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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, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number: 333-61547
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Oklahoma 73-0767549
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
302 N. Independence, Suite 300, Enid, Oklahoma 73701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (580) 233-8955
Securities registered pursuant to Section 12 (b) of the Act: None
Securities registered pursuant to Section 12 (g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such report(s), 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, 2000, there were 49,041 shares of the registrant's common
stock, par value $1.00 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, 1999
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
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
PART I
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 Mountains and the
Mid-Continent, and to a growing extent, in the Gulf Coast region of Texas and
Louisiana. In addition to its exploration, development and acquisition
activities, the Company owns and operates 750 miles of natural gas pipelines,
five gas gathering systems and two gas processing plants in its operating
areas exclusive of the sale of two systems in January, 2000. 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 49.3 MMBoe at year-end
1999, and increased its annual production from 2.2 MMBoe in 1995 to 4.3 MMBoe
in 1999. As of December 31, 1999, the Company's reserves had a present value
of estimated future net cash flows, discounted at 10% ("PV-10") of $334.4
million calculated in accordance with the Securities and Exchange Commission
(the "Commission" or "SEC") guidelines. Approximately 74% of the Company's
estimated proved reserves were oil and approximately 94% of its total
estimated reserves were classified as proved developed. At December 31, 1999,
the Company had interests in 1,119 producing wells of which it operated 960.
The Company was originally formed in 1967 to explore, develop and produce oil
and gas properties in Oklahoma. The Company acquired interests in the
Williston Basin in 1993 and has since focused on the Rocky Mountains,
expanding its operations within the Williston Basin and acquiring additional
interests in the Big Horn Basin in 1998 and 1999.
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 including the Rocky
Mountain and Mid-Continent Regions while increasing the Company's natural gas
reserves through exploration on the Company's acreage in the Gulf Coast.
Through development activities, the Company seeks to increase production, cash
flow, and develop additional reserves through the use of drilling new wells
(including horizontal wells), expanding high pressure air injection ("HPAI")
technology into the West Medicine Pole Hills Unit and the Cedar Hills Field of
the Williston Basin, workovers, recompletions of existing wells, water floods,
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 the use of the Company's technical expertise in horizontal drilling
and high pressure air injection allow the company to maximize the utilization
of its infrastructure in core operating areas. The Company's exploration
strategy includes expanding the existing reserve base by testing new
reservoirs in existing fields and capitalizing on existing acreage positions
in the Gulf Coast by creating strategic alliances with companies familiar with
the Gulf Coast area for the purpose of increasing the Company's natural gas
reserves with less risk. On an on-going basis, the Company evaluates and
considers divesting of oil and gas properties considered to be non-core to the
Company's reserve growth plans for the purpose of assuring that all company
assets are contributing to the Company's long-term strategic plan.
PROPERTY OVERVIEW
The Company's Mid-Continent activities are conducted primarily in the
Anadarko Basin of western Oklahoma, in southwestern Kansas and in the Texas
Panhandle. At December 31, 1999 the Company's Anadarko Basin properties
represented approximately 99% of the PV-10 attributable to the Company's
estimated proved reserves in the Mid-Continent and approximately 21% of the
Company's total estimated proved reserves. In the Anadarko Basin the Company
owns approximately 62,000 net leasehold acres, has interests in 534 gross (319
net) producing wells and has identified 10 potential drilling locations.
The Company also owns leasehold interests in the Gulf Coast region of Texas
and Louisiana and expects to expand its exploration activities in the Gulf
Coast region during 2000. The Company's Gulf Coast activities are located in
the Jefferson Island Project, Iberia Parish, Louisiana and in the Pebble Beach
Project, Nueces County, Texas. These properties currently provide 10% of the
PV10 attributable to the Company's estimated proved reserves of natural gas
and 4.5% of the Company's total PV10 . From a combined total of 60 square
miles of proprietary 3-D data, the Company has identified 16 development and
11 exploratory locations for drilling. The Company has developed a strategic
alliance with a company familiar with the Gulf Coast region for the purpose of
reducing the Company's risk and expediting the development of the properties
with no substantial capital outlay required by the Company.
The Company's Rocky Mountain activities are concentrated in the Williston
and Big Horn Basins. The Company's operations in the Williston Basin are
focused on the Cedar Hills Field, which the Company believes is, potentially,
one of the largest onshore discoveries in the lower 48 states since 1971. The
Cedar Hills Field represented approximately 33% of the PV10 attributable to
the Company's estimated proved reserves at December 31, 1999. The Company has
assigned no secondary reserves for this field, which the Company believes will
be three barrels of oil of secondary recovery for one barrel of oil of primary
recovery. In the Williston Basin, the Company owns approximately 337,000 net
leasehold acres and has interests in 291 gross (226 net) wells, has identified
40 potential drilling locations and conducts both primary and enhanced
recovery operations. As of December 31, 1999, the Company operated one-half of
the high pressure air injection projects in North America. 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
consists of approximately 75,000 net leasehold acres in which the Company has
interests in 243 gross (217 net) producing wells, of which 230 are company
operated, and represent approximately 29% of the PV10 attributable to the
Company's estimated proved reserves at December 31, 1999. In the Worland Field
the Company has identified 162 potential drilling locations which represent
significant opportunities.
OTHER INFORMATION
The Company's subsidiary, Continental Gas, Inc., was formed as a gas
marketing company in April 1990. Continental Gas, Inc. has developed into a
company specializing in gas marketing, pipeline construction, gas gathering
systems and gas plant operations. Continental Crude Co. was incorporated in
May 1998. Since its incorporation, Continental Crude Co. has had no
operations, has acquired no assets and has incurred no liabilities.
Continental Resources, Inc. is headquartered in Enid, Oklahoma, with
additional primary 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. Continental has demonstrated consistent growth
through a balanced program of development and exploratory drilling and
acquisitions. The Company has increased its proved reserves from 26.6 million
barrels of oil equivalent ("MMBOE") in 1995 to 49.3 million as of December 31,
1999.
SUBSTANTIAL DRILLING INVENTORY. The Company has identified over 228
potential drilling locations based on geological and geophysical evaluations.
As of December 31, 1999 the Company held approximately 501,000 net acres, of
which approximately 55% were classified as undeveloped. Management believes
that its current acreage holdings could support five to ten years of drilling
activities depending upon oil and gas prices.
LONG-LIFE NATURE OF RESERVES. Continental'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.
SUCCESSFUL DRILLING AND ACQUISITION RECORD. The Company has maintained a
successful drilling record. During the five years ended December 31, 1999, the
Company participated in 245 gross (166 net) wells of which 94% were
successfully completed resulting in the addition of 29.1 MMBoe of proved
developed reserves at an average finding cost of $5.81 per Boe excluding
the potential secondary recovery in the Williston Basin. During the same
five year period, the Company acquired 24.2 MMBoe at an average cost of
$3.08 per Boe. Also, including major revisions of 14.7 MMBoe due primarily
to fluctuating prices, the Company added a total of 53.3 MMBoe at an average
cost of $4.57 per Boe during the last five years.
SIGNIFICANT OPERATIONAL CONTROL. Approximately 92.5% of the Company's PV10
at December 31, 1999 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 rapidly evolving technologies of 3-D seismic evaluation,
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 172
horizontal wells in the Rocky Mountains and Mid-Continent. Through the
combination of precision horizontal drilling and HPAI 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 21 years of oil and gas
industry experience. Additionally, the Company's technical staff, which
includes ten petroleum engineers and seven geoscientists, has an average of
over 21 years experience in the industry.
DEVELOPMENT, EXPLOITATION AND EXPLORATION ACTIVITIES
DEVELOPMENT AND EXPLOITATION. The Company's development and exploitation
activities include the drilling of development wells, precision drilling of
horizontal wells, infill drilling, water floods, workovers, recompletions and
HPAI projects. During 2000, the Company projects that development drilling
will represent 85% of the drilling budget. The development drilling will occur
rather evenly with 23% in the Mid Continent and Gulf Coast, 35% in the
Williston Basin, and 42% in the Big Horn Basin. Approximately 89% of the
Company's development drilling inventory, representing an estimated 202 wells,
is located in the Rockies, specifically, the Cedar Hills Field, the Medicine
Pole Hills, Buffalo, South Dakota and West Buffalo Units in the Williston
Basin and the Worland Field in the Big Horn Basin. The Company will continue
to seek opportunities and increase production from its substantial inventory
of 116 workovers and recompletions in the Rockies as well as the 16 located in
the Mid-Continent and Gulf Coast Regions. The unitization process required to
install HPAI in West Medicine Pole Hills Fields will continue with target
dates for initial injection to begin in quarter three of 2000. The following
table sets forth the Company's development inventory as of December 31, 1999.
NUMBER OF DEVELOPMENT PROJECTS
------------------------------
ENHANCED
DRILLING WORKOVERS AND RECOVERY
LOCATIONS RECOMPLETIONS PROJECTS TOTAL
--------- ------------- -------- -----
ROCKY MOUNTAINS:
Williston Basin 40 10 2 52
Big Horn Basin 162 106 1 269
MID-CONTINENT:
Anadarko Basin 10 42 - 52
GULF COAST 16 - - 16
--- --- --- ---
TOTAL 228 158 3 389
=== === === ===
The Company will initiate, on a priority basis, as many projects as
available cash allows. Based on forecasted cash flow, the Company anticipates
initiating 62 development drilling projects, 21 workover projects and one
enhanced recovery project during 2000. The Company expects to expend $31.3 to
$37.5 million in capital expenditures related to these projects in 2000.
EXPLORATION ACTIVITIES. 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 plans to limit
its drilling investment in these higher risk exploratory projects to
approximately 15% of its drilling budget during 2000 given the projected
commodity price environment for the year. The Company will continue to build
exploratory inventory throughout the year for future drilling. Currently the
Company has 19 exploratory wells in inventory.
The following table sets forth information pertaining to the Company's
existing exploration project inventory at December 31, 1999:
NUMBER OF EXPLORATION PROJECTS
DRILLING LOCATION 3-D SEISMIC
----------------- -----------
ROCKY MOUNTAINS:
Williston Basin 4 2
Big Horn Basin 2 3
MID-CONTINENT 2 -
GULF COAST 11 4
--- ---
TOTAL 19 9
=== ===
ACQUISITION ACTIVITIES
The Company seeks to acquire properties that 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.
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 the Company 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 than the effect on other natural gas producers
with which it 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. Sales of crude oil,
condensate and gas liquids by the Company 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. Extensive federal, state and local laws regulating the
discharge of materials into the environment or otherwise relating to the
protection of the environment affect the Company's oil and gas operations.
Numerous governmental departments issue rules and regulations to implement and
enforce such laws, which are often difficult and costly to comply with and
which carry substantial civil and even criminal penalties for failure to
comply. Some laws, rules and regulations relating to protection of the
environment may, in certain circumstances, impose strict liability for
environmental contamination, rendering a person or entity liable for
environmental damages and cleanup costs without regard to negligence or fault
on the part of such person or entity. Other laws, rules and regulations may
restrict the rate of oil and gas production below the rate that would
otherwise exist or even prohibit exploration and production activities in
sensitive areas. In addition, state laws often require various forms of
remedial action to prevent pollution, such as closure of inactive pits and
plugging of abandoned wells. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and consequently affects the
Company's profitability. The Company believes that it is in substantial
compliance with current applicable environmental laws and regulations and that
continued compliance with existing requirements will not have a material
adverse impact on the Company's operations. However, environmental laws and
regulations have been subject to frequent changes over the years, and the
imposition of more stringent requirements could have a material adverse effect
upon the capital expenditures or competitive position of the Company.
The Company currently owns or leases, and has in the past owned or leased,
numerous properties that have been used for the exploration and production of
oil and gas and for other uses associated with the oil and gas industry.
Although the Company followed operating and disposal practices that it
considered appropriate under applicable laws and regulations, hydrocarbons or
other wastes may have been disposed of or released on or under the properties
owned or leased by the Company or on or under other locations where such
wastes were taken for disposal. In addition, the Company owns or leases
properties that have been operated by third parties in the past. The Company
could incur liability under the Comprehensive Environmental Response,
Compensation and Liability Act or comparable state statutes for contamination
caused by wastes it generated or for contamination existing on properties it
owns or leases, even if the contamination was caused by the waste disposal
practices of the prior owners or operators of the properties. In addition, it
is not uncommon for landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the release of
produced fluids or other pollutants into the environment.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and certain other wastes associated with the
exploration, development or production of oil and gas from regulation as
"hazardous waste." A similar exemption is contained in many of the state
counterparts to RCRA. Disposal of such oil and gas exploration, development
and production wastes usually is regulated by state law. Other wastes handled
at exploration and production sites or used in the course of providing well
services may not fall within this exclusion. Moreover, stricter standards for
waste handling and disposal may be imposed on the oil and gas industry in the
future. From time to time legislation has been proposed in Congress that would
revoke or alter the current exclusion of exploration, development and
production wastes from the RCRA definition of "hazardous wastes" thereby
potentially subjecting such wastes to more stringent handling and disposal
requirements. If such legislation were enacted, or if changes to applicable
state regulations required the wastes to be managed as hazardous wastes, it
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general.
The Company's operations are also subject to the Clean Air Act (the "CAA")
and comparable state and local requirements. Amendments to the CAA were
adopted in 1990 and contain provisions that may result in the gradual
imposition of certain pollution control requirements with respect to air
emissions from operations of the Company. The Company may be required to incur
certain capital expenditures in the next several years for air pollution
control equipment in connection with obtaining and maintaining operating
permits and approvals for air emissions. However, the Company believes its
operations will not be materially adversely affected by any such requirements,
and the requirements are not expected to be any more burdensome to the Company
than to other similarly situated companies involved in oil and gas exploration
and production activities or well servicing activities.
The Federal Water Pollution Control Act of 1972 (the "FWPCA") imposes
restrictions and strict controls regarding the discharge of wastes, including
produced waters and other oil and gas wastes, into navigable waters. These
controls have become more stringent over the years, and it is probable that
additional restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters. The FWPCA
provides for civil, criminal and administrative penalties for unauthorized
discharges of oil and other hazardous substances and imposes substantial
potential liability for the costs of removal or remediation. State laws
governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state
waters. In addition, the Environmental Protection Agency has promulgated
regulations that require many oil and gas production sites, as well as other
facilities, to obtain permits to discharge storm water runoff. The Company
believes that compliance with existing requirements under the FWPCA and
comparable state statutes will not have a material adverse effect on the
Company's financial condition or results of operations.
REGULATION OF OIL AND GAS EXPLORATION AND PRODUCTION. Exploration and
production operations of the Company 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
Risk."
EMPLOYEES
As of March 28, 2000, the Company employed 191 people, 69 of which were
administrative personnel, 8 of which were geological personnel, 11 of which
were engineers and the remaining 103 were 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
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 estimate
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 2000 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.
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 make 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. Approximately 6% of the Company's estimated proved reserves at
December 31, 1999 were attributable to undeveloped reserves. Recovery of such
reserves will require additional capital expenditures and successful drilling
operations. There can be no certainty regarding the results of developing
these 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 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 relies 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, 1999, the estimated future net cash flows and PV-10
of $646.9 million and $334.4 million, respectively, attributable to the
Company's proved oil and gas reserves are based on prices in effect at that
date ($24.38 per barrel ("Bbl") of oil and $1.76 per thousand cubic feet
("Mcf") of natural gas), which may be materially different than 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. The addition of the
Worland Field properties may result in additional impairment of the Company's
oil and gas properties to the extent the Company's net book value of such
properties exceeds the projected discounted future net revenues of the related
proved reserves. See "--Write down of Carrying Values." 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, 1999, on a consolidated basis, the Company and the
Subsidiary Guarantors had $170.6 million of indebtedness (including short term
debt and current maturities of long-term indebtedness) compared to the
Company's stockholders' equity of $86.6 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 (as described in the Indenture) 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, 2000 was $12.6 million
exclusive of $12.4 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, CGI. The Company's other subsidiary, CCC was
incorporated in May 1998 and since its incorporation has had no operations,
has acquired no assets and has incurred no liabilities. 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. If the Company enters
into financial instrument contracts for the purpose of hedging prices and the
estimated production volumes are less than the amount covered by these
contracts, the Company would be required to mark-to-market these contracts and
recognize any and all losses within the determination period. 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 affect 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 realized gains on these arrangements,
determined before $.8 million of transportation costs and related expenses,
was $6.3 million for twelve months ended December 31, 1999. The Company's
current policy is to limit its exposure from open positions to $1.0 million at
any one time. At December 31, 1999 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 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, 2000, the principal stockholder, President and Chief Executive
Officer and a Director of the Company, beneficially owned 44,496 shares of
Common Stock representing, in the aggregate, approximately 91% of the
outstanding Common Stock of the Company. As a result, the principal
stockholder 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".
ITEM 2. PROPERTIES
Until 1993, the Company's oil and gas activities were focused in the Mid-
Continent. In 1993 the Company made the strategic move to increase oil
production and reserves by expanding its development and exploration
activities into the Rocky Mountains. The Company currently controls
approximately 412,000 net acres in the Rocky Mountains and is ranked among the
largest oil producers in the Rocky Mountains. Continental's oil production is
characterized by long lived, stable production with high secondary and
enhanced oil recovery potential which perpetuates production and cash flow
from its properties. Approximately 74% of its estimated proved reserves on a
BOE basis at December 31, 1999 were oil. To achieve a more balanced reserve
mix, the Company is focusing on generating an increased inventory of natural
gas drilling opportunities in the Mid-Continent and Gulf Coast. Currently, 70%
of the Company's drilling budget is focused on further expansion and
development of its Rocky Mountain oil fields, and the remaining 30% is focused
on natural gas projects in the Mid-Continent and Gulf Coast. The Company's
Gulf Coast activities are conducted onshore near the Texas and Louisiana
coasts and on the shallow shelf of the Gulf of Mexico. In the Gulf Coast, the
Company holds approximately 6,000 net leasehold acres and has identified 16
potential drilling locations.
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,
1999:
PERCENT
PRESENT OF TOTAL
VALUE OF PRESENT
OIL FUTURE CASH VALUE OF
OIL GAS EQUIVALENT FLOWS(2) FUTURE CASH
AREA (MBBL) (MMCF) (MBOE) (M $) FLOWS(2)
- ---- ------ ------ ---------- ----------- -----------
ROCKY MOUNTAINS:
Williston Basin 20,115 5,264 20,993 $148,149 44.3%
Big Horn Basin 14,021 20,955 17,513 98,400 29.4
MID-CONTINENT:
Anadarko Basin 2,176 39,426 8,747 70,550 21.1
Arkoma Basin 2 2,456 411 2,424 .7
GULF COAST 310 7,660 1,586 14,888 4.5
------ ------ ------ -------- -----
TOTALS 36,624 75,761 49,250 $334,411 100.0%
====== ====== ====== ======== =====
_______________
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, 1999 totaled 38.5 MMBoe and represented 73.7% of the Company's
PV-10. Approximately 94% of these estimated proved reserves are proved
developed. During the twelve months ended December 31, 1999, the average net
daily production was 7,690 Bbls of oil and 3,399 Mcf of natural gas, or 8,256
Boe per day from the Rocky Mountain properties , excluding the Worland
Properties which were contributed by the principal stockholder on December 31,
1999. The addition of the Worland Properties will add approximately 920 Bbls
of oil per day and 2,833 Mcf of natural gas, or 1,392 Boe per day. As of
December 31, 1999, excluding the contributed properties, the Company is
producing approximately 11,857 Boe per day with another 34 Boe per day shut
in due to economics or equipment repairs. The Company's leasehold interests
include 156,649 net developed and 255,231 net undeveloped acres, which
represent 31% and 51% of the Company's total leasehold, respectively. This
leasehold is expected to be developed utilizing 3-D seismic,
precision horizontal drilling and HPAI, where applicable. As of December 31,
1999, the Company's Rocky Mountain properties included an inventory of 202
development and 6 exploratory drilling locations.
WILLISTON BASIN
CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994 and
is still under development. During the twelve months ended December 31, 1999,
the Cedar Hills Field properties produced 4,826 net Boe per day to the Company
interests and represented 33% of the PV-10 attributable to the Company's
estimated proved reserves as of December 31, 1999. 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, 1999, 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 HPAI technology. On four
nearby HPAI projects operated by the Company, HPAI technology has increased oil
recoveries 200% to 300% over primary recovery with ultimate recoveries reaching
up to 40% of the original oil in place. The Company intends to initiate
installation of HPAI secondary recovery on certain of its Cedar Hills Field
properties upon completion of field unitization, which is expected to occur in
2000. The Company believes that HPAI could increase its total recovery from the
Cedar Hills Field by as much as 75 million net barrels. On May 15, 1998, the
Company and Burlington Resources Oil and Gas Company ("Burlington") entered into
a definitive agreement to exchange undivided interests so that effective
December 1, 1998 the Company will own working interests ranging from 90% to
92% in approximately 65,000 gross (59,000 net) leasehold acres in the northern
half of the Cedar Hills Field. As a result of the agreement, the Company will
enhance its ability to unitize all interests in the northern half of the Cedar
Hills Field, which is necessary in order for the Company to initiate the planned
HPAI enhanced recovery operations in the Cedar Hills Field. On August 19, 1998,
the Company instituted a declaratory judgment action against Burlington in the
District Court of Garfield County, Oklahoma (Case No. CJ-98-613-03) alleging
that Burlington provided false and misleading information regarding certain
of Burlington's oil and gas properties to a third party consultant charged
with determining the relative values of oil and gas properties owned by the
Company and Burlington which served as the basis for the exchange of interests.
The Company claimed that the consultant relied on such false and misleading
information in determining the relative fair values of the oil and gas
interests. The Company sought a declaratory judgment determining that it is
excused from further performance under its exchange agreement with Burlington.
Burlington denied the Company's allegations and sought specific performance by
the Company, plus monetary damages of an unspecified amount. A non-jury trial
was held in the case in October 1999. 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 finalize
the Agreements. Even though Continental is appealing the decision of the
Trial Court, it is complying with the Order entered by the Court.
As of December 31, 1999, there were 6 horizontal drilling locations in
inventory, all of which are development well locations.
MEDICINE POLE HILLS, BUFFALO, WEST BUFFALO AND SOUTH BUFFALO UNITS. In 1995,
the Company acquired the following interests in four production units in the
Williston Basin: Medicine Pole Hills (63%); Buffalo (86%); West Buffalo (82%);
and South Buffalo (85%). During the twelve months ended December 31, 1999, these
units produced 1,917 Boe per day, net to the Company's interests, and repre-
sented 5.8 MMBoe or 8.9% of the PV-10 attributable to the Company's estimated
proved reserves as of December 31, 1999. These units are HPAI enhanced recovery
projects that produce from the Red River "B" Formation and are operated by the
Company. These units 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 96 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 and is in
the process of forming the West Medicine Pole Hills Unit. The unit encompasses
an additional 25 square miles of productive Red River B reservoir and represents
first in a two phase expansion of the Medicine Pole Hills Field. Secondary
injection is scheduled to begin in the West Medicine Pole Hills Unit during the
fourth quarter 2000. The Company will own approximately 80 % of the newly formed
unit. During 2000, the Company plans to drill up to 20 horizontal wells as part
of phase two to further expand and develop these units. There are currently 28
development drilling locations identified in these units.
LUSTRE AND MIDFORK FIELDS. In January 1992, the Company acquired the Lustre and
Midfork Fields which, during the twelve months ended December 31, 1999, produced
244 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 pro-
duction rate and is long lived. There are currently 27 wells producing in the
two fields, and no secondary recovery is underway in either field. The Company
currently owns 72,000 net acres in the Lustre and Midfork Fields and plans to
utilize 3-D seismic combined with horizontal drilling to further exploit the
Charles "C" reservoir, and to generate drilling opportunities for deeper
objectives underlying the Lustre and Midfork Fields as well as guide exploration
for new fields on its substantial undeveloped leasehold.
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 Harold
Hamm, 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 75,000 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 45,000
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 over
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 40 of the 60 producing wells located on non-unitized acreage. The Com-
pany's Worland Field properties include interests in 243 producing wells, 230
of which are operated by the Company.
As of December 31, 1999, the estimated net proved reserves attributable to the
Company's Worland Field properties were approximately 17.5 MMBoe, with an
estimated PV-10 of $98.4 million. Approximately 80%, by volume, of these proved
reserves consist of oil, principally in the Phosphoria formation. Oil produced
from the Company's Worland Field properties is low gravity, sour (high sulphur
content) crude, resulting in a lower sales price per barrel than non-sour crude,
and is sold into a Marathon pipeline or is trucked from the lease. Gas produced
from the Worland Field properties is also sour, resulting in a sale price that
is less per Mcf than non-sour natural gas. From the effective date of the
Worland Field Acquisition through September 30, 1998, the average price of crude
oil produced by the Worland Field properties was $5.19 per Bbl less than the
NYMEX price of crude oil. The Company entered into a contract effective 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.
The new contract will expire April 1, 2000 and is currently being renegotiated.
In addition to the proved reserves, the Company has identified 162 development
drilling locations on its Worland Field properties, to further develop and
exploit the undeveloped portion of the Worland Field. Over 100 wells have been
identified for acid fracture stimulation, 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, 1999, the Company's estimated proved reserves in the Mid-Continent
totaled 9.2 MMBoe, representing 21.8% of the Company's PV-10 at such date. At
December 31, 1999 approximately 76% of the Company's estimated proved reserves
in the Mid-Continent were natural gas. Net daily production from these prop-
erties during 1999 averaged 1,113 Bbls of oil and 14,259 Mcf of natural gas, or
3,489 Boe to the Company's interests. The Company's Mid-Continent leasehold
position includes 65,454 net developed and 17,439 net undeveloped acres,
representing 13% and 3% of the Company's total leasehold, respectively, at
December 31, 1999.
As of December 31, 1999, the Company's Mid-Continent properties included an
inventory of ten development drilling locations, all of them in the Anadarko
Basin.
ANADARKO BASIN. The Anadarko Basin properties contained 99% of the Company's
estimated proved reserves for the Mid-Continent and 21.1% of the Company's total
PV-10 at December 31, 1999 and at such date, represented 52% of the Company's
estimated proved reserves of natural gas. During the twelve months ended
December 31, 1999, net daily production from its Anadarko Basin properties
averaged 1,113 Bbls of oil and 13,002 Mcf of natural gas, or 3,280 Boe to the
Company's interest from 534 gross (319 net) producing wells, 422 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 Ford, Oswego, Skinner
and Tonkawa formations, at depths ranging from 6,000 to 12,000 feet. These
properties are currently being re-evaluated for further development drilling and
workover potential.
ARKOMA BASIN. In the Arkoma Basin, the Company was focused on coal bed
methane, where it owned approximately 12,000 acres and had 40 producing wells
from the Hartshorne coal at depths of 2,500 to 3,500 feet. 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. The PV-10 of the
reserves on these properties was approximately $2.4 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. During 1999 the Company also 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, 1999, the Company's
estimated proved reserves in the Gulf Coast totaled 1.6 MMBOE (80% gas)
representing 4.5% of the Company's total PV10 and 10% of the Company's estimated
proved reserves of natural gas. Net daily production from these properties is 56
Bbls of oil and 3200 Mcf of natural gas or 589 Boe to the Company's interest
from 11 wells. The Company's leasehold position includes 1,526 net developed
and 4,515 net undeveloped acres representing .3% and .9% of the Company's total
leasehold respectively. From a combined total of 68 square miles of proprietary
3-D data, 16 development and 11 exploratory locations have been identified for
drilling on these projects to date.
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 65.2 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 13 development and 5 explora-
tory drilling locations to date. The first well drilled off the 3-D data was
successful and a second well is scheduled to be drilled in the first quarter
2000. The Company plans to drill one well per quarter to carefully incorporate
new well data into the 3-D seismic and allow a third party to complete a 5 well
drilling obligation to earn 50% of the project. The third party has drilled two
of the five obligation wells to date and will drill the remaining three during
2000. The Company controls 2,393 gross and 1,406 net acres in the project.
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. Using 20 square miles of proprietary 3-D
seismic, the Company has identified 3 development and 5 exploratory drilling
locations. During 1999 the Company established significant production from the
project and plans to continue drilling and expanding the project through 2000.
The Company has scheduled two wells for the first half of 2000 and the
acquisition of additional proprietary 3-D seismic to expand the project. The
Company owns 7,685 gross and 4,564 net acres in the project.
GULF OF MEXICO. During 1999 the Company elected to expand its drilling
program into the shallow waters of the Gulf of Mexico though a joint venture
arrangement with Challanger Minerals. This is part of the Company's ongoing
strategy to build its opportunity base of high rate of return, natural gas op-
portunities in the Gulf Coast region. The Company will not operate and expects
to participate only in projects with turnkey drilling contracts. Drilling
expenditures in the Gulf of Mexico will be restricted to under $500,000 per
project while the Company builds experience in this new area. As of December 31,
1999, the Company has participated in 2 wells which resulted in one excellent
producer with added behind pipe pay. The Company currently has one well in
inventory and expects it will spend no more than 10% of its drilling budget on
Gulf of Mexico drilling opportunities during 2000.
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
----------------------------
1997 1998 1999
---- ---- ----
NET PRODUCTION DATA:
Oil and condensate (MBBL) 3,518 3,981 3,221
Natural gas (MMCF) 5,789 6,755 6,640
Total (MBOE) 4,483 5,107 4,328
UNIT ECONOMICS
Average sales price per Bbl $ 18.61 $ 12.38 $ 16.93
Average sales price per Mcf 2.21 1.61 1.72
Average equivalent price (per Boe) 17.53 11.78 15.24
Lifting cost (per Boe) 4.63 4.43 4.47
DD&A expense (per Boe) 6.74 6.78 3.61
General and administrative expense
(per Boe) 1.47 1.40 1.31
------- ------- -------
Gross margin $ 4.69 $ (0.83) $ 5.85
======= ======= =======
- --------------
Calculated by dividing oil and gas revenues, as reflected in the
Consolidated Financial Statements, by production volumes on a Boe basis.
Oil and gas revenues reflected in the Consolidated Financial Statements
are recognized as production is sold and may differ from oil and gas
revenues reflected on the Company's production records which reflect oil
and gas revenues by date of production. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
Related to drilling and development activities.
Related to drilling and development activities, net of operating overhead
income.
PRODUCING WELLS
The following table sets forth the number of productive wells in which the
Company owned an interest as of December 31, 1999:
OIL NATURAL GAS
---------------- --------------
GROSS NET GROSS NET
----- --- ----- ---
ROCKY MOUNTAINS:
Williston Basin 291 226 - -
Big Horn Basin 242 216 1 -
MID-CONTINENT:
Anadarko Basin 311 217 223 102
Other - - 40 35
GULF COAST 5 3 6 4
--- --- --- ---
Total 849 662 270 141
=== === === ===
- ---------------
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, 1999:
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS NET GROSS NET
----- --- ----- ---
ROCKY MOUNTAINS:
Williston Basin 167,913 126,460 272,334 210,044
Big Horn Basin 30,189 30,189 45,187 45,187
MID-CONTINENT:
Anadarko Basin 91,775 53,729 14,909 8,697
Other 12,588 11,725 8,786 8,742
GULF COAST 2,339 1,526 8,460 4,515
------- ------- ------- -------
Total 304,804 223,629 349,676 277,185
======= ======= ======= =======
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on its
properties for the periods indicated:
YEAR ENDED DECEMBER 31,
----------------------------------------
1997 1998 1999
------------ ------------ ----- ---
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
DEVELOPMENT WELLS:
Productive 63 42.41 32 22 12 6.90
Non-productive - - - - 1 .16
-- ----- -- ----- -- -----
Total 63 42.41 32 22 13 7.06
== ===== == ===== == =====
EXPLORATORY WELLS:
Productive 15 11.29 5 4.23 2 .74
Non-productive 5 1.98 - - 2 1.25
-- ----- -- ----- -- -----
Total 20 13.27 5 4.23 4 1.99
== ===== == ===== == =====
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 72% of the PV-10 at December 31, 1997, 83% of the PV-10 at
December 31, 1998 and December 31, 1999. The Company prepared the reserve and
present value data on all other properties.
AS OF DECEMBER 31,
------------------------------
1997 1998 1999
---- ---- ----
(DOLLARS IN THOUSANDS)
RESERVE DATA:
Proved developed reserves:
Oil (MBBL) 19,411 19,097 34,432
Natural gas (MMCF) 47,676 54,905 65,723
Total (MBOE) 27,357 28,248 45,386
Proved undeveloped reserves:
Oil (MBBL) 5,308 833 2,192
Natural gas (MMCF) 1,702 314 10,038
Total (MBOE) 5,592 885 3,865
Total proved reserves:
Oil (MBBL) 24,719 19,930 36,624
Natural gas (MMCF) 49,378 55,219 75,761
Total (MBOE) 32,949 29,133 49,251
PV-10 $ 241,625 $ 107,670 $ 334,411
- ----------------
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 and including the effects of hedging
activities. 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,
1997, 1998 and 1999 were $18.06 per Bbl of oil and $2.25 per Mcf of
natural gas, $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, respectively.
Estimated quantities of proved reserves and future net cash flows therefrom
are affected by oil and gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating oil and gas
reserves and their values, including many factors beyond the control of the
producer. The reserve data set forth in this annual report on Form 10-K
represent only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact manner. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates of different engineers, including those
used by the Company, may vary. In addition, estimates of reserves are subject
to revision based upon actual production, results of future development and
exploration activities, prevailing oil and gas prices, operating costs and
other factors, which revisions may be material. Accordingly, reserve estimates
are often different from the quantities of oil and gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon
the accuracy of the assumptions upon which they are based.
In general, the volume of production from oil and gas properties declines as
reserves are depleted. Except to the extent the Company acquires properties
containing proved reserves or conducts successful exploitation and development
activities, the proved reserves of the Company will decline as reserves are
produced. The Company's future oil and gas production is, therefore, highly
dependent upon its level of success in finding or acquiring additional reserves.
GAS GATHERING SYSTEMS
The Company's gas gathering systems are owned by CGI. Natural gas and
casinghead gas are purchased at the wellhead primarily under either market-
sensitive percent-of-proceeds-index contracts or keep-whole gas purchase
contracts or 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 is 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, 1999,
purchases of the Company's natural gas production by GPM Gas Corporation
accounted for 12% of the Company's total gas sales for such period and for the
same period purchases of the Company's oil production by EOTT Energy Corp.
accounted for 65% and Plains Marketing and Transportation accounted for 12%
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 pro-
ceedings 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.
However, the Company is engaged in litigation with Burlington with respect to
the agreement to exchange interests in the Cedar Hills Field. See ITEM 2.
PROPERTIES.
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. As of
March 28, 2000, there were 3 record holders of the Company's common stock. The
Company issued no equity securities during 1999.
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 opera-
tions and other financial data for the years ended December 31, 1995, 1996,
1997, 1998 and 1999, and the balance sheet data as of December 31, 1995, 1996,
1997, 1998 and 1999 have been derived from, and should be reviewed in con-
junction 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, 1998, and 1999 and
the statements of operations for the years ended December 31, 1997, 1998 and
1999 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,
------------------------------------------------
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
(DOLLARS IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales $ 30,576 $ 75,016 $ 78,599 $ 60,162 $ 65,949
Crude oil marketing - - - 232,216 241,630
Gathering, marketing and processing 20,639 25,766 25,021 17,701 21,563
Oil and gas service operations 6,148 6,491 6,405 6,689 6,319
-------- -------- -------- -------- --------
Total revenues 57,363 107,273 110,025 316,768 335,461
Operating costs and expenses:
Production expenses and taxes 7,611 19,338 20,748 22,611 19,368
Exploration expenses 6,184 4,512 6,806 7,106 7,750
Crude oil marketing purchases and
expenses - - - 228,797 236,135
Gathering, marketing and processing 13,223 21,790 22,715 15,602 17,850
Oil and gas service operations 3,680 4,034 3,654 3,664 3,420
Depreciation, depletion and
amortization 9,614 22,876 33,354 38,716 20,385
General and administrative 8,260 9,155 8,990 10,002 8,627
-------- -------- -------- -------- --------
Total operating costs and expenses 48,572 81,705 96,267 326,498 313,535
-------- -------- -------- -------- --------
Operating income (loss) 8,791 25,568 13,758 (9,730) 21,926
Interest income 137 312 241 967 310
Interest expense (2,396) (4,550) (4,804) (12,248) (16,534)
Change in accounting principle 0 0 0 0 (2,048)
Other revenue (expense), net(1) (411) 233 8,061 3,031 266
-------- -------- -------- -------- --------
Income before income taxes 6,121 21,563 17,256 (17,980) 3,920
Federal and state income taxes
(benefit)(2) 2,252 8,238 (8,941) - -
-------- -------- -------- -------- --------
Net income (loss) $ 3,869 $ 13,325 $ 26,197 $(17,980) $ 3,920
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Adjusted EBITDA(3) $ 24,315 $ 53,502 $ 54,721 $ 40,090 $ 48,589
Net cash provided by operations 18,985 41,724 51,477 25,190 23,904
Net cash used in investing (58,022) (50,619) (78,359) (112,050) (13,698)
Net cash provided by (used in)
financing 37,994 10,494 24,863 101,376 (15,602)
Capital expenditures(4) 58,226 50,341 80,937 92,782 55,255
RATIOS:
Adjusted EBITDA to interest expense 10.1x 11.8x 11.4x 3.3x 3.0x
Total debt to Adjusted EBITDA 1.8x 1.0x 1.5x 4.2x 3.5x
Earnings to fixed charges(5) 3.6x 5.7x 4.6x N/A 1.2x
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents $ 1,722 $ 3,320 $ 1,301 $ 15,817 $ 10,421
Total assets 107,825 145,693 188,386 253,739 282,559
Long-term debt, including current
maturities 44,265 54,759 79,632 167,637 170,637
Stockholders' equity 38,752 52,077 78,264 60,284 86,666
See Notes to Selected Consolidated Financial Data.
NOTES TO SELECTED CONSOLIDATED FINANCIAL DATA
(1) In 1997, other income includes $7.5 million resulting from the settlement of
certain litigation matters.
(2) Effective June 1, 1997, the Company elected to be treated as an S-Corpo-
ration 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 exist-
ing tax provision, resulted in a net income tax benefit to the Company
of $8.9 million.
(3) 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 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. 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.
(4) Capital expenditures include costs related to acquisitions of producing
oil and gas properties and includes the contribution of the Worland
properties by the principal stockholder of $22.4 million.
(5) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income before taxes from continuing operations, plus 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.
(6) 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 Consoli-
dated 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 pro-
duces. Although the Company produced less oil and gas in 1999 than in 1998, it
experienced a significant increase in revenues, net income and Adjusted EBITDA
in 1999 compared to 1998 because of higher prevailing oil and gas prices.
Average well head prices as of December 31, 1999, were $24.38 per Bbl of oil
and $1.76 per Mcf of natural gas compared to $10.84 per Bbl of oil and $1.64
per Mcf of natural gas as of December 31, 1998. 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 invest-
ment in oil and gas properties. Under the successful efforts method of account-
ing, 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
oil and gas properties 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, 1999:
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1998 1999
---- ---- ----
(Dollars in Thousands, Except Average Price Data)
Revenues $ 110,025 $ 316,768 $ 335,461
Operating expenses 96,267 326,498 313,535
Non-Operating income (expense) 3,498 (8,250) (15,958)
Change in accounting principle (2,048)
Net income after tax 26,197 (17,980) 3,920
Adjusted EBITDA 54,721 40,090 48,589
Production Volumes:
Oil and condensate (MBBL) 3,518 3,981 3,221
Natural gas (MMCF) 5,789 6,755 6,640
Oil equivalents (MBOE) 4,483 5,107 4,328
Average Prices:
Oil and condensate (per Bbl) $ 18.61 $ 12.52 $ 16.93
Natural gas (per Mcf) 2.21 1.61 1.72
Oil equivalents (per Boe) 17.53 11.78 15.24
- ---------------
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. 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, 1997,
1998 and 1999, were $17.53, $11.88 and $15.31, respectively.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
REVENUES
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 $.4 million, or 6%, to $6.3
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 & TAXES
Production expense and taxes were $19.4 million for 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, ex-
cept 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
Expense for the purchases of 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. This 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 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 payroll and benefit 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 401K plan.
Permanent savings due to staff reductions was 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 is
attributable primarily to the 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 Com-
pany's interest costs on the Notes, or an increase in 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
Net income before income taxes and change in accounting principle for the year
ended December 31, 1999 was a gain of $5.9 million, an increase in net income
before taxes 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 after taxes was $3.9 million, including a charge result-
ing 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 account-
ing principle of $2,048,000.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
OIL AND GAS SALES
Oil and gas sales revenue for 1998 decreased $18.4 million, or 23.5%, to $60.2
million from $78.6 million in 1997. Oil prices decreased from an average of
$18.61/Bbl in 1997 to $12.38/Bbl in 1998 which resulted in a $21.9 million re-
duction in revenues. The effects of the price reduction was partially offset by
a 463 Mbbl increase in oil production in 1998 compared to 1997. The increased
production was realized from the acquisition of the Worland Field properties
which contributed 234 MBBL of oil production after the June 1, 1998 acquisition
date and from the further development of the Cedar Hills and Midfork/Lustre
fields through drilling which contributed an additional 384 MBBL of oil pro-
duction. Company production volumes decreased by 20 MBBL with the fourth
quarter sale of its Illinois properties and by 120 MBbls due to the natural
decline in production rates in the Company's existing HPAI units. The net
increase in production resulted in additional revenues of $5.7 million for the
period. Gas revenues for 1998 increased by $1.6 million due to the sale of an
additional 966 MMCF of production. The revenue due to the increase in pro-
duction was partially offset by a $3.5 million reduction in revenues due to
lower gas sales prices realized during the year when compared to 1997. The
Company's average gas sales prices decreased from $2.21 per Mcf in 1997 to
$1.61 per Mcf in 1998 on a company average.
CRUDE OIL MARKETING
The Company began marketing crude oil purchased from third parties in July,
1998. The Company recognized revenues on crude oil purchased for resale of
$232.2 million for 1998.
GATHERING, MARKETING AND PROCESSING
As a result of the elimination of gas sales associated with purchases of gas
to be sold for marketing purposes unrelated to gas processing, 1998 gathering,
marketing and processing revenues decreased $7.3 million, or 29%, to $17.7 mil-
lion compared to $25.0 million for 1997.
OIL AND GAS SERVICE OPERATIONS
Oil and gas service operations revenues increased $.3 million, or 4.4%, to
$6.7 in 1998 from $6.4 million in 1997. Revenues in 1998 increased due to an
increase in administrative income compared to the 1997 period because of
increased overhead reimbursement associated with the increased maintenance
activities performed on company operated properties during 1998.
COSTS AND EXPENSES
PRODUCTION EXPENSE AND TAXES
Production expense and taxes were $22.6 million for the twelve months ended
December 31, 1998, a $1.9 million, or 9% increase, over the 1997 expenses of
$20.7 million, primarily as a result of the Worland Field Acquisition. For the
year, the Company has incurred $1.7 million in operating costs on the Worland
Field properties. The Company also incurred $0.7 million in non-recurring
charges to repair several air injection and producing wells in the High Pres-
sure Air Injection Units.
EXPLORATION EXPENSE
Exploration expenses increased $0.3 million, or 4%, to $7.1 million in 1998
from $6.8 million in 1997. The Company recognized expense on the expiration of
$2.0 million in leasehold associated with non-core areas which was $0.8 million
greater than the leasehold expiration expense of $1.2 million recognized in
1997. During 1998 leases on 40,000 net acres in which the Company has an invest-
ment of $2.2 million will expire. The Company has not determined if these
leases will be drilled, renewed, or allowed to expire.
CRUDE OIL MARKETING
The Company began marketing crude oil purchased from third parties during
1998. For the year ended December 31, 1998, the Company recognized expense for
the purchases of crude oil purchased for resale of $228.1 million and marketing
expenses of $0.7 million.
GATHERING, MARKETING AND PROCESSING
Gathering, Marketing and Processing expense for 1998 was $15.6 million, a $7.1
million, or 31%, decrease from the $22.7 million incurred in 1997. This de-
crease is mainly due to the elimination of purchases of third party gas not
used for gas plant supply, but sold as part of the Company's gas marketing
activities which have been reduced to minimal volumes.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
For the year ended December 31, 1998, DD&A Expenses were $38.7 million, a $5.4
million, or 16%, increase over the 1997 expense of $33.4 million. Lease and Well
depletion and depreciation increased $4.0 million mainly due to the $7.9 million
write-down associated with FASB 121 in 1998 compared to the $5.0 million write-
down recognized in 1997. In 1998, the FASB 121 write-down contributed $1.55 per
Boe , or 23%, of the total DD&A expense of $6.78 per Boe produced. The FASB 121
write-down in 1997 contributed $1.12 per Boe, or 17%, to the $6.74 per Boe of
DD&A expense. The 1998 write-down included the impairment of $3.6 million on
ten step out properties on the fringes of the Cedar Hills Field in North Dakota.
The Company has excluded these wells from the exchange agreement with Burlington
and does not expect them to be included in future unitization plans. Because of
these factors, the reserves associated with these wells are low and provide
minimal future cash flow. The 1998 DD&A expense also included $0.6 million of
amortization expense associated with the capitalized costs related to the
Company's $150 million debt offering.
GENERAL AND ADMINISTRATIVE (G&A)
G&A expense for 1998 was $10.0 million, net of overhead reimbursement of $2.9
million, an increase of $0.5 million, or 9%, to $7.1 million from $9.0 million,
net of overhead reimbursement of $2.4 million, or $6.6 million for 1997. The
increase is attributable to increased employment and benefits costs of $1.5
million which was partially offset by a reduction of $0.9 million in consulting
and contract services expenses.
INTEREST INCOME
Interest income for 1998 was $1.0 million compared to $0.2 million for 1997, a
$0.8 million, or 300% increase. The increase in the 1998 period is attributable
primarily to higher levels of cash invested during 1998, which was partially
generated by the sale of the Illinois properties.
INTEREST EXPENSE
Interest expense for 1998 was $12.2 million, an increase of $7.4 million, or
155%, from $4.8 million in 1997. The increases in the 1998 expense are
attributable primarily to higher levels of indebtedness outstanding during 1998
with the acquisition of the Worland Field Properties and continued drilling
associated with the development of the Cedar Hills Field.
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 Com-
pany's interest costs on the Notes, or an increase in interest expense of ap-
proximately $0.4 million for the term of the Notes.
OTHER INCOME
Other income decreased $5.0 million, or 62%, to $3.0 million for the year
ended December 31, 1998 from $8.1 million for 1997. The 1997 other income
included $7.5 million from the settlement of certain litigation issues. This
decrease in other income from 1997 was partially offset by 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
Net income before income taxes for the year ended December 31, 1998 was a loss
of $18.0 million, a decrease in net income before taxes of $35.2 million, or
204%, from $17.3 million of net income before taxes for 1997. This decrease
was due to the reduced revenues caused by lower oil and gas sales prices,
increased interest expense caused by higher levels of indebtedness and the
recognition of certain litigation settlements in 1997. These reductions to
income were partially offset by the income generated by the crude oil marketing
activities begun in 1998 and the gain on the sale of the Illinois properties
which took place in 1998.
NET INCOME
The 1998 Net Income after taxes was a loss of $18.0 million, a decrease in net
income of $44.2 million, or 169%, compared to 1997. In addition to the items
related to income before income taxes previously discussed, net income for 1997
also included $8.9 million in income tax benefits recognized in connection with
the Company's conversion to an S-corporation effective June 1, 1997.
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 interest payments.
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $23.9 million for 1999 a 5%
decrease from the $25.2 million in 1998. Cash decreased to $10.4 million at
December 31, 1999, from $15.8 million at year-end 1998 primarily due to repay-
ment in January 1999 of the short term note to the principal stockholder out-
standing at December 31, 1999.
RESERVES AND ADDED FINDING COSTS
During 1998 and 1999, the Company spent $85.2 and $32.5, respectively on
acquisitions, exploration, exploitation and development of oil and gas prop-
erties. The 1998 amount includes the acquisition of the Worland Field prop-
erties, net of the sale of an undivided 50% interest of the Worland properties
to the principal stockholder for $42.6 million. The 1999 amount includes the
assumption of the loan of $18.6 million from the principal stockholder. Total
estimated proved reserves of natural gas increased from 55.2 Bcf at
year-end 1998 to 75.8 Bcf at December 31, 1999, and estimated total proved oil
reserves increased from 19.9 MMBbls at year-end 1998 to 36.6 MMBbls at December
31, 1999. 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.
FINANCING
Long-term debt at December 31, 1998 and December 31, 1999 was $157.3 million
and $170.2 million, respectively. The $12.9 million, or 8% increase was mainly
due to the assumption of the principal stockholder's note of $18.6 million re-
lated to the principal stockholder's contribution of his interest in the Worland
Field properties offset by a reduction in the Company's bank debt of $4.0
million and other debt by $1.7 million.
CREDIT FACILITY
Long-term debt outstanding at December 31, 1998 included $4.0 million of
revolving debt under the Credit Facility. The Company has no outstanding debt
balance under the Credit Facility at December 31, 1999. The effective rate of
interest under the Credit Facility was 7.75% at December 31, 1998 and was 8.5%
at December 31, 1999. This Credit Facility has available borrowings of $25
million and bears interest at either Bank One prime adjusted LIBOR, which
includes the LIBOR rate as determined on a daily basis by the bank adjusted
for a facility fee % and non-use fee %. 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 14, 2001. In
January 2000, the Company utilized proceeds from the Credit Facility to pay
off the outstanding balance of the principal stockholder's note assumed in
1999. As of March 28, 2000 the Company has borrowed $12.6 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. On February 29, 2000,
the Company purchased $3,000,000 of the Notes for $2,880,000 plus accrued
interest and commissions and on March 10, 2000, the Company purchased
$1,000,000 of the Notes for $950,000 plus accrued interest and no commission.
CAPITAL EXPENDITURES
In 1999, the Company incurred $12.9 million of capital expenditures, exclusive
of acquisitions. The Company will initiate, on a priority basis, as many pro-
jects as cash flow allows. It is anticipated that approximately 84 projects
will be initiated in 2000 for projected capital expenditures of $31.3 million.
The Company expects to fund the 2000 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 bal-
ance 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
The Company has not made any dividend distributions to its stockholders.
However, the Company may be required to dividend the stockholders an amount
sufficient to cover the taxes on the taxable income passed through to the
stockholders of record.
HEDGING
From time to time, the Company 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 instru-
ments, as defined in SFAS No. 119 "Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments" and does not use them for
trading purposes. 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 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 im-
balance 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 pre-tax gains of
approximately $674,000, $2,614,000 and $151,400 in 1997, 1998 and 1999
respectively. Total amounts of oil and gas reserves associated with these
dispositions during 1997 and 1998 were 471 Bbls of oil and 2,463 Mmcf of
natural gas. The reserves associated with the few properties sold in 1999
were insignificant. August 19, 1998, the Company instituted a declaratory
judgment action against Burlington in the District Court of Garfield County,
Oklahoma (Case No. CJ-98-613-03) alleging that Burlington provided false
and misleading information regarding certain of Burlington's oil and gas
properties to a third party consultant charged with determining the relative
values of oil and gas properties owned by the Company and Burlington which
served as the basis for the exchange of interests. The Company claimed that
the consultant relied on such false and misleading information in determining
the relative fair values of the oil and gas interests. The Company sought a
declaratory judgment determining that it is excused from further performance
under its exchange agreement with Burlington. Burlington denied the Company's
allegations and sought specific performance by the Company, plus monetary
damages of an unspecified amount. A non-jury trial was held in the case
in October, 1999. On December 22, 1999, the Court issued an Order requiring the
parties to proceed in accordance with terms of the Trade Agreement and in-
structing them to use their best efforts to finalize the Agreements. Even though
Continental is appealing the decision of the Trial Court, it is complying with
the Order entered by the Court.
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.
During the third quarter of 1999, the Company entered into forward fixed price
sales contracts in accordance with its hedging policy, to mitigate its exposure
to the price volatility associated with its crude oil production. The monthly
contracts total 80,000 barrels through February 2000 at $20.43 per barrel and an
additional 320,000 barrels from May to December 2000 at $22.04 per barrel. At
December 31, 1999, the Company had open hedging contracts totaling approximately
400,000 barrels with unrealized deferred losses of approximately $61,668. The
Company accounts for changes in the market value of its hedging instruments as
deferred gains or losses until the production month of the hedged transaction,
at which time the realized gain or loss is recognized in the results of opera-
tions.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX OF FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 1998 and 1999
Consolidated Statements of Operations for the Years Ended December 31, 1997,
1998 and 1999
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1997, 1998 and 1999
Consolidated Statements of Cash Flows for the Years Ended December 31, 1997,
1998 and 1999
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,
1998 and 1999 and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. 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, 1998 and 1999
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
February 18, 2000
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share information)
ASSETS
December 31,
--------------------
1998 1999
---- ----
CURRENT ASSETS:
Cash $ 15,817 $ 10,421
Accounts receivable-
Oil and gas sales 7,255 11,508
Joint interest and other, net 7,734 8,517
Inventories 4,627 4,112
Prepaid expenses 168 1,690
---------- ---------
Total current assets 35,601 36,248
---------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)-
Producing properties 241,358 293,467
Nonproducing leaseholds 47,583 43,083
Gas gathering and processing facilities 24,709 25,740
Service properties, equipment and other 15,989 14,884
---------- ---------
Total property and equipment 329,639 377,174
Less--Accumulated depreciation, depletion
and amortization (121,061) (138,872)
---------- ---------
Net property and equipment 208,578 238,302
---------- ---------
OTHER ASSETS:
Debt issuance costs 9,023 7,847
Other assets 537 162
---------- ---------
Total other assets 9,560 8,009
---------- ---------
Total assets $ 253,739 $ 282,559
========== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 10,532 $ 8,448
Current portion of long-term debt 337 356
Revenues and royalties payable 5,855 6,865
Accrued liabilities and other 9,224 9,776
Short-term debt - stockholder 10,000 0
---------- ---------
Total current liabilities 35,948 25,445
---------- ---------
LONG-TERM DEBT, net of current portion 157,302 170,281
OTHER NONCURRENT LIABILITIES 205 167
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS' EQUITY:
Common stock, $1 par value, 75,000 shares
authorized, 49,041 shares issued and
outstanding at December 31, 1998 and 1999 49 49
Additional paid-in capital 2,721 25,182
Retained earnings 57,514 61,435
---------- ---------
Total stockholders' equity 60,284 86,666
---------- ---------
Total liabilities and
stockholders' equity $ 253,739 $ 282,559
========== =========
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,
---------------------------------------
1997 1998 1999
---- ---- ----
REVENUES:
Oil and gas sales $ 78,599 $ 60,162 $ 65,949
Crude oil marketing - 232,216 241,630
Gas gathering, marketing and
processing 25,021 17,701 21,563
Oil and gas service operations 6,405 6,689 6,319
--------- --------- ---------
Total revenues 110,025 316,768 335,461
--------- --------- ---------
OPERATING COSTS AND EXPENSES:
Production expenses 16,825 19,028 14,796
Production taxes 3,923 3,583 4,572
Exploration expenses 6,806 7,106 7,750
Crude oil marketing purchases
and expenses - 228,797 236,135
Gas gathering, marketing and
processing 22,715 15,602 17,850
Oil and gas service operation 3,654 3,664 3,420
Depreciation, depletion and
amortization 33,354 38,716 20,385
General and administrative 8,990 10,002 8,627
--------- --------- ---------
Total operating costs and expenses 96,267 326,498 313,535
OPERATING INCOME (LOSS) 13,758 (9,730) 21,926
--------- --------- ---------
OTHER INCOME AND EXPENSES:
Interest income 241 967 310
Interest expense (4,804) (12,248) (16,534)
Other income, net 8,061 3,031 266
--------- --------- ---------
Total other income and (expenses) 3,498 (8,250) (15,958)
--------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 17,256 (17,980) 5,968
CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE - - (2,048)
INCOME TAX BENEFIT 8,941 - -
--------- --------- ---------
NET INCOME (LOSS) $ 26,197 $ (17,980) $ 3,920
========= ========= =========
EARNING (LOSS) PER COMMON SHARE $ 534.18 $ (366.63) $ 79.94
========= ========= =========
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, 1997, 1998 AND 1999
(in thousands)
Total
Additional Stock-
Common Paid-In Treasury Retained holders
Stock Capital Stock Earnings Equity
------- ------- ------- ------- -------
Balance, December 31, 1996 $ 49 $ 2,731 $ (10) $49,298 $52,068
Net income - - - 26,197 26,197
------- ------- ------- ------- -------
Balance, December 31, 1997 49 2,731 (10) 75,495 78,265
Retirement of treasury stock (10) 10 - -
Net loss - - - (17,980) (17,980)
------- ------- ------- ------- -------
Balance, December 31, 1998 49 2,721 0 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 $ 49 $25,182 $ 0 $61,435 $86,666
======= ======= ======= ======= =======
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, 1997, 1998 AND 1999
(in thousands)
1997 1998 1999
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 26,197 $ (17,980) $ 3,920
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities-
Depreciation, depletion and
amortization 33,354 38,716 20,385
Gain on sale of assets (674) (2,539) (151)
Dry hole costs and impairment of
undeveloped leases 1,468 2,880 5,978
Deferred income taxes (11,979) - -
Other noncurrent assets and
liabilities - (3) 338
Changes in current assets and
liabilities-
Decrease(increase) in accounts
receivable (3,971) 9,645 (5,037)
Decrease(increase) in inventories 8 (1,078) 515
Decrease(increase) in prepaid
expenses 3,454 215 (1,522)
Increase(decrease) in accounts
payable 1,979 (9,082) (2,084)
Increase(decrease) in revenues and
royalties payable 689 (1,642) 1,010
Increase(decrease) in accrued
liabilities and other 952 6,059 552
---------- --------- ----------
Net cash provided by operating
activities 51,477 25,191 23,904
---------- --------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (63,702) (42,715) (12,233)
Gas gathering and processing facilities
and service properties, equipment
and other (16,760) (7,517) (266)
Purchase of producing properties (475) (85,100) (1,695)
Cash received on note receivable -
stockholder - 19,582 -
Proceeds from sale of assets 2,177 3,641 496
Advances from (to) affiliates 401 58 -
---------- --------- ----------
Net cash used in investing
activities (78,359) (112,051) (13,698)
---------- --------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 33,493 266,515 4,600
Repayment of line of credit and other (30,570) (165,539) (10,202)
Debt issuance costs - (9,600) -
Proceeds from short-term debt due to
stockholder 21,950 10,000 -
Repayment of short-term debt due to
stockholder - - (10,000)
Purchase of treasury stock (10) - -
---------- --------- ----------
Net cash provided by financing
activities 24,863 101,376 (15,602)
---------- --------- ----------
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(in thousands)
1997 1998 1999
---- ---- ----
NET INCREASE (DECREASE) IN CASH $ (2,019) $ 14,516 $ (5,396)
CASH, beginning of year 3,320 1,301 15,817
---------- --------- ----------
CASH, end of year $ 1,301 $ 15,817 $ 10,421
========== ========= ==========
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 4,302 $ 12,248 $ 16,583
Income taxes paid $ 300 $ - $ -
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 1,120 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.
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, 1998 and 1999, are
recorded net of an allowance for doubtful accounts of approximately $400,000
and $387,000, 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, 1998 and 1999, tubular goods and production equipment totaled
approximately $3,913,000 and $3,620,000, respectively and crude oil in tanks
totaled approximately $714,000 and $491,000, 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. The
effect of eliminating the deferred tax assets and liabilities were recognized
in the results of operations for the year ended December 31, 1997, the year of
adoption.
Earnings per Common Share
Earnings per common share includes no dilution and is computed by dividing
income available to common stockholders by the weighted-average number of
shares outstanding for the period. There are no common stock equivalents or
securities outstanding which would result in material dilution. The weighted-
average number of shares used to compute earnings per common share was 49,042
in 1997, 49,041 in 1998 and 49,041 in 1999.
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, 1998 and 1999, 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,
1997, 1998 and 1999.
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, 1999, the market value of the
Company's open energy trading contracts resulted in an unrealized gain of $1.5
million which is recorded in crude oil marketing revenues in the accompanying
consolidated statement of operations and prepaid expenses in the accompanying
consolidated balance sheet.
Crude Oil Hedging
During the third quarter of 1999, the Company entered into forward fixed
price sales contracts in accordance with its hedging policy, to mitigate its
exposure to the price volatility associated with its crude oil production.
The monthly contracts total 80,000 barrels through February 2000 at $20.43 per
barrel and an additional 320,000 barrels from May to December 2000 at $22.04
per barrel. At December 31, 1999, the Company had open hedging contracts
totaling approximately 400,000 barrels with unrealized deferred losses of
approximately $61,668. The Company accounts for changes in the market value of
its hedging instruments as deferred gains or losses until the production month
of the hedged transaction, at which time the realized gain or loss is
recognized in the results of operations.
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, 1998 and 1999 were not material.
Significant Customer
During 1997, 1998 and 1999, approximately 46.6%, 24.2% and 25.2%,
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.
Presentation
Certain information has been reclassified to conform to the 1999
presentation.
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 No. 133." Adoption of SFAS No. 133
is now required for financial statements for periods beginning after June 15,
2000. The Company will adopt this new standard effective January 1, 2001.
Management has not yet determined whether the adoption of this new standard
will have a material impact on its consolidated 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 years
ended December 31, 1997 and 1998 as if these acquisitions had been consummated
as of January 1, 1997. These pro forma results are not necessarily indicative
of future results.
(in thousands, except per share data) Pro Forma (Unaudited)
---------------------
1997 1998
---- ----
Revenues $ 120,151 $ 318,895
========= =========
Net income (loss) $ 19,618 $ (21,184)
========= =========
Earnings (loss) available to common stock $ 19,618 $ (21,184)
========= =========
Earnings (loss) per common share $ 400.03 $(431.97)
========= =========
On December 31, 1999 the Company's principal stockholder contributed the
undivided 50% interest in the Worland Properties 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, 1997, 1998, and 1999 as if the contribution had been
consummated as of January 1, 1997. These pro forma results are not
necessarily indicative of future results.
(In thousands, except per share data) Pro Forma (Unaudited)
---------------------
1997 1998 1999
---- ---- ----
Revenues $130,277 $321,023 $341,796
======== ======== ========
Net income (loss) $ 21,837 $(22,931) $ 6,052
======== ======== ========
Earnings (loss) available to
common stock $ 21,837 $(22,931) $ 6,052
======== ======== ========
Earnings (loss) per common share $ 445.28 $ 431.97 $ 123.41
======== ======== ========
4. LONG-TERM DEBT:
Long-term debt as of December 31, 1998 and 1999, consists of the following
(in thousands):
1998 1999
---- ----
Senior Subordinated Notes (a) $150,000 $150,000
Line of credit agreement (b) 4,000 -
Notes payable to principal stockholder (c) - 18,600
Note payable to General Electric Capital
Corporation (d) 3,582 2,017
Capital lease agreements (e) 57 20
-------- --------
Outstanding debt 157,639 170,637
Less-Current portion 337 356
-------- --------
Total long-term debt $157,302 $170,281
======== ========
(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 ef-
fective 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.
(b) In August, 1998, the Company amended its previous line of credit with a
bank to allow borrowings up to $75.0 million with semi-annual redetermi-
nation dates as of November 1 and May 1. Effective November 1, 1998, the
borrowing base was lowered to $25.0 million. 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 Bank One 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 or sixty 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. At December
31, 1998 interest was based on prime (7.75%). The Bank One prime interest
rate at December 31, 1999, was 8.5%. Interest is payable monthly with all
outstanding principal and interest due at maturity on May 14, 2001. The
Company has no outstanding debt on its line of credit at December 31, 1999.
(c) During 1997, CRI and CGI entered into various notes with the principal
stockholder of the Company. These notes bear interest at 8.25% with inter-
est payments due monthly or quarterly for twenty-four to thirty-six months.
On December 31, 1997, the notes between CRI and the principal stockholder
were combined into one note totaling $21,750,000 bearing interest at 8.25%
with interest payments due on a quarterly basis for twenty-four months with
the balance to be paid in full by December 31, 2002. The outstanding bal-
ance of notes was paid in full in connection with the sale of the undivided
50% interest in the Worland Properties to the principal stockholder in
1998, as discussed above. 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. However, 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 accrues
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 is secured by the airplane. As of
December 31, 1999 the outstanding principal balance was $2,016,819.
(e) During 1997, the Company entered into two capital lease agreements to
purchase a copier and computer equipment. The agreements require monthly
payments of principal and interest totaling $559.13 and $2,080.67 for
forty-two and sixty months, respectively.
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, 1999 and expects to be in compliance through the
date the agreement terminates.
The annual maturities of long-term debt subsequent to December 31, 1999, are
as follows (in thousands):
2000 $ 356
2001 18,958
2002 387
2003 419
2004 and thereafter 150,517
--------
Total maturities $170,637
========
At December 31, 1999, the Company had $853,750 of outstanding letters of credit
which expire during 2000.
5. INCOME TAXES:
The Company follows Statement of Financial Accounting Standards ("SFAS") No.
109, "Accounting for Income Taxes." As mentioned in Note 2, effective June 1,
1997, the Company converted to 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. Accordingly,
the deferred income tax assets and liabilities at May 31, 1997, were eliminated
through recording a provision for income tax benefit. The components of income
tax expense (benefit) for the year ended December 31, 1997 is as follows (in
thousands):
1997
----
Current $ 3,038
Deferred (11,979)
--------
Income tax expense (benefit) $ (8,941)
========
The provision for income taxes differs from an amount computed at the
statutory rates at December 31, 1997 as follows (in thousands):
1997
----
Federal income tax at statutory rates $ 6,040
State income taxes 518
Nondeductible expenses 30
Conversion to S-Corporation (15,529)
----------
Income tax benefit $ (8,941)
==========
6. 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 1997,
1998 and 1999, contributions to the plan were 4%, 5% and 5%,
respectively, 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, 1997, 1998 and 1999, was approximately $242,000, $374,000 and
$252,000, 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, respec-
tively, 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 assess-
ments are anticipated for periods prior to December 31, 1999. 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. The Company has been successful in
Federal courts in its lawsuit against a gas purchaser arising from
tortious interference with business relations. A judgment was awarded
for actual and punitive damages under the Federal lawsuit totaling
$30,269,000 plus accrued interest. In May 1996, this decision was
remanded by the U.S. Supreme Court back to the Tenth Circuit Court of
Appeals for further consideration. During 1997, this lawsuit was settled
with an aggregate judgment of $9,500,000 of which the Company's share
was approximately $7,500,000. This amount is included in other income
in the accompanying consolidated statement of operations for the year
ended December 31, 1997.
On May 15, 1998, the Company and an unrelated third party entered into a
definitive agreement to exchange undivided interests in approximately
65,000 gross (59,000 net) leasehold acres in the northern half of the
Cedar Hills Field. On August 19, 1998, the Company instituted a declara-
tory judgment action against the unrelated third party in the Oklahoma
District Court. The Company sought a declaratory judgment determining
that it is excused from further performance under its exchange agreement
with the third party. The third party denied the Company's allegations
and sought specific performance by the Company, plus monetary damages
of an unspecified amount. A non-jury trial was held in the case in
October, 1999. On December 22, 1999, the Court issued an Order re-
quiring the parties to proceed in accordance with terms of the Trade
Agreement and instructing them to use their best efforts to finalize
the Agreements. Even though Continental is appealing the decision of
the Trial Court, it is complying with the Order entered by the Court.
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 environ-
mental contamination. The Company is not aware of any material potential
environmental issues or claims.
7. RELATED PARTY TRANSACTIONS:
In December 1998, the Company borrowed $10,000,000 from their principal
stockholder. The note bears interest at 8.5% and is payable on demand.
The note 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 $11,852,000, $12,842,000 and $7,418,000
during the years ended December 31, 1997, 1998 and 1999, respectively.
These services are provided at amounts which management believes approxi-
mate the costs which would have been paid to an unrelated party for the
same services. At December 31, 1998 and 1999, the Company owed approxi-
mately $876,000 and $448,000, 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, 1998 and 1999, approximately $1,371,000 and $875,000,
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.
CRI and CGI advance certain amounts to affiliates primarily for operating
expenditures. The advances outstanding to affiliates at December 31, 1998,
totaled approximately $700 and none were outstanding at December 31, 1999.
Interest income earned during the years ended December 31, 1997, 1998 and
1999, was approximately $33,000, $296,000 and $0, respectively, on advances
to affiliates.
The Company leases office space under operating leases directly or in-
directly from the principal stockholder. Rents paid associated with
these leases totaled approximately $294,000, $363,000 and $369,000 for the
years ended December 31, 1997, 1998 and 1999, 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.
8. 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 1997, 1998 and 1999 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 determined appropriate an additional charge
was added to depreciation, depletion and amortization ("DD&A") expense.
The Company recognized additional DD&A impairment in 1997 and 1998 of
approximately $5,000,000 and $7,900,000, respectively. No impairment was
required in 1999.
9. 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
1997, 1998 and 1999 (in thousands):
1997 1998 1999
---- ---- ----
AS OF DECEMBER 31
Current assets $ 3,094 $ 2,493 $ 3,392
Noncurrent assets 20,263 22,263 21,643
--------- --------- ---------
Total assets 23,357 24,756 25,035
========= ========= =========
Current liabilities 11,043 13,503 13,188
Noncurrent liabilities 200 616 -
Stockholder's equity 12,114 10,637 11,847
--------- --------- ---------
Total liabilities and
stockholder's equity 23,357 24,756 25,035
========= ========= =========
FOR THE YEAR ENDED DECEMBER 31
Total revenues $ 29,656 $ 20,859 $ 25,037
Operating costs and expenses 29,122 21,703 24,185
--------- --------- ---------
Operating income (loss) 534 (844) 852
Other expenses (17) (633) (758)
Income tax benefit 2,028 - -
--------- --------- ---------
Net income (loss) $ 2,545 $ (1 ,477) $ 94
========= ========= =========
At December 31, 1998 and 1999, current liabilities payable to CRI totaled
approximately $10,000,000 and $9,500,000, respectively. For the years ended
December 31, 1997, 1998 and 1999, depreciation, depletion and amortization,
included in operating costs, totaled approximately $1,560,000, $2,178,000 and
$2,063,000, respectively.
Since its incorporation, CCC has had no operations, has acquired no assets
and has incurred no liabilities.
10. SUBSEQUENT EVENTS:
On January 2000, the Company sold for $5.8 million all of its oil and gas
properties in the Arkoma Basin, along with the Rattlesnake and Enterprise Gas
Gathering systems. The standardized measure of discounted future net cash flows
at December 31, 1999 attributable to the oil and gas properties was approxi-
mately $2.4 million and the Company's net book carrying value of the oil and
gas properties and the gathering systems was approximately $2.5 million.
On February 29, 2000, the Company purchased $3,000,000 of the Notes for
$2,880,000 plus accrued interest and commissions and on March 10, 2000, the
Company purchased $1,000,000 of the Notes for $950,000 plus accrued
interest and no commission.
11. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
Proved Oil and Gas Reserves (Unaudited)
The following reserve information was developed from reserve reports as of
December 31, 1996, 1997, 1998 and 1999, 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) (BBLS in thousands)
----------- -------------------
Proved reserves as of December 31, 1996 50,535 19,492
Revisions of previous estimates 3,640 6,731
Extensions, discoveries and other additions 2,903 2,072
Production (5,789) (3,518)
Sale of minerals in place (1,911) (58)
------- -------
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
======= =======
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 quanti-
ties of oil and gas that are ultimately recovered.
Gas imbalance receivables and liabilities for each of the three years ended
December 31, 1997, 1998 and 1999, were not material and have not been included
in the reserve estimates.
Proved Developed Oil and Gas Reserves (Unaudited)
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) (BBLS in thousands)
- ------------------------- ----------- -------------------
January 1, 1997 49,082 15,265
January 1, 1998 47,676 19,411
January 1, 1999 54,901 19,095
January 1, 2000 65,723 34,432
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.
1997 1998 1999
---- ---- ----
Property acquisition costs:
Proved Purchased $ 476 $ 85,100 $ 19,745
Proved Contributed - - 22,461
Unproved 4,641 3,770 1,274
-------- -------- --------
Total property acquisition costs 5,117 88,870 43,480
Exploration costs 9,792 4,801 379
Development costs 49,268 34,144 10,945
-------- -------- --------
Total $ 64,177 $127,815 $ 54,804
======== ======== ========
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):
1998 1999
---- ----
Proved oil and gas properties $270,708 $322,452
Unproved oil and gas properties 18,233 13,733
-------- --------
Total 288,941 336,185
Less- Accumulated DD&A 111,618 126,995
-------- --------
Net capitalized costs $177,323 $209,190
======== ========
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):
1997 1998 1999
---- ---- ----
Revenues $ 78,599 $ 60,162 $ 65,949
Production costs 20,748 22,611 19,368
Exploration expenses 6,806 7,106 7,750
DD&A and valuation provision 30,202 34,662 16,778
-------- -------- --------
Income (loss) 20,843 (4,217) 22,053
Income tax expense 3,300 - -
-------- -------- --------
Results of operations from producing
activities (excluding corporate
overhead and interest costs) $ 17,543 $ (4,217) $ 22,053
======== ======== ========
______________________
Includes $5.0 million, $7.9 million in 1997 and 1998, respectively, of
additional DD&A as a result of SFAS No. 121 impairments.
The 1997 income tax provision was computed based on estimated oil and
gas operations income for the five months ended March 31, 1997, times
the estimated effective income tax rate. The Company's S-Corporation
status was effective June 1, 1997.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Unaudited)
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, 1997, 1998 and 1999 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 in-
formation 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).
1997 1998 1999
---- ---- ----
Future cash inflows $ 576,330 $ 328,333 $1,069,436
Future production and development costs (189,520) (157,003) (422,558)
Future income tax expenses - - -
---------- ---------- ----------
Future net cash flows 386,810 171,330 646,878
10% annual discount for estimated timing
of cash flows (145,185) (63,660) (312,467)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows $ 241,625 $ 107,670 $ 334,411
========== ========== ==========
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 computa-
ion of future cash inflows was approximately $18.06, $10.84, and $24.38 per
BBL at December 31, 1997, 1998, and 1999, respectively. The year-end
weighted average gas price utilized in the computation of future cash
inflows was approximately $2.25, $1.64, and $1.76 per MCF at December 31,
1997,1998, and 1999, 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, 1997, 1998 or 1999, 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):
1997 1998 1999
---- ---- ----
Standardized measure of discounted
future net cash flows at the
beginning of the year $177,133 $241,625 $107,670
Extensions, discoveries and improved
recovery, less related costs 16,352 7,088 5,370
Revisions of previous quantity
estimates 58,001 (34,228) 128,280
Changes in estimated future
development costs (36,901) 2,506 (25,914)
Purchases(sales) of minerals in place (3,233) 11,815 49,984
Net changes in prices and production
costs (51,456) (116,458) 135,803
Accretion of discount 17,713 24,163 10,767
Sales of oil and gas produced, net of
production costs (57,851) (37,551) (46,581)
Development costs incurred during the
period 32,474 22,960 1,246
Net change in income taxes 89,915 - -
Change in timing of estimated future
production, and other (522) (14,250) (32,214)
-------- -------- --------
Standardized measure of discounted
future net cash flows at the end of
the year $241,625 $107,670 $334,411
======== ======== ========
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) 54 Chairman of the Board of Directors, President,
Chief Executive Officer and Director
Jack Stark(1)(3) 45 Senior Vice President--Exploration and Director
Jeff Hume(1)(4) 49 Senior Vice President--Drilling Operations and
Director
Randy Moeder(1)(2) 39 Senior Vice President, General Counsel,
Secretary and Director
Roger Clement(1)(3) 55 Senior Vice President, Chief Financial Officer,
Treasurer and Director
Tom Luttrell 42 Senior Vice President--Land
Jeff White(5) 33 Senior Vice President--Business Development
Tom Myers 54 Manager of Production Operations
- ------------------
(1) Member of the Executive, Compensation and Audit Committees.
(2) Term expires in 2002.
(3) Term expires in 2001.
(4) Term expires in 2000.
(5) Son-in-law of Harold Hamm
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.
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 Vice President, General Counsel and a Director of the
Company since November 1990 and has served as Secretary of the Company since
February 1994 and as President of Continental Gas, Inc. since January 1995 and
was Vice President of Continental Gas, Inc. from November 1990 to January 1995.
Mr. Moeder was promoted to Senior Vice President of the Company in May, 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, 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.
TOM LUTTRELL has been Vice President--Land of the Company since February 1997
and was promoted to Senior Vice President in May, 1998. From 1991 to February
1997, Mr. Luttrell was Senior Landman of the Company. Prior to joining the
Company, Mr. Luttrell served as a landman for Terra Resources, Inc., Pacific
Enterprises Oil & Gas Company and Alexander Energy Corporation, all independent
oil and gas exploration companies. Mr. Luttrell is a member of the American
Association of Petroleum Landmen.
JEFF WHITE has been Vice President--Business Development of the Company since
July 1996 and was promoted to Senior Vice President--Business Development in
May, 1998. From 1993 to July 1996, Mr. White served as Special Assistant to the
Chairman of the Federal Deposit Insurance Corporation and also served as a
Financial Analyst for the Federal Deposit Insurance Corporation. From July,
1990 to December, 1992, Mr. White served as a financial/budget analyst on
issues relating to Resolution Trust Corporation funding. Prior to 1990, Mr.
White served as an analyst to the Banking Committee of the House of
Representatives.
TOM MYERS has been Manager of Production Operations since January, 1997. He
was formerly with Sonat Exploration from 1990 to 1996 serving in the capacity of
Operations Manager in West Virginia, Arkansas/Eastern Oklahoma, South Texas and
the Permian Basin. He was also the Corporate Director of Operations from 1993 to
1994. From 1980 until 1990 he was with Texas Oil and Gas Corp. in West Texas,
Mississippi, Alabama, Arkansas, and Eastern Oklahoma in the capacity of District
Drilling and Production Manager. Mr. Myers is a Registered Professional
Engineer and a member of the Society of Petroleum Engineers and the Oklahoma
Independent Petroleum Association.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
Securities
Other Underlying
Annual Compensation Annual Option All Other
------------------- Compensation Awards Compensation
Name Year Salary($) Bonus($) ($)(1) (# of shares) ($)(2)
- ---- ---- --------- -------- ------ ------------- ------
Harold Hamm 1999(3) $ - $ - $ - $ - $ -
1998 250,000 - - - 857
1997 187,506 - - - -
Jack Stark 1999 131,616 5,000 - - 8,942
1998 139,964 - - - 12,831
1997 116,550 10,249 - - 9,815
Jeff Hume 1999 125,456 5,000 - - 12,094
1998 123,584 - - - 17,226
1997 113,350 10,249 - - 11,162
Tom Myers 1999 106,928 1,300 - - 8,519
1998 105,513 - - - 11,942
1997 102,679 7,289 - - 346
Roger Clement 1999 106,008 5,000 - - 3,756
1998 98,476 - - - 4,823
1997 89,968 9,718 - - 3,118
Randy Moeder 1999 102,313 20,000 - - 8,200
1998 91,333 - - - 19,566
1997 90,743 10,436 - - 18,666
- -----------------
(1) Represents the value of perquisites and other personal
benefits in excess of 10% of annual salary and bonus. For
the year ended December 31, 1999, the Company paid no other
annual compensation to its named Executive Officers.
(2) 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.
(3) Received no compensation during the calendar year 1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Harold Hamm, Chairman of the board, President and Chief Executive Officer and
a director of the Company beneficially owns 44,496 shares (90.7%) of the
Company's outstanding common stock. The remaining 4,545 shares (9.3%) of
the outstanding common stock is beneficially owned by the Harold Hamm HJ
Trust (1,818 shares) and the Harold Hamm DST Trust (2,727 shares). These
trusts are irrevocable trusts over which Harold Hamm has no voting or
investment power.
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 1999. 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,
including Hamm & Phillips Service Company, Stride Well Service Inc., Oil Tool
Rentals, Inc. and Catworks, Inc. 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 1999 was $7.4 million and at December 31, 1999 the Company
owed these companies approximately $0.4 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, 1999, the Company owed such persons an aggregate of
$1,239,000, representing their shares of oil and gas production sold by the
Company.
STOCKHOLDER LOANS AND ADVANCES. During 1999, the Company made no loans or
advances to the principal stockholder or affiliates.
OFFICE LEASE. The Company leases office space under operating leases directly
or indirectly from the principal stockholder and Continental Management Company,
L.L.C., a Company owned in part by the principal stockholder. In 1999, the
Company paid rents associated with these leases of approximately $369,000.
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 prop-
erties. At December 31, 1999, the aggregate unpaid balance owed to the Company
by such officers and directors was $768,000, none of which was past due. Of
the amount due from directors and officers at December 31, 1999, $767,000 is
associated with the principal stockholder's ownership in the Worland field.
Currently, the December 31, 1999 balance has been paid and the amount due from
the principal stockholder is approximately $11,000.
WORLAND FIELD. 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, Harold Hamm. 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. The principal stockholder paid $19.3 million of the
purchase price in cash and the balance of $23.3 million by the cancellation
of indebtedness owed to the principal stockholder by the Company. The
principal stockholder is subject to the applicable unit agreements in place
with respect to his interests in the Worland Field. In December 1999, the
principal stockholder contributed his interest in the purchased properties
of approximately $41.4 million along with debt of $18.6 million.
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 in PART II,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Report of Independent Public Accountants
Consolidated Balance Sheet as of December 31, 1998 and 1999
Consolidated Statement of Operations for the three years in the period ended
December 31, 1999
Consolidated Statement of Cash Flows for the three years in the period ended
December 31, 1999
Consolidated Statement of Changes in Equity for the three years in the
period ended December 31, 1999
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
All schedules are omitted because the required information is inapplicable or
the information is presented in the Financial Statements or the notes thereto.
(b) REPORTS ON FORM 8-K
None
(c) EXHIBITS:
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc. [3.1] (1)
3.2 Amended and Restate Bylaws of Continental Resources, Inc. [3.2] (1)
3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3] (1)
3.4 Bylaws of Continental Gas, Inc., as amended and restated. [3.4] (1)
3.5 Certificate of Incorporation of Continental Crude Co. [3.5] (1)
3.6 Bylaws of Continental Crude Co. [3.6] (1)
4.1 Restated Credit Agreement dated May 12, 1998 among Continental Resources,
Inc. and Continental Gas, Inc., as Borrowers and Bank One, Oklahoma,
N.A. and the Institutions named therein as Banks and Bank One,
Oklahoma, N.A. as Agent (the "Credit Agreement") [4.1] (1)
4.1.1 First Amendment to the Credit Agreement between Registrant, the financial
institutions named therein and Bank One, Oklahoma, N.A., as Agent dated
February 10, 1999 (2)
4.2 Form of Revolving Note under the Credit Agreement [4.2] (1)
4.3 Indenture dated as of July 24, 1998 between Continental Resources, Inc.,
as Issuer, the Subsidiary Guarantors named therein and the United
States Trust Company of New York, as Trustee [4.3] (1)
10.4* Conveyance Agreement of Worland Area Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April 23,
1984 to Continental Resources, Inc.
10.5* Purchase Agreement signed January 2000, effective October 1, 1999 by
and between Patrick Energy Corporation as Buyer and Continental
Resources, Inc. as Seller
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
27* Financial Data Schedule
_________________________
* 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, 1998.
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, 2000 Continental Resources, Inc.
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, 2000
President, Chief Executive
Officer (principal executive
officer) and Director
Roger V. Clement Senior Vice President and March 28, 2000
Chief Financial Officer
(Principal financial officer
and principal accounting
officer), Treasurer,
and Director
Jack Stark Senior Vice President and March 28, 2000
Director
Randy Moeder Senior Vice President, March 28, 2000
Secretary and Director
Jeff Hume Senior Vice President and March 28, 2000
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
- ------- ----------- ----------------
3.1 Amended and Restated Certificate of Incorporated herein by reference
Incorporaiton of Continental
Resources, Inc.
3.2 Amended and Restated Bylaws of Incorporated herein by reference
Continental Resources, Inc.
3.3 Certificate of Incorporation of Incorporated herein by reference
Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference
amended and restated
3.5 Certificate of Incorporation of Incorporated herein by reference
Continental Crude Co.
3.6 Bylaws of Continental Crude Co. Incorporated herein by reference
4.1 Restated Credit Agreement dated May, Incorporated herein by reference
12, 1998 among Continental Resources,
Inc. and Continental Gas, Inc., as
Borrowers and Bank One, Oklahoma, N.A.
and the Institutions named therein as
Bank and Bank One, Oklahoma, N.A. as
Agent
4.1.1 First Amendment to the Credit Incorporated herein by reference
Agreement between Registrant, the
financial institutions named therein
and Bank One, Oklahoma, N.A., as Agent
dated February 10, 1999
4.2 Form of Revolving Note under the Incorporated herein by reference
Credit Agreement
4.3 Indenture dated as of July 24, 1998 Incorporated herein by reference
between Continental Resources, Inc.,
as Issuer, the Subsidiary Guarantors
named therein and the United States
Trust Company of New York, as Trustee
10.4 Conveyance Agreement of Worland Filed herewith electronically
Area Properties from Harold G.
Hamm, Trustee of the Harold G.
Hamm Revocable Intervivos Trust
dated April 23, 1984 to
Continental Resources, Inc. as
Seller
10.5 Purchase Agreement signed Filed herewith electronically
January 2000, effective October
1, 1999 by and between Patrick
Energy Corporation as Buyer and
Continental Resources, Inc. as
Seller
12.1 Statement re computation of ratio Filed herewith electronically
of debt to Adjusted EBITDA
12.2 Statement re computation of Filed herewith electronically
earnings to fixed charges
12.3 Statement re computation of Filed herewith electronically
ratio of Adjusted EBITDA to
interest expense
21.0 Subsidiaries of Registrant Incorporated herein by reference
incorporated by reference to
page 1 of 1999 Annual Report
27 Financial Data Schedule Filed herewith electronically