387,415
--------- --------- ----------
OPERATING INCOME (LOSS) (9,730) 21,926 48,311
--------- --------- ----------
OTHER INCOME ( EXPENSE):
Interest income 967 310 756
Interest expense (12,248) (16,534) (15,786)
Other income, net 3,031 266 4,499
--------- --------- ----------
Total other income (expense) (8,250) (15,958) (10,530)
--------- --------- ----------
INCOME (LOSS) BEFORE
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE (17,980) 5,968 37,780
CUMULATIVE EFFECT OF CHANGE
NET INCOME (LOSS) $ (17,980) $ 3,920 $ 37,780
========= ========= ==========
EARNING (LOSS) PER COMMON SHARE:
Before cumulative effect of change in
accounting principle
Basic $ (1.25) $ .42 $ 2.63
========= ========= ==========
Diluted $ (1.25) $ .42 $ 2.62
========= ========= ==========
After cumulative effect of change in
accounting principle
Basic $ (1.25) $ .27 $ 2.63
========= ========= ==========
Diluted $ (1.25) $ .27 $ 2.62
========= ========= ==========
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, 1998, 1999 AND 2000
(in thousands)
Balance, December 31, 1998 14,368,919 $ 144 $ 2,626 $ 57,515 $ 60,285
Contribution of interest in oil
and gas properties and associated
debt by principal stockholder -- -- 22,461 -- 22,461
Net income -- -- -- 3,920 3,920
---------- ------ -------- -------- --------
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
========== ====== ======== ======== ========
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, 1998, 1999 AND 2000
(in thousands)
1998 1999 2000
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (17,980) $ 3,920 $ 37,780
Adjustments to reconcile net income (loss) to net
cash provided by operating activities-
Depreciation, depletion and amortization 38,716 20,385 21,945
Gain on sale of assets (2,539) (151) (3,719)
Dry hole costs and impairment of undeveloped leases 2,880 5,978 7,667
Other noncurrent assets and liabilities (3) 338 1,373
Changes in current assets and liabilities-
Decrease(increase) in accounts receivable 9,645 (5,037) (5,591)
Decrease(increase) in inventories (1,078) 515 (876)
Decrease(increase) in prepaid expenses 215 (1,522) 1,481
Increase(decrease) in accounts payable (9,082) (2,084) 8,716
Increase(decrease) in revenues and royalties payable (1,642) 1,010 315
Increase(decrease in accrued liabilities and other 6,059 552 599
--------- --------- ---------
Net cash provided by operating activities 25,191 23,904 69,690
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (42,715) (12,233) (48,139)
Gas gathering and processing facilities and service
properties, equipment and other (7,517) (266) (1,200)
Purchase of producing properties (85,100) (1,695) --
Cash received on note receivable - stockholder 19,582 -- --
Proceeds from sale of assets 3,641 496 7,665
Advances from affiliates 58 -- --
--------- --------- ---------
Net cash used in investiving activities (112,051) (13,698) (41,674)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 266,515 4,600 37,000
Repayment of Senior Subordinated Notes -- -- 19,850
Repayment of line of credit and other (165,539) (10,202) (47,436)
Debt issuance costs (9,600) -- --
Proceeds from short-term debt due to stockholder 10,000 -- --
Repayment of short-term debt due to stockholder -- (10,000) --
Payment of cash dividend -- -- (1,000)
--------- --------- ---------
Net cash provided by (used in) financing activities 101,376 (15,602) (31,286)
--------- --------- ---------
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000
(in thousands)
1998 1999 2000
---- ---- ----
NET INCREASE (DECREASE) IN CASH 14,516 (5,396) (3,270)
CASH, beginning of year 1,301 15,817 10,421
-------- -------- --------
CASH, end of year $ 15,817 $ 10,421 $ 7,151
======== ======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 12,248 $ 16,583 $ 16,615
NONCASH INVESTING AND FINANCING ACTIVITIES:
Sale of 50% interest in oil and gas
properties to principal stockholder:
Satisfaction of note payable $ 22,969 $ -- $ --
Issuance of note receivable $ 19,582 $ -- $ --
Conversion of account receivable to note
receivable $ 510 $ -- $ --
Contribution of interest in oil and gas
properties by stockholder
Oil and gas properties $ -- $ 41,371 $ --
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 two wholly-owned subsidiaries, Continental Gas, Inc. ("CGI") and
Continental Crude Co. ("CCC"). CGI was incorporated in April 1990. CCC was
incorporated in May 1998. Since its incorporation, CCC has had no operations,
has acquired no assets and has incurred no liabilities.
CRI's principal business is oil and natural gas exploration, development and
production. CRI has interests in approximately 1,291 wells and serves as the
operator in the majority of such wells. CRI's operations are primarily in
Oklahoma, North Dakota, South Dakota, Montana, Wyoming, Texas 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 five 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, CGI and CCC (collectively the "Company"). All significant
intercompany accounts and transactions have been eliminated in the consolidated
financial statements.
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, 1999 and 2000, are recorded
net of an allowance for doubtful accounts of approximately $387,000 and
$383,000, 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, 1999 and 2000, tubular goods and production equipment totaled
approximately $3,620,000 and $4,311,000, respectively and crude oil in tanks
totaled approximately $491,000 and $677,000, 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 1998, 1999 and 2000. The weighted-average number
of shares used to compute diluted EPS for 2000 was 14,393,132. There are no
common stock equivalents or securities outstanding during 1998 and 1999 which
would result in material dilution.
Futures Contracts
CGI, in the normal course of business, enters into fixed price contracts for
either the purchase or sale of natural gas at future dates. Due to fluctuations
in the natural gas market, CGI buys or sells natural gas futures contracts to
hedge the price and basis risk associated with the specifically identified
purchase or sales contracts. CGI accounts for changes in the market value of
futures contracts as a deferred gain or loss until the production month of the
hedged transaction, at which time the gain or loss on the natural gas futures
contracts is recognized in the results of operations. At December 31, 1999 and
2000, there were no open natural gas futures contracts. Net gains and losses on
futures contracts 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, 1998, 1999 and 2000.
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, 2000, 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.
Crude Oil Hedging
At December 31, 2000, the Company had no open hedging contracts.
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, 1999 and
2000 were not material.
Significant Customer
During 1998, 1999 and 2000, approximately 24.2%, 25.2% and 22.8%,
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 bank debt 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.
Accounting Principles
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 is now 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.
3. ACQUISITION OF PRODUCING PROPERTIES:
On May 18, 1998, the Company consummated the purchase for approximately
$86.5 million of producing and non- producing oil and gas properties and certain
other related assets in the Worland Properties effective as of June 1, 1998,
which the Company funded through borrowings on its line of credit. Subsequently,
and effective June 1, 1998, the Company sold an undivided 50% interest in the
Worland Properties (excluding inventory and certain equipment) to the Company's
principal stockholder for approximately $42.6 million. Of the total sale price
to the stockholder, approximately $23.0 million plus interest of approximately
$0.3 million was offset against the outstanding balance of notes payable to the
stockholder and approximately $19.6 million was recorded as an increase in
advances to affiliates.
This acquisition has been recorded using the purchase method of accounting.
The following presents unaudited pro forma results of operations for the year
ended December 31, 1998, as if these acquisitions had been consummated as of
January 1, 1998. These pro forma results are not necessarily indicative of
future results.
(in thousands, except per share data) 1998 Pro Forma
(Unaudited)
-----------
Revenues $ 318,895
---------
Net income (loss) $ (21,184)
---------
Earnings (loss) available to common stock $ (21,184)
---------
Basic Earnings (loss) per common share $ (1.47)
---------
On December 31, 1999, the Company's principal stockholder contributed the
undivided 50% interest in the Worland Properties to the Company along with debt
with an outstanding 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. The following presents unaudited pro forma results of
operations for the years ended December 31, 1998 and 1999, as if the
contribution had been consummated as of January 1, 1998. These pro forma results
are not necessarily indicative of future results.
Pro Forma (Unaudited)
--------- -----------
(in thousands, except per share data) 1998 1999
---- ----
Revenues $ 321,023 $ 341,796
========= =========
Net income (loss) $ (22,931) $ 6,052
========= =========
Earnings (loss) available to common stock $ (22,931) $ 6,052
========= =========
Basic Earnings (loss) per common share $ (1.60) $ 0.42
========= =========
4. LONG-TERM DEBT:
Long-term debt as of December 31, 1999 and 2000, consists of the following (in
thousands):
1999 2000
---- ----
Senior Subordinated Notes (a) $150,000 $130,150
Line of credit agreement (b) -- 10,200
Notes payable to principal stockholder (c) 18,600 --
Note payable to General Electric Capital Corporation (d) 2,017 --
Capital lease agreements (e) 20 --
-------- --------
Outstanding debt 170,637 140,350
Less- Current portion 356 10,200
--------
Total long-term debt $170,281 $130,150
======== ========
(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.
(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, 2000, was 9.5%. Interest is
payable monthly with all outstanding principal and interest due at maturity
on May 31, 2001. The Company has $10.2 million outstanding debt on its line
of credit at December 31, 2000. The credit agreement is currently being
renegotiated to be extended for two years and the line is expected to
increase to $35 million.
(c) On December 31, 1999, the Company's principal stockholder contributed the
undivided 50% interest in the Worland Properties and the Company assumed
his loan of $18,600,000. The loan is at the prime interest rate which was
8.5% at December 31, 1999. Interest is payable monthly with all outstanding
principal and interest due at maturity on May 1, 2001. On February 5, 2000,
the Company drew on it's line of credit and paid this loan in full.
(d) In July 1997 the Company borrowed $4,000,000 from General Electric Capital
Corporation to finance the purchase of an airplane. The note accrued
interest at 7.91% to be paid in one hundred nineteen (119) consecutive
monthly installments of principal and interest of $48,341 each and a final
installment of approximately $48,000. It was secured by the airplane. The
balance was paid in full on March 31, 2000.
(e) During 1997, the Company entered into a capital lease agreement to purchase
computer equipment. The agreement required monthly payments of principal
and interest. On September 30, 2000, the balance was paid in full on the
computer equipment.
The Company's line of credit agreement contains certain negative financial
and certain information reporting covenants. The Company was in compliance with
the covenants at December 31, 2000, and expects to be in compliance through the
date the agreement terminates.
The annual maturities of long-term debt subsequent to December 31, 2000,
are as follows (in thousands):
2001 $ 10,200
2002 --
2003 --
2004 --
2005 and thereafter 130,150
-------
Total maturities $140,350
========
At December 31, 2000, the Company had $0.4 million of outstanding letters of
credit which expire during 2001.
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 from
that date 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 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 at during
2000.
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
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%
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 Company applies APB Option No. 25 in accounting for its fixed price
stock options. Accordingly, no current compensation cost for options has been
recognized in the financial statements. Under APB Opinion 25, all compensation
costs recognized in future years will be treated as a contribution to capital by
the principal stockholder with the offset recorded in compensation expense. 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
----
Net Income:
As Reported $37,780
Pro Forma $37,765
Basic Earnings Per Share:
As Reported $ 2.63
Pro Forma $ 2.63
Diluted Earnings Per Share:
As Reported $ 2.62
Pro Forma $ 2.62
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 1998, 1999 and 2000,
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, 1998, 1999 and 2000, was approximately $374,000, $252,000 and $390,000,
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, 2000. 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 have been filed with the Court
which will result 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:
In December 1998 the Company borrowed $10,000,000 from their principal
stockholder. The note incurred interest at 8.5% and was repaid in January 1999.
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 $12,842,000, $7,418,000 and $8,713,000 during the
years ended December 31, 1998, 1999 and 2000, 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, 1999
and 2000, the Company owed approximately $448,000 and $502,000, 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, 1999 and 2000, approximately $875,000 and $131,000,
respectively, from affiliated companies is included in accounts receivable in
the accompanying consolidated balance sheets.
During 1998 approximately $5,692,000 and $1,522,000 of the Company's crude
marketing revenues and purchases, respectively, were transacted with Independent
Trading and Transportation Company ("ITT") an affiliate of the Company. There
were no transactions with ITT in 1999 and 2000.
The Company leases office space under operating leases directly or
indirectly from the principal stockholder. Rents paid associated with these
leases totaled approximately $363,000, $369,000 and $313,000 for the years ended
December 31, 1998, 1999 and 2000, respectively.
During the years ended December 31, 1998, advances were made to the Company
from the principal stockholder. Interest expense related to these advances
totaled approximately $721,000 in 1998.
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.
10. IMPAIRMENT OF LONG-LIVED ASSETS:
The Company accounts for impairment of long-lived assets in accordance with
Financial Accounting Standards Board issued SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
During 1998, 1999 and 2000 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 additional DD&A impairment in 1998 of approximately $7,900,000, no
impairment was required in 1999, and $1,665,000 was recognized additional DD&A
impairment in 2000.
11. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries have guaranteed the Notes discussed
in Note 4. The following is a summary of the financial information of CGI for
1998, 1999 and 2000 (in thousands):
1998 1999 2000
---------- --------- ---------
AS OF DECEMBER 31
Current assets $ 2,493 $ 3,392 $ 5,835
Noncurrent assets 22,263 21,643 19,467
-------- -------- --------
Total assets 24,756 25,035 25,302
======== ======== ========
Current liabilities 13,503 13,188 10,972
Noncurrent liabilities 616 -- --
Stockholder's equity 10,637 11,847 14,330
-------- -------- --------
Total liabilities and stockholder's equity $ 24,756 $ 25,035 $ 25,302
======== ======== ========
FOR THE YEAR ENDED DECEMBER 31
Total revenues $ 20,859 $ 25,037 $ 36,928
Operating costs and expenses 21,703 24,185 34,439
-------- -------- --------
Operating income (loss) (844) 852 2,489
Other expenses (633) (758) (6)
Income tax benefit -- -- --
-------- -------- --------
Net income (loss) $ (1,477) $ 94 $ 2,483
======== ======== ========
At December 31, 1999 and 2000, current liabilities payable to CRI totaled
approximately $9,500,000 and $5,839,000, respectively. For the years ended
December 31, 1998, 1999 and 2000, depreciation, depletion and amortization,
included in operating costs, totaled approximately $2,178,000, $2,063,000 and
$2,107,000, 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, 1997, 1998, 1999 and 2000, 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, 1997 49,378 24,719
Revisions of previous estimates 262 (8,065)
Extensions, discoveries and other additions 2,878 1,011
Production (6,755) (3,981)
Sale of minerals in place (165) (177)
Purchase of minerals in place 9,621 6,423
------- -------
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
======= =======
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, 1998, 1999 and 2000, 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, 1998 47,676 19,411
January 1, 1999 54,901 19,095
January 1, 2000 65,723 34,432
January 1, 2001 55,338 27,590
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.
1998 1999 2000
---- ---- ----
Property acquisition costs:
Proved Purchased $ 85,100 $ 19,745 $ --
Proved Contributed -- 22,461 --
Unproved 3,770 1,274 5,231
-------- -------- --------
Total property acquisition costs $ 88,870 $ 43,480 $ 5,231
Exploration costs 4,801 379 6,152
Development costs 34,144 10,945 36,756
-------- -------- --------
Total $127,815 $ 54,804 $ 48,139
======== ======== ========
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):
1999 2000
---- ----
Proved oil and gas properties $322,452 $351,391
Unproved oil and gas properties 13,733 14,350
-------- --------
Total 336,185 365,741
Less- Accumulated DD&A 126,995 136,115
-------- --------
Net capitalized costs $209,190 $229,625
======== ========
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):
1998 1999 2000
---- ---- ----
Revenues $ 60,162 $ 65,949 $115,478
Production costs 22,611 19,368 29,807
Exploration expenses 7,106 7,750 13,321
DD&A and valuation provision(1) 34,662 16,778 17,454
-------- -------- --------
Income (loss) (4,217) 22,053 54,896
Income tax expense(2) -- -- --
-------- -------- --------
Results of operations from producing
activities (excluding corporate
overhead and interest costs) $ (4,217) $ 22,053 $ 54,896
======== ======== ========
- ------------------------
(1) Includes $7.9 million in 1998 and $1.6 million in 2000 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.
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, 1998, 1999 and 2000, as required by Financial Accounting
Standards Board's Statement of Financial Accounting Standards 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).
1998 1999 2000
---- ---- ----
Future cash inflows $ 328,333 $ 1,069,436 $ 1,403,645
Future production and development costs (157,003) (422,558) (495,953)
Future income tax expenses -- -- --
----------- ----------- -----------
Future net cash flows 171,330 646,878 907,692
10% annual discount for estimated timing of cash flows (63,660) (312,467) (415,893)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 107,670 $ 334,411 $ 497,799
=========== =========== ===========
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 $10.84, $24.38, and $26.80 per BBL at
December 31, 1998, 1999 and 2000, respectively. The year-end weighted average
gas price utilized in the computation of future cash inflows was approximately
$1.64, $1.76, and $9.78 per MCF at December 31, 1998, 1999 and 2000,
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, 1998, 1999 or 2000, 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):
1998 1999 2000
---- ---- ----
Standardized measure of discounted future net cash
flows at the beginning of the year $ 241,625 $ 107,670 $ 334,411
Extensions, discoveries and improved recovery, less
related costs 7,088 5,370 24,923
Revisions of previous quantity estimates (34,228) 128,280 910
Changes in estimated future development costs 2,506 (25,914) 853
Purchases(sales) of minerals in place 11,815 49,984 (1,387)
Net changes in prices and production costs (116,458) 135,803 149,123
Accretion of discount 24,163 10,767 33,441
Sales of oil and gas produced, net of production costs
Development costs incurred during the period 22,960 1,246 19,196
Change in timing of estimated future production, and
other (14,250) (32,214) 16,000
--------- --------- ---------
Standardized measure of discounted future net cash
flows at the end of the year $ 107,670 $ 334,411 $ 491,799
========= ========= =========
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)............ 55 Chairman of the Board of Directors,
President, Chief Executive Officer and
Director
Jack Stark(1)(3)............. 46 Senior Vice President--Exploration and
Director
Jeff Hume(1)(4).............. 50 Senior Vice President--Drilling
Operations and Director
Randy Moeder(1)(2)........... 40 Secretary; President - Continental Gas,
Inc., and Director
Roger Clement(1)(3).......... 56 Senior Vice President, Chief Financial
Officer, Treasurer and Director
(1) Member of the Executive, Compensation and Audit Committees.
(2) Term expires in 2002.
(3) Term expires in 2001.
(4) Term expires in 2003.
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. 1995. Mr. Moeder had been a Director of the Company since November 1990
and 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 Council 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 and Treasurer
and a Director of the Company in March 1989 and was promoted to Senior Vice
President in May 1998. Prior to joining the Company, Mr. Clement was a partner
in the accounting firm of Hunter and Clement in Oklahoma City, Oklahoma. Mr.
Clement is a Certified Public Accountant.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
Securities
Underlying
Other Annual Option All Other
Annual Compensation Compensation Awards Compensation
Name Year Salary($) Bonus($) ($) (# of shares) ($)
- ------------------------ ------------------------------------------------------------------------------
Harold Hamm 2000............$ 500,000 $ -- $ -- # -- $ --
1999........ -- -- -- -- --
1998............ 250,000 -- -- -- 857
Jack Stark 2000 139,456 16,850 -- 32,000 10,648
1999............ 131,616 5,000 -- -- 8,942
1998............ 139,964 -- -- -- 12,831
Jeff Hume 2000 119,226 15,820 -- 32,000 21,711
1999............ 125,456 5,000 -- -- 12,094
1998............ 123,584 -- -- -- 17,226
Roger Clement 2000............ 120,376 15,406 -- 40,000 ,558
1999............ 106,008 5,000 -- -- 3,756
1998............ 98,476 -- -- -- 4,823
Randy Moeder 2000............ 121,335 16,024 -- 25,000 11,817
1999............ 102,313 20,000 -- -- 8,200
1998............ 91,333 -- -- -- 19,566
Represents the value of perquisites and other personal benefits in excess
of 10% of annual salary and bonus. For the year ended December 31, 2000,
the Company paid no other annual compensation to its named Executive
Officers.
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.
Received no compensation during the calendar year 1999.
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.
The following tables list those persons in the previous table who were
granted options to purchase shares of the Company's common stock in 2000. The
following tables provide information regarding the Company's outstanding options
on a converted basis. No stock options were exercised by the persons in the
following tables in 2000.
Option Grants in 2000
Individual Grants
------------------------------------------------
Number of Percent of Total Exercise
Securities Underlying Options Granted Price Expiration Date Grant Date
Name Options Granted to Employees in 2000 ($/share) Present
Value
- ---------------- ---------------------- -------------------- -------------- ------------------- ------------
Jack Stark 32,000 22.22% $11.375 September 30, 2010 3.38-7.44
Jeff Hume 32,000 22.22% 11.375 September 30, 2010 3.38-7.44
Roger Clement 40,000 27.78% 10.500 September 30, 2010 3.38-7.44
Randy Moeder 25,000 17.36% 12.600 September 30, 2010 3.38-7.44
Based upon the estimated fair market value of the Company's common stock
underlying the options on the date the options were granted.
2000 Year-End Option Value
Number of Securities Underlying Value of Unexercised In-the-Money
Unexercised Options at 12/31/00(#) Options at 12/31/00($)
Name Exercisable/Unexercisable Exercisable/Unexercisable
- ------------ ----------------------------------- -----------------------------------
Jack Stark 0/32,000 0/$72,000
Jeff Hume 0/32,000 0/$72,000
Roger Clement 0/40,000 0/$140,000
Randy Moeder 0/25,000 0/$35,000
The value of unexercised in-the-money options at December 31, 2000 is
computed as the product of the stock value at December 31, 2000, assumed to
be $14.00 per share, less the stock option exercise price, and the number
of underlying securities at December 31, 2000.
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 March 28, 2001 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 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)
Director
Executive officer
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Set forth below is a description of transactions entered into between the
Company and certain of its officers, directors, employees and stockholders
during 2000. 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 2000 was $8.7 million and at December 31, 2000, the
Company owed these companies approximately $0.5 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, 2000, the Company owed such persons an aggregate of $0.1 million,
representing their shares of oil and gas production sold by the Company.
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 2000, the Company paid rents associated with these
leases of approximately $313,000. 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, 2000, the aggregate unpaid balance owed to the
Company by such officers and directors was $23,047, 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 under ITEM 8
above.
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 1999 and 2000
Consolidated Statement of Operations for the three years in the period
ended December 31, 2000
Consolidated Statement of Cash Flows for the three years in the period
ended December 31, 2000
Consolidated Statement of Stockholder's Equity for the three years in
the period ended December 31, 2000
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
None.
(a) REPORTS ON FORM 8-K
None
(b) EXHIBITS:
2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc. dated
October 1, 2000. *
3.1 Amended and Restated Certificate of Incorporation of Continental Resources,
Inc.
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)
4.3 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. (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 (2)
10.6 Continental Resources, Inc. 2000 Stock Option Plan. *
10.7 Form of Incentive Stock Option Agreement. *
10.8 Form of Non-Qualified Stock Option Agreement. *
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 incorporated by reference to page 1 of 1999
Annual Report
- -------------------------
* 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
by reference herein.
(2) Incorporated by reference to Annual Report on Form 10-K for the fiscal year
ended December 31, 1999.
(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.
SIGNATURES
Pursuant to the requirements of Section 13 and 15 (d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
March 28, 2001 Continental Resources, Inc.
By HAROLD HAMM
Harold Hamm
Chairman of the Board, President
And Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in capacities and on the dates indicated.
Signatures Title Date
- ---------- ----- ----
HAROLD HAMM
Harold Hamm Chairman of the Board, March 28, 2001
President, Chief Executive
Officer (principal executive
officer) and Director
ROGER V. CLEMENT
Roger V. Clement Senior Vice President and March 28, 2001
Chief Financial Officer
(Principal financial officer
and principal accounting
officer), Treasurer,
and Director
JACK STARTK
Jack Stark Senior Vice President and March 28, 2001
Director
RANDY MOEDER
Randy Moeder Secretary; President of March 28, 2001
Continental Gas, Inc.
and Director
JEFF HUME
Jeff Hume Senior Vice President and March 28, 2001
Director
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.
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
--- ----------- ----------------
2.1 Agreement and Plan of Recapitalization Filed herewith electronically
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., Incorporated herein by reference
as 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
4.1.1 Form of Consolidated Revolving Incorporated herein by reference
Note under the Credit Agreement
4.3 Indenture dated as of July 24, Incorporated herein by reference
1998 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 Incorporated herein by reference
Area 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 Filed herewith electronically
Stock Option Plan.
10.7 Form of Incentive Stock Option Filed herewith electronically
Agreement.
10.8 Form of Non-Qualified Stock Option Filed herewith electronically
Agreement.
12.1 Statement re computation of ratio Filed herewith electronically
of debt to Adjusted EBITDA
12.2 Statement re computation of ratio Filed herewith electronically
of earning to fixed charges
12.3 Statement re computation of ratio Filed herewith electronically
of Adjusted EBITDA to interest
expense
21.0 Subsidiaries of Registrant Incorporated herein by reference