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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
NUMBER OF DEVELOPMENT PROJECTS
------------------------------
ENHANCED
DRILLING WORKOVERS AND RECOVERY
LOCATIONS RECOMPLETIONS PROJECTS TOTAL
--------- ------------- -------- -----
<S> <C> <C> <C> <C>
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
=== === === ===
</TABLE>
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:
<TABLE>
<CAPTION>
NUMBER OF EXPLORATION PROJECTS
DRILLING LOCATION 3-D SEISMIC
----------------- -----------
<S> <C> <C>
ROCKY MOUNTAINS:
Williston Basin 4 2
Big Horn Basin 2 3
MID-CONTINENT 2 -
GULF COAST 11 4
--- ---
TOTAL 19 9
=== ===
</TABLE>
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:
<TABLE>
<CAPTION>
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)
- ---- ------ ------ ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
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<F1> 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%
====== ====== ====== ======== =====
_______________
<FN>
<F1> These non-core assets were sold in January 2000 for $5.8 million.
<F2> Future estimated net cash flows discounted at 10%
</FN>
</TABLE>
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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
----------------------------
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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)<F1> 17.53 11.78 15.24
Lifting cost (per Boe)<F2> 4.63 4.43 4.47
DD&A expense (per Boe)<F2> 6.74 6.78 3.61
General and administrative expense
(per Boe)<F3> 1.47 1.40 1.31
------- ------- -------
Gross margin $ 4.69 $ (0.83) $ 5.85
======= ======= =======
- --------------
<FN>
<F1> 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."
<F2> Related to drilling and development activities.
<F3> Related to drilling and development activities, net of operating overhead
income.
</FN>
</TABLE>
PRODUCING WELLS
The following table sets forth the number of productive wells in which the
Company owned an interest as of December 31, 1999:
<TABLE>
<CAPTION>
OIL NATURAL GAS
---------------- --------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
ROCKY MOUNTAINS:
Williston Basin 291 226 - -
Big Horn Basin<F1> 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
=== === === ===
- ---------------
<FN>
<F1> Represents Worland Field properties acquired by the Company in the
Worland Field Acquisition.
</FN>
</TABLE>
ACREAGE
The following table sets forth the Company's developed and undeveloped gross
and net leasehold acreage as of December 31, 1999:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
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
======= ======= ======= =======
</TABLE>
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on its
properties for the periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1997 1998 1999
------------ ------------ ----- ---
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
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
== ===== == ===== == =====
</TABLE>
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.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------
1997 1998 1999
---- ---- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
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<F1> $ 241,625 $ 107,670 $ 334,411
- ----------------
<FN>
<F1> 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.
</FN>
</TABLE>
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1998 1999
---- ---- ----
(Dollars in Thousands, Except Average Price Data)
<S> <C> <C> <C>
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<F1> 54,721 40,090 48,589
Production Volumes<F2>:
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<F3>:
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
- ---------------
<FN>
<F1>
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.
<F2>
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.
<F3>
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.
</FN>
</TABLE>
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
<PAGE>
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
<PAGE>
<TABLE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share information)
<CAPTION>
ASSETS
December 31,
--------------------
1998 1999
---- ----
<S> <C> <C>
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
========== =========
</TABLE>
The accompanying notes are an integral part of these consolidated balance
sheets.
<PAGE>
<TABLE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share information)
<CAPTION>
December 31,
---------------------------------------
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<TABLE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(in thousands)
<CAPTION>
Total
Additional Stock-
Common Paid-In Treasury Retained holders
Stock Capital Stock Earnings Equity
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
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
======= ======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<TABLE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(in thousands)
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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)
---------- --------- ----------
</TABLE>
<PAGE>
<TABLE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(in thousands)
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
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.
<TABLE>
<CAPTION>
(in thousands, except per share data) Pro Forma (Unaudited)
---------------------
1997 1998
---- ----
<S> <C> <C>
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)
========= =========
</TABLE>
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.
<TABLE>
<CAPTION>
(In thousands, except per share data) Pro Forma (Unaudited)
---------------------
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
4. LONG-TERM DEBT:
<TABLE>
Long-term debt as of December 31, 1998 and 1999, consists of the following
(in thousands):
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
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
======== ========
</TABLE>
(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):
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>
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.
<TABLE>
<CAPTION>
Crude Oil and
Natural Gas Condensate
(MMCF) (BBLS in thousands)
----------- -------------------
<S> <C> <C>
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
======= =======
</TABLE>
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.
<TABLE>
<CAPTION>
Crude Oil and
Natural Gas Condensate
Proved Developed Reserves (MMCF) (BBLS in thousands)
- ------------------------- ----------- -------------------
<S> <C> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
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):
<TABLE>
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
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
======== ========
</TABLE>
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):
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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<F1> 30,202 34,662 16,778
-------- -------- --------
Income (loss) 20,843 (4,217) 22,053
Income tax expense<F2> 3,300 - -
-------- -------- --------
Results of operations from producing
activities (excluding corporate
overhead and interest costs) $ 17,543 $ (4,217) $ 22,053
======== ======== ========
______________________
<FN>
<F1> Includes $5.0 million, $7.9 million in 1997 and 1998, respectively, of
additional DD&A as a result of SFAS No. 121 impairments.
<F2> 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.
</FN>
</TABLE>
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).
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>
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):
<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
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.
<PAGE>
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.
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
Exhibit
No. Description Method of Filing
- ------- ----------- ----------------
<S> <C> <C>
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
</TABLE>
Exhibit 10.4
CONVEYANCE AGREEMENT
This Agreement is made and entered into on this 21st day of December,
1999 by and between Harold G. Hamm, Trustee of the Harold G. Hamm Revocable
Intervivos Trust dated April 23, 1984 ("Hamm Trust") and Continental
Resources, Inc. ("Continental").
WHEREAS, pursuant to that certain Worland Area Purchase and Sale
Agreement ("Worland Agreement") entered into on June 25, 1998 the Hamm Trust
did acquire certain oil & gas wells, leases and other rights from Continental.
All right, title and interest acquired by the Hamm Trust pursuant the Worland
Agreement, together with any right, title or interest the Hamm Trust may have
subsequently acquired or be entitled to in connection with the Worland
Agreement, is collectively herein referred to as the "Subject Properties",
and;
WHEREAS, the Hamm Trust now desires to convey, assign, transfer and
relinquish unto Continental all of its rights, title and interest in and to
the Subject Properties.
NOW THEREFORE, in consideration of the mutual benefit to accrue to the
parties hereto and ten and no dollars ($10.00) and other valuable
consideration, the receipt and sufficiency of which is hereby acknowledged,
Hamm Trust and Continental hereby agree as follows:
1.1 Property being conveyed: The Hamm Trust shall convey to
Continental, as of the Effective Date, all of its right, title and interest
in and to the following:
A. All oil & gas leases, overriding royalty interests, mineral and
royalty interests, easements and rights-of-way, contractual rights
and interests, together with all rights and interests appurtenant
thereto or used or obtained in connection therewith which were
acquired by the Hamm Trust in connection with the Worland
Agreement;
B. All oil and gas wells and interests therein, together with all
materials, supplies, machinery, equipment, improvements and other
personal property and fixtures located thereon, associated
therewith or appurtenant thereto that were acquired by the Hamm
Trust in connection with the Worland Agreement.
C. All rights, title and interest of whatsoever nature, whether real
or personal, that the Hamm Trust may have acquired and/or in
anyway been entitled to as a result of or in connection with the
Worland Agreement.
2. Effective Date and Allocation of Revenue and Expenses: The
conveyance contemplated by this Agreement shall be effective as of December
31, 1999 ("Effective Date"). The Hamm Trust shall be entitled to all revenue
and bear all costs, risk and expense associated with the Subject Properties
accruing on or prior to the Effective Date. Continental shall be entitled to
all revenue and bear all costs, risk and expense associated with the Subject
Properties accruing after the Effective Date.
3. Title Verification Waiver: Continental represents that it has
heretofore conducted all necessary due diligence investigations and satisfied
itself with respect to title and specifically waives any claims in that
regard.
4. Covenants and Representations: The Hamm Trust covenants and
represents that at Closing, the Subject Properties will be conveyed to
Continental free of all mortgages, liens, claims and demands of whatsoever
nature other than those existing and burdening the Subject Properties prior to
the Hamm Trusts acquisition thereof. Continental covenants and represents that
it is a validly existing Oklahoma Corporation, authorized to conduct business
in the State where the Subject Properties are located.
5. Abolishment of AMI: The Worland Agreement established an Area of
Mutual Interest ("AMI") covering certain lands, and among other things created
certain obligations and entitlements with respect to subsequently acquired
interests. Both the Hamm Trust and Continental hereby abolish and terminate
such AMI and agree same is no longer effective for any purpose, and also
relinquish and surrender unto one another any rights or obligations which may
have heretofore accrued in connection with such AMI.
6. Assumption and Indemnification. UPON DELIVERY TO AND
ACCEPTANCE BY CONTINENTAL OF THE ASSIGNMENT AND BILL OF SALE, CONTINENTAL
SHALL BE DEEMED TO HAVE ASSUMED, TO PAY AND PERFORM TIMELY, ALL DUTIES,
EXPENSES, OBLIGATIONS, LOSSES, HAZARDS AND LIABILITIES RELATING TO THE
OWNERSHIP OF THE PROPERTIES ARISING ON AND AFTER THE EFFECTIVE DATE
(INCLUDING, WITHOUT LIMITATION, THOSE ARISING UNDER OR BY VIRTUE OF ANY LEASE,
CONTRACT, AGREEMENTS, DOCUMENT, PERMIT OR RULE, OR DELAY IN OBTAINING APPROVAL
OF FEDERAL OR STATE ASSIGNMENTS); AND, TO RELEASE, INDEMNIFY, DEFEND, AND HOLD
HARMLESS THE HAMM TRUST FROM AND AGAINST ANY AND ALL CLAIMS, ACTIONS,
LIABILITIES, LOSSES, DAMAGES, COSTS, OR EXPENSES (INCLUDING COURT COSTS AND
ATTORNEYS' FEES) OF ANY KIND OR CHARACTER ARISING OUT OF OR OTHERWISE RELATING
TO THE OWNERSHIP OF THE PROPERTIES ON AND AFTER THE EFFECTIVE DATE. IN
CONNECTION WITH (BUT NOT IN LIMITATION OF) THE FOREGOING, IT IS SPECIFICALLY
UNDERSTOOD AND AGREED THAT MATTERS ARISING OUT OF OR OTHERWISE RELATING TO THE
OWNERSHIP OF THE PROPERTIES ON AND AFTER THE EFFECTIVE DATE SHALL BE DEEMED TO
INCLUDE ALL MATTERS ARISING OUT OF THE STATUS AND THE CONDITION OF THE
PROPERTIES ON THE EFFECTIVE DATE INCLUDING, WITHOUT LIMITATION, ALL
OBLIGATIONS TO PROPERLY PLUG AND ABANDON WELLS LOCATED ON THE PROPERTIES, TO
RESTORE THE SURFACE OF THE PROPERTIES TO AS NEAR ITS ORIGINAL CONDITION AS
PRACTICABLE AND TO COMPLY WITH, OR BRING THE PROPERTIES INTO COMPLIANCE WITH,
APPLICABLE ENVIRONMENTAL LAWS AND REGULATIONS, INCLUDING ALL LIABILITY AND
EXPENSE FOR ANY RESTORATION, REMEDIATION, CLEAN-UP, DISPOSAL OF WASTE, OR
REMOVAL THAT MAY BE INCURRED AS A RESULT OF THE EXISTENCE OR DISCOVERY OF
NATURALLY OCCURRING RADIOACTIVE MATERIALS, OR OTHER HAZARDOUS OR DELETERIOUS
SUBSTANCES IN, ON, UNDER OR ASSOCIATED WITH THE PROPERTIES, REGARDLESS OF WHEN
THE EVENTS OCCURRED THAT GIVE RISE TO SUCH CONDITION, AND THE ABOVE PROVIDED
FOR ASSUMPTIONS AND INDEMNIFICATIONS BY CONTINENTAL SHALL EXPRESSLY COVER AND
INCLUDE SUCH MATTERS. THE FOREGOING ASSUMPTIONS AND INDEMNIFICATIONS SHALL
APPLY WHETHER OR NOT SUCH DUTIES, OBLIGATIONS, OR LIABILITIES, OR SUCH CLAIM,
ACTIONS, CAUSES OF ACTION, LIABILITIES, DAMAGES, LOSSES, COSTS, OR EXPENSES
ARISE OUT OF (i) NEGLIGENCE (INCLUDING SOLE NEGLIGENCE, SIMPLE NEGLIGENCE,
CONCURRENT NEGLIGENCE, ACTIVE OR PASSIVE NEGLIGENCE OR OTHERWISE, BUT
EXPRESSLY NOT INCLUDING GROSS NEGLIGENCE OR WILLFUL MISCONDUCT) OF THE HAMM
TRUST OR ANY OTHER INDEMNIFIED PARTY, OR (ii) STRICT LIABILITY.
7. Environmental Assessment and Indemnification by Continental.
CONTINENTAL EXPRESSLY ACKNOWLEDGES THAT IT HAS MADE AN ENVIRONMENTAL
ASSESSMENT OF THE PROPERTIES. CONTINENTAL HEREBY AGREES TO ASSUME THE RISKS
THAT THE PROPERTIES MAY CONTAIN WASTE MATERIALS OR HAZARDOUS SUBSTANCES, AND
THAT ADVERSE PHYSICAL CONDITIONS, INCLUDING BUT NOT LIMITED TO THE PRESENCE OF
WASTE MATERIALS OR HAZARDOUS SUBSTANCES OR THE PRESENCE OF UNKNOWN ABANDONED
OIL AND GAS WELLS, WATER WELLS, SUMPS AND PIPELINES, MAY EXIST IN, ON, OR
UNDER THE PROPERTIES AS OF THE EFFECTIVE DATE, ALL RESPONSIBILITY AND
LIABILITY RELATED TO ALL SUCH CONDITIONS, WHETHER KNOWN OR UNKNOWN, WILL BE
TRANSFERRED FROM THE HAMM TRUST TO CONTINENTAL. CONTINENTAL ASSUMES FULL
RESPONSIBILITY FOR, AND AGREES TO INDEMNIFY, HOLD HARMLESS AND DEFEND HAMM
TRUST FROM AND AGAINST ALL LOSS, LIABILITY, CLAIMS, FINES, EXPENSES, COSTS
(INCLUDING ATTORNEYS' FEES AND EXPENSES) AND CAUSES OF ACTION CAUSED BY OR
ARISING OUT OF ANY FEDERAL, STATE OR LOCAL LAWS, RULES, ORDERS AND REGULATIONS
APPLICABLE TO ANY NATURALLY OCCURRING RADIOACTIVE MATERIAL, WASTE MATERIAL OR
HAZARDOUS SUBSTANCES ON OR ASSOCIATED WITH THE PROPERTIES OR THE PRESENCE,
DISPOSAL, RELEASE OR ASSOCIATED WITH THE PROPERTIES OR THE PRESENCE, DISPOSAL,
RELEASE OR THREATENED RELEASE OF ALL NATURALLY OCCURRING RADIOACTIVE
MATERIALS, WASTE MATERIAL OR HAZARDOUS SUBSTANCES FROM THE PROPERTIES INTO THE
ATMOSPHERE OR INTO OR UPON LAND OR ANY WATER COURSE OR BODY OF WATER,
INCLUDING GROUND WATER, WHETHER OR NOT ATTRIBUTABLE TO CONTINENTAL'S
ACTIVITIES OR THE ACTIVITIES OF THIRD PARTIES (REGARDLESS OF WHETHER OR NOT
HAMM TRUST WAS OR IS AWARE OF SUCH ACTIVITIES) PRIOR TO, DURING OR AFTER THE
PERIOD OF HAMM TRUST'S OWNERSHIP OF THE PROPERTIES. THIS INDEMNIFICATION AND
ASSUMPTION SHALL ALSO APPLY TO LIABILITY FOR VOLUNTARY ENVIRONMENTAL RESPONSE
ACTIONS UNDERTAKEN PURSUANT TO THE COMPREHENSIVE ENVIRONMENTAL RESPONSE
COMPENSATION AND LIABILITY ACT (CERCLA) OR ANY OTHER FEDERAL, STATE OR LOCAL
LAW.
8. Disclaimer of Warranties. THE PROPERTIES SHALL BE CONVEYED
PURSUANT HERETO WITHOUT ANY WARRANTY OR REPRESENTATION WHATSOEVER, WHETHER
EXPRESS, IMPLIED OR STATUTORY AS TO, DESCRIPTION, QUANTITY, QUALITY, FITNESS
FOR A PARTICULAR PURPOSE, CONFORMITY TO THE MODELS OR SAMPLES OF MATERIALS, OR
MERCHANTABILITY OF ANY EQUIPMENT OR ITS FITNESS FOR ANY PURPOSE, OR OTHERWISE.
CONTINENTAL SHALL HAVE INSPECTED, OR WAIVED ITS RIGHT TO INSPECT, THE
PROPERTIES FOR ALL PURPOSES AND SATISFIED ITSELF AS TO THEIR PHYSICAL AND
ENVIRONMENTAL CONDITION, BOTH SURFACE AND SUBSURFACE, INCLUDING, BUT NOT
LIMITED TO, CONDITIONS SPECIFICALLY RELATED TO THE PRESENCE, RELEASE, OR
DISPOSAL OF HAZARDOUS SUBSTANCES, SOLID WASTES, ASBESTOS, OR OTHER MANMADE
FIBERS OR NATURALLY OCCURRING RADIOACTIVE MATERIALS ("NORM") IN, ON, OR UNDER
THE PROPERTIES. CONTINENTAL IS RELYING SOLELY UPON ITS OWN INSPECTION OF THE
PROPERTIES, AND CONTINENTAL SHALL, EXCEPT AS PROVIDED OTHERWISE HEREIN, ACCEPT
ALL OF THE SAME "AS IS, WHERE IS". WITHOUT LIMITATION OF THE FOREGOING, HAMM
TRUST MAKES NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY, OR
OTHERWISE, AS TO THE ACCURACY OR COMPLETENESS OF ANY DATA, REPORTS, RECORDS,
PROJECTIONS, INFORMATION, OR MATERIALS NOW, HERETOFORE, OR HEREAFTER FURNISHED
OR MADE AVAILABLE TO CONTINENTAL IN CONNECTION WITH THIS AGREEMENT, INCLUDING,
WITHOUT LIMITATION, PRICING ASSUMPTIONS OR QUALITY OR QUANTITY OF HYDROCARBON
RESERVES (IF ANY) ATTRIBUTABLE TO THE PROPERTIES OR THE ABILITY OR POTENTIAL
OF THE PROPERTIES TO PRODUCE HYDROCARBONS OR THE ENVIRONMENTAL CONDITION OF
THE PROPERTIES OR ANY OTHER MATTERS CONTAINED IN THE PROPRIETARY DATA OR ANY
OTHER MATERIALS FURNISHED OR MADE AVAILABLE TO CONTINENTAL BY HAMM TRUST OR BY
HAMM TRUST'S AGENTS OR REPRESENTATIVES. ANY AND ALL SUCH DATA, RECORDS,
REPORTS, PROJECTIONS, INFORMATION, AND OTHER MATERIALS (WRITTEN OR ORAL)
FURNISHED BY HAMM TRUST OR OTHERWISE MADE AVAILABLE OR DISCLOSED TO
CONTINENTAL ARE PROVIDED TO CONTINENTAL AS A CONVENIENCE AND SHALL NOT CREATE
NOR GIVE RISE TO ANY LIABILITY OF OR AGAINST HAMM TRUST, AND ANY RELIANCE ON
OR USE OF THE SAME SHALL BE AT CONTINENTAL'S SOLE RISK TO THE MAXIMUM EXTENT
PERMITTED BY LAW.
9. Closing: On or before January 31, 2000 the Hamm Trust shall
deliver to Continental a fully executed Assignment and Bill of Sale which
shall effect the conveyance described in Article 1 above. Such Assignment and
Bill of Sale shall be in a mutually acceptable form, and shall be made with
special warranty of title, being be through and under the Hamm Trust, but not
otherwise.
10. Post-Closing Agreements: Within ninety (90) days after
Closing, the parties shall settle any necessary reconciliations regarding
revenue and expenses, or other matters remaining to be resolved in connection
with the transaction contemplated by this Agreement.
IN WITNESS WHEREOF, this Agreement is made and entered into on this
21st day of December, 1999.
HAROLD G. HAMM REVOCABLE INTERVIVOS TRUST DATED APRIL 23, 1984
By: HAROLD G. HAMM
Harold G. Hamm, Trustee
CONTINENTAL RESOURCES, INC.
By: TOM LUTTRELL
Tom Luttrell
Vice President - Land
Exhibit 10.5
PURCHASE AGREEMENT
THIS ASSET PURCHASE AGREEMENT (this "Agreement") is made and entered
into effective as of October 1, 1999 by and among Patrick Energy Corp., (the
"Purchaser") and Continental Resources, Inc. and Continental Gas, Inc.;
Oklahoma Companies (hereinafter collectively referred to as "Sellers" or
"Companies").
W I T N E S S E T H:
WHEREAS, the Sellers are engaged in the oil and gas business;
WHEREAS, Sellers desire to sell and Purchaser desires to purchase assets
of Sellers upon the terms and subject to the conditions set forth herein; and
WHEREAS, Sellers understand that Purchaser is acquiring (among other
assets and without limitations) coalbed methane gas;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants, representations and warranties set forth herein, and for other good
and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto, intending to be bound hereby, agree as
follows:
SECTION 1. SALE AND PURCHASE OF ASSETS
1.1 Sale and Purchase.
1.1.1. Sale and Purchase of Assets.
Upon the terms and subject to the conditions set forth in this
Agreement, at the Closing (as defined in Section 11.1 hereof), but effective
as of the Effective Date (as defined in Section 1.3 hereof), Sellers shall
sell, assign, transfer, convey and deliver to Purchaser, and Purchaser shall
purchase, take possession and acquire assets from Sellers (collectively the
"Assets") including:
(a) The oil, gas and mineral leases set forth on the schedules
attached hereto and collectively referred to as "Schedule 1.1.1" (and in and
to any ratifications and amendments to such leases, whether or not such
ratifications or amendments are set forth on Schedule 1.1.1 hereto), insofar
as such leases cover and affect the lands and depths described on Schedule
1.1.1 hereto, the foregoing to be conveyed to Purchaser with full warranty of
title, by, through and under Sellers, but not otherwise;
(b) All other right, title and interest (of every kind or character,
whether legal or equitable, and whether vested or contingent) in and to the
oil, gas and other minerals in and under or that may be produced from the
lands described in Schedule 1.1.1 hereto (including, without limitation,
interests in oil, gas and mineral leases, licenses, permits and similar
arrangements, overriding royalty interest, reversionary interest, back-in
interest, production payments, net profits interests, fee mineral interests,
fee royalty interests and other interests in such oil, gas and other minerals),
even though Sellers' interests in such oil, gas and other minerals may be
incorrectly described on Schedule 1.1.1 hereto;
(c) All oil, gas and mineral unitization, pooling and
communitization agreements, declarations and orders (including, without
limitation, all units formed under orders, rules, regulations or other
official acts of any federal, state or other authority having jurisdiction,
voluntary unitization agreements, designations and declarations) relating to
the properties described in clauses (a) and (b) properties described in
clauses (a) and (b) above (the properties, rights and interests described in
clauses (a), (b) and (c) and the same properties, rights and interests in the
assets are sometimes hereinafter referred to as the "Oil and Gas Properties");
(d) All materials, supplies, machinery, equipment, improvements
and other personal property and fixtures (including, without limitation,
leased compressors, all wells, well head equipment, pumps, pumping units,
platforms, flow lines, tanks, buildings, injection facilities, salt water
disposal facilities, compression facilities, gathering systems, salt water
disposal wells, water wells, line well facilities, sulfur recovery facilities,
compressors, compressor stations, dehydration facilities, treating facilities,
values, meters, separator tanks, tank batteries, tools, leased equipment,
office equipment, and other fixtures and equipment located on the Oil and Gas
Properties and used in connection with he exploration, development, operation
or maintenance thereof);
(e) To the extent transferable, all production sales contracts,
operating agreements, equipment, real estate and other leases, licenses,
permits, security agreements, joint venture agreements, unit agreements,
pooling agreements, areas of mutual interest, farm-out agreements, farm-in
agreements, (salt water disposal agreements, water injection agreements, line
well injection agreements, if any, but Sellers believe there are none), road
use agreements, gas balancing agreements, gas processing agreements, gas
contracts, supplier contracts, service contracts, (construction agreements,
storage or warehouse agreements, if any, but Sellers believe there are none),
and other agreements and contracts which relate to the Oil and Gas Properties,
to the extent, and only to the extent, such rights, titles and interests are
attributable tot he Oil and Gas Properties and all other contracts and other
agreements relating to the Assets (the "Contracts");
(f) All seismic, geological and geophysical data, of every kind
or nature, wherever located, relating to the Oil and Gas Properties
transferred to Purchaser;
(g) To the extent transferable, all surface use agreements,
easements, rights of way, licenses, authorizations, permits and similar rights
and interests applicable to any of the Oil and Gas Properties transferred to
Purchaser;
(h) To the extent transferable, all franchises, approvals,
permits, licenses, qualifications, orders, registrations, certificates,
variances and similar rights obtained from governmental and regulatory
authorities and any pending applications therefor related to the Assets
transferred to Purchaser; and
(i) Copies of all books, records, ledgers, files, data,
documents, correspondence, lists, plats, materials, studies, reports and other
printed and written materials related to the Assets transferred to Purchaser
will be provided as required by paragraph 17.4 of this Agreement.
1.2 Liabilities. Purchaser shall not assume any liability of
Sellers or the Companies, by way of explanation and not Limitation, the
Purchaser does not assume any of the following (collectively, the
"Liabilities"):
(a) Royalties, taxes and trade and accounts payable related to the
Assets due and payable or incurred before the Effective Date to the extent not
previously paid by Sellers;
(b) All severance obligations of Sellers with respect to all
employees of Sellers who become employees of Purchaser, if any.
1.3 Effective Date. The "Effective Date" of the sale and
purchase of the Assets provided for in this Agreement is October 1, 1999,
notwithstanding the Closing Date.
SECTION 2. PURCHASE PRICE
2.1 Purchase Price. In payment and consideration for the sale
of the Assets by Sellers to Purchaser, at the Closing, upon the terms and
subject to the conditions and reductions set forth in this Agreement,
Purchaser shall pay to Sellers a purchase price of Five Million Eight Hundred
Thousand Dollars ($5,800,000) (the "Base Purchase Price") subject to the
following adjustments (as so adjusted, the "Purchase Price"):
(a) Less an amount equal to the value of all Oil and Gas
Properties as to which third parties exercise Preferential Rights or as to
which Consents are not obtained, in each case such term is defined in, and in
accordance with the provisions of, Section 5.3 hereof;
(b) Plus or less, as appropriate, an amount equal to the value of
all Title Defects (as defined in Section 8.1 hereof) in accordance with the
provisions of Section 8.1 hereof;
(c) Less an amount equal to the reduction in value of all Assets
subject to Casualty Defects (as defined in Section 8.4 hereof) that exist at
the Closing in accordance with the provisions of Section 8.4 hereof;
(d) Plus or less, as appropriate, an amount equal to the value of
all gas imbalances in accordance with the provisions of Section 8.5 hereof;
and
(e) Less the amount, if any, of all prepayments, take-or-pay
payments or similar payments (out of any royalties and of any production,
severance or sales taxes not reimbursed to Sellers by the purchaser of
production) received by Sellers that are attributable to oil or gas from the
Oil and Gas Properties that is obligated to be delivered after the Effective
Date without the owner of the Oil and Gas Properties receiving fill payment
therefor.
2.2 Payment of Purchase Price. The Base Purchase Price, as
adjusted, shall be paid by Purchaser to Sellers at the Closing by wire
transfer of immediately available funds to an account designated by Sellers.
2.3 Allocation of Purchase Price. The Purchase Price shall be
allocated by Purchaser for all purposes (including financial reporting and tax
purposes) among the Assets and as set forth on Schedule 2.3 hereto. Sellers
and Purchaser each hereby covenant and agree that they will not take a
position on any income tax return, before any governmental authority charged
with the collection of any income tax, or in any judicial proceeding that is
in any way inconsistent with the terms of this Section 2.3.
2.4 Post-Closing Adjustment. Within five business days after
the final determination of the adjustments to the Purchase Price in accordance
with Section 14 hereof, Purchaser shall pay to Sellers, or Sellers shall pay
to Purchaser, as appropriate, the amount of the post-Closing adjustments to
the Base Purchase Price. Any such payments shall be made by wire transfer of
immediately available funds to an account designated by the payee thereof.
2.5 Deposit. Contemporaneously with the execution of this
Agreement, Purchaser paid to Sellers an amount equal to twenty-five thousand
dollars ($25,000.00) (the "Deposit"). If the sale and purchase of the Assets
contemplated hereby is consummated in accordance with the terms hereof, then
the Deposit, without any interest thereon, shall be applied to the Purchase
Price to be paid by Purchaser to Sellers at the Closing. If this Agreement is
terminated in accordance with the provisions of Section 15.1 (a) - (e) hereof
and neither Purchaser nor Sellers has breached or defaulted under any
provision of this Agreement, then the Deposit, without interest thereon, shall
be returned to Purchaser. If this Agreement is terminated due to a breach or
default by Sellers of any provision of this Agreement which occurred in the
absence of a breach or default by Sellers of any provision of this Agreement
which occurred in the absence of a breach or default of any provision of this
Agreement by Purchaser, or pursuant to Section 15.1 (f), then the Deposit,
together with any interest earned thereon, shall be returned to Purchaser. If
this Agreement is terminated by Purchaser and Sellers are not in breach or
default under any provision of this Agreement, and Purchaser's termination is
not made pursuant to Section 15.1 (a)-(f), then the Deposit, together with any
interest earned thereon, shall be retained by Sellers.
SECTION 3. REPRESENTATIONS AND WARRANTIES OF SELLERS
Sellers hereby represent and warrant to Purchaser as follows:
3.1 Organization. Sellers are corporations duly organized,
validly existing and in good standing under the laws of the State of Oklahoma.
3.2 Power and Authority. Sellers have the full corporate power
and authority to execute and deliver this Agreement and to perform its
obligations hereunder, and the execution and delivery of this Agreement by
Sellers and the performance by Sellers of its obligations hereunder have been
duly authorized by all necessary corporate action of Sellers.
3.3 Enforceability. This Agreement has been duly executed and
delivered on behalf of Sellers and the transaction contemplated hereby will
constitute the valid and binding obligation of Sellers, enforceable against
Sellers in accordance with its terms, except as such enforceability may be
limited by (a) any applicable bankruptcy, insolvency, reorganization,
receivership, moratorium, fraudulent transfer and conveyance laws and other
similar laws of general application relating to or affecting the rights and
remedies of creditors, or (b) general principals of equity, whether applied by
a court of law or equity.
3.4 No Conflict. Neither the execution and delivery of this
Agreement by Sellers nor the performance by Sellers of its obligations
hereunder will violate, result in the breach of any provision of, or
constitute a default under (a) the Articles of Incorporation or By-laws of
Sellers, (b) any agreement or instrument to which Sellers are a party or by
which it or the Assets is bound, (c) any judgment, order, decree or writ to
which Sellers are a party or by which Sellers or the Assets are bound, or (d)
any law, rule or regulation applicable to Sellers or the Assets, except for
any violation, breach or default that will not have a material adverse effect
on the Assets.
3.5 Brokers. Sellers have incurred no obligation or liability,
contingent or otherwise, for brokers' or finders' fees in connection with this
Agreement in respect of which Purchaser may have any obligation or liability,
and any such obligation or liability that might exist shall be the sole
obligation of Sellers.
3.6 Litigation and Claims. Except as set forth on Schedule 3.6
hereto, there are no claims, actions, suits or proceedings pending against
Sellers, or any of the Assets which, if adversely determined, would reasonably
be expected to either have a material adverse effect on the ability of Sellers
to execute, deliver or perform its obligations under this Agreement or to have
a material adverse effect on the Assets.
3.7 Contracts. Each Contract included within the Assets is a
valid and binding obligation of Sellers and each other party thereto,
enforceable against Sellers and each other party thereto in accordance with
its terms, except as such enforceability may be limited by (a) the course of
conduct of the parties to the Contracts, (b) any applicable bankruptcy,
insolvency, reorganization, receivership, moratorium, fraudulent transfer and
conveyance laws and other similar laws of general application relating to or
affecting the rights and remedies of creditors, or (c) general principles of
equity, whether applied by a court of law or equity. Neither Sellers nor any
other party is in breach of, or default under, any provision of any Contract,
which breach or default could be reasonably expected to have an adverse effect
on the Assets.
3.8 Permits and Licenses. Sellers have complied in all material
respects with the provisions and requirements of all orders, regulations and
rules issued or promulgated by governmental authorities having jurisdiction
with respect to the Assets and possesses all governmental permits and other
licenses necessary for Sellers' current operation of the Assets, other than
permits and licenses (a) required for the sale and transfer of the Assets to
Purchaser of (b) the failure of which to possess would bot have an adverse
effect on the Assets.
3.9 Environmental Matters. Except as set forth on Schedule 3.9
hereto, to the best of Sellers' knowledge (a) the Assets being sold to
Purchaser are in compliance with all laws, rules and regulations pertaining to
the control of hazardous substances or of pollutants or the protection of the
environment ("Environmental Laws"), (b) neither Sellers nor the Companies have
any liability for remediation actions (including removal, response, clean-up,
investigating and monitoring of contaminants and pollutants) resulting from
any release, discharge, placement, migration or movement of contaminants or
pollutants into the environment from any of the Assets, and (c) there are no
claims, action, suits or proceedings, judgements, orders, writs or injunctions
of any court or governmental authority pending or presently in effect of, to
the knowledge of Sellers, overtly threatened against Sellers or the Companies
relating to Environmental Laws, which, in any case, would reasonably be
expected to have (i) an adverse effect on the ability of Sellers to execute,
deliver or perform its obligations under the Agreement or (ii) an adverse
effect on the Assets.
3.10 Title to the Purchased Assets. Sellers have title to all the
Assets; Sellers shall convey to Purchaser the Assets with warranty of title,
by, through and under Sellers; and at the Closing Date, such Assets shall be
free and clear of all mortgages, pledges, liens, security interests, leases,
conditional sale or other title retention agreements, encumbrances, rights or
other changes of any kind or character, except as otherwise set forth on
Schedule 3.10 hereto, including leased Assets, also reflected on Schedule
3.10. To the best of Sellers' knowledge, the names of the Companies defined
herein, are the only names under which Purchaser needs to search the public
records to determine the existence of validly perfected liens or security
interests in or to the Assets. Upon the transfer of the Assets by Sellers to
Purchaser at the Closing, Purchaser will receive all the Assets free and clear
of all pledges, liens, security interests, leases, conditional sale or other
title retention agreements, encumbrances or other charges of any kind.
SECTION 4. REPRESENTATIONS AND WARRANTIES OF PURCHASER
Purchaser hereby represents and warrants to Sellers as follows:
4.1 Organization. Purchaser is a corporation duly organized,
validly existing and in good standing under the laws of the State of Michigan.
4.2 Power and Authority. Purchaser has the full corporate power
and authority to execute and deliver this Agreement and to perform its
obligations hereunder. The execution and delivery of this Agreement by
Purchaser and the performance by Purchaser of its obligations hereunder have
been duly authorized by the Board of Directors of Purchaser and by all other
necessary corporate action of Purchaser.
4.3 Enforceability. This Agreement has been duly executed and
delivered on behalf of Purchaser and constitutes the valid and binding
obligation of Purchaser, enforecable against Purchaser in accordance with its
terms, except as such enforceability may be limited by (a) any applicable
bankruptcy, insolvency, reorganization, receivership, moratorium, fraudulent
transfer and conveyance laws and other similar laws of general application
relating to or affecting the rights and remedies of creditors, or (b) general
principals of equity, whether applied by a court of law or equity.
4.4 No Conflicts. Neither the execution and delivery of this
Agreement by Purchaser nor the performance by Purchaser of its obligations
hereunder will violate, result in the breach of any provision of, or
constitute a default under (a) the Certificate of Incorporation, By-laws or
other charter or organizational documents of Purchaser, (b) any agreement or
instrument to which Purchaser is a party or by which it or its assets is
bound, (c) any judgment, order, decree or writ to which Purchaser is a party
or by which Purchaser or its assets is bound, or (d) any law, rule or
regulation applicable to Purchaser or its assets.
SECTION 5. COVENANTS OF SELLERS
5.1 (a) Access. Until the Closing Date (the "Due Diligence
Period"), Sellers shall make available to Purchaser and its officers,
employees, agents and representatives, at any reasonable time upon adequate
notice to Sellers, access to the Assets and Sellers' full and accurate books,
records, documents, data and other information relating to the Assets
including, but not limited to Purchaser's right to investigate and audit all
of the pertinent technical, geological, geophysical engineering, reserves,
revenue, costs operations, land, legal title, environmental, marketing,
accounting, contracts, and dedication agreements, revenue studies, enhanced
oil recovery studies, drilling plans, pipeline specifications, test data,
operating costs, production, plugging liabilities, field facilities, lease and
right of way documents, permits, title opinions and other information
Purchaser may request ("Sellers Data");
(b) Purchaser's Right to Terminate. The Purchaser shall
have the absolute right to terminate this Agreement by delivering written
notice to Sellers of such termination on or before 6:00 p.m. on the last day
of the Due Diligence Period if, alone or in the aggregate, (i)-(iv), below,
exceed ten percent (10%) of the Base Purchase Price (i) the Assets are subject
to substantial defects in title, liens or encumbrances (which will not be
released prior to Closing), or (ii) if an independent third party has
exercised or exercises an interest in the Assets, or (iii) in the event
Purchaser becomes aware of any circumstance or set of circumstances involving
a material adverse change in the Assets occurring during the Due Diligence
Period (and Purchaser shall use reasonable business efforts to inform Sellers
as soon as Purchaser becomes aware of any such circumstance or set of
circumstances), or (iv) the Assets are subject to a Casualty Defect. Upon
termination of this Agreement under this paragraph each party hereto shall be
released from all liabilities and obligations under this Agreement and Sellers
shall return the Deposit to Purchaser.
5.2 Operations. From the date of this Agreement until the Closing
Date, Sellers shall, except as otherwise contemplated by this Agreement:
(a) Conduct its Business and operate (or, if not the operator,
use its best efforts to cause the operation of ) the Assets in the ordinary
course of business consistent with past practices;
(b) Use its best efforts to maintain and keep the Assets in
their present working order, ordinary wear and tear excepted, and keep them
supplied with all necessary repairs, renewals and improvements;
(c) Perform all its obligations in conformity in all respect
with all oil, gas and mineral leases and other material agreements and
Contracts included in the Assets;
(d) Operate the Assets in conformity with all applicable laws,
regulations and orders of governmental authorities having jurisdiction over
Sellers or the Assets;
(e) Not sell, lease (as lessor), transfer, license (as
licensor), or otherwise dispose of any of the Assets, except for the sale of
inventory or monthly production (not future production) in the ordinary course
of business and for any other disposition of a non-material portion of the
Assets;
(f) Not release, terminate, permit to terminate, modify or
reduce its rights under any oil, gas or mineral lease or other material
agreement or contract forming a part of the Assets, or modify or enter into
any new production, sales or marketing contracts relating to the Assets, which
in any case has an adverse effect on the Assets; and
(g) Pay and discharge all taxes and expenses (including,
without limitation, all bills for labor, materials and supplies used or
furnished for use in connection with the Assets and all severance, production,
windfall project and all similar taxes) and liabilities relating to Sellers'
operation of the Assets.
5.3 Preferential Rights and Consents. Sellers do not believe that
the Oil and Gas Properties are, but if, certain of the Oil and Gas Properties
are or may be subject to (a) preferential purchase rights, rights of first
refusal and similar option rights in third parties to purchase all or part of
certain of the Oil and Gas Properties (collectively, "Preferential Rights"),
or (b) lessors' approvals or other consents to transfer any part of the Oil
and Gas Properties (other than governmental approvals routinely acquired after
a transfer) including the non-transferability requirement of any license,
permits, right-of-way, pipeline franchise or easement, or a requirement of
renegotiation upon transfer of ownership (collectively, "Consents"), Sellers
shall request, from each party shown on Sellers' records as holding
Preferential Rights or as required to give Consents, and in accordance with
the documents creating such rights, waivers of the Preferential Rights and
Consents. If a party from whom a waiver of a Preferential Right is requested
refuses to give such waiver, Sellers shall tender (at a price determined by
the documents creating the Preferential Rights) the Oil and Gas Properties
affected by such unwaived Preferential Right and if, and to the extent that,
such Preferential Right is exercised by the holder thereof, and such interest
in the Oil and Gas Property is actually sold pursuant to such right, such
interest in the Oil and Gas Properties shall be excluded from the sale and
purchase of Assets contemplated hereby and the Purchase Price shall be reduced
by the amount allocated to such Oil and Gas Property as set forth in Schedule
2.3 hereto, or if not so set forth, by the amount so determined by mutual
agreement of the parties hereto. All Oil and Gas Properties for which a
Preferential Right has not been asserted prior to the Closing by the holder of
such right shall be sold to Purchaser at the Closing pursuant to the
provisions of this Agreement. Except that the Purchaser at its option shall
exclude such Preferential Right properties if no written consent is given and
reduce the Purchase Price dollar-for-dollar by the amount set forth on
Schedule 2.3 hereto, or if not so set forth, by the amount so determined by
mutual agreement of the parties hereto. If any holder of Preferential Rights
notifies Sellers subsequent to the Closing that it intends to assert its
Preferential Rights, Sellers shall give notice thereof t Purchaser, whereupon
Purchaser shall satisfy such Preferential Rights and all other obligations of
Sellers to such holder. Sellers shall have no obligation hereunder other than
to request waivers of Preferential Rights and to request Consents (including,
without limitation, Sellers shall have no obligation to assure that such
waivers of Preferential Rights or Consents are obtained).
If the Sellers sell any of their interest in the Assets, subject to any
Preferential Rights and Consents Sellers shall provide Purchaser, in writing
the name of the purchaser of such Assets and the purchase price thereof within
ten (10) days of the third parties notice to Sellers.
5.4 Operating Agreement. With the exception of the Wil E. Coyote
#1-26 and the Wil E. Coyote #2-26 wells, Sellers own the controlling working
interest in the Assets subject to operating agreements, and agree to transfer
operations to Purchaser subject to the Model 82 operating agreement
controlling such Assets, or such other documents or regulatory orders
controlling the Assets.
SECTION 6. COVENANTS OF PURCHASER
6.1 Confidentiality. Purchaser shall cause the Sellers Data
furnished or made available to Purchaser and its officers, employees, agents
and representatives in connection with this Agreement or in connection with
Purchaser's investigation of the Assets to be maintained strictly confidential
and not be used for any purpose other than in connection with this Agreement
and Purchaser's investigation of the Assets until the earlier to occur of:
(a) the Closing, (b) such time as the Sellers Data in question is disclosed to
Purchaser by a third party that is not obligated to Sellers to maintain such
information in confidence, or (c) such time as the Sellers Data in question
becomes generally available to the oil and gas industry other than through a
breach of confidentiality obligation to Sellers from Purchaser.
6.2 Return of Sellers Data. Purchaser agrees that if this
Agreement is terminated for any reason whatsoever prior to the Closing,
Purchaser shall return to Sellers all Sellers Data, workpapers, information
and other materials (including copies, extracts thereof) furnished by Sellers
to Purchaser or its officers, employees, agents and representatives in
connection with this Agreement without retaining any copies thereof.
SECTION 7. COVENANTS OF SELLERS AND PURCHASER
7.1 Performance of Obligations. Upon the terms and subject to the
conditions set forth in this Agreement, Sellers and Purchaser shall each use
its best efforts to take, or cause to be taken, as promptly as practicable,
all such actions and cause to be done all of the things necessary or
appropriate to carry out its obligations under this Agreement and to
consummate and make effective the transactions contemplated hereby, including,
without limitation, fulfilling all conditions to this Agreement.
7.2 Public Statements. Prior to the Closing, Sellers and
Purchaser shall consult with each other prior to issuing any press release or
otherwise making any public statement with respect to this Agreement or the
transactions contemplated hereby, and shall not issue any such press release
or make any such public statement prior to such consultation or if either
objects thereto, unless the same is required by applicable law based on the
advice of legal counsel.
7.3 Notification of Certain Matters. Sellers and Purchaser shall
each give prompt oral and written notice to the other of (a) the occurrence,
or failure to occur, of any event the occurrence or failure of which would be
reasonably likely to cause any representation or warranty contained in this
Agreement to be untrue or inaccurate in any material respect at any time from
the date hereof to and on the Closing Date, and (b) any material failure on
its part to comply with or satisfy any material covenant, condition or
agreement to be complied with or satisfied by it hereunder.
7.4 Governmental Notification and Approvals. Sellers and
Purchaser shall promptly prepare and file any documents required by law to be
filed with any governmental or regulatory authority in order to permit the
consummation of the transactions contemplated hereby.
7.5 Consents. Sellers and Purchaser shall use their best efforts
to obtain all consents, authorizations, permits, licenses, orders, approvals
and declarations of, and make all filings and registrations with, and give all
required notices to, any governmental or regulatory authority or third party
necessary to consummate the purchase and sale of the Assets contemplated
hereby, including, but not limited to, the waiver or release of all mortgages
and other liens on the Assets.
SECTION 8. TITLE DEFECTS, CASUALTY LOSSES AND GAS IMBALANCES
8.1 Definition of Title Defect. As used in this Agreement, the
term "Title Defect" shall mean the following:
(a) Sellers' ownership of an Oil and Gas Property is such that,
with respect to a well or lease listed on Schedule 1.1.1 hereto, it clearly
(i) entitles Sellers to receive a decimal share of the oil, gas and other
hydrocarbons produced from, or allocated to, such well or lease which is less
than the decimal share set forth on Schedule 1.1.1 hereto in connection with
such well or lease in the column headed "Net Revenue Interest" (or words of
similar import), or (ii) causes Sellers to be obligated to bear a decimal
share of the cost of operation of such well or lease greater than the decimal
share set forth on Schedule 1.1.1 hereto in connection with such well or lease
in the column headed "Working Interest" (or words of similar import) without a
corresponding increase in Net Revenue Interest; or
(b) Sellers' ownership of an Asset is subject to a lien, charge
or encumbrance other than (i) a lien, charge or encumbrance set forth on
Schedule 1.1.1 hereto, (ii) materialmen's, mechanic's, repairmen's,
employee's, contractor's, operator's, tax or any similar liens and charges
arising in the ordinary course of business for obligations that are not
delinquent or that will be paid and discharged by Sellers or, if delinquent,
that are being contested in good faith by appropriate action; (iii) lessors'
royalties, overriding royalties, reversionary interests and similar burdens if
the net cumulative effect of the burdens does not operate to reduce
substantially the interests of Sellers with respect to all oil and gas
produced from any well listed on Schedule 1.1.1 hereto below the Net Revenue
Interests for such well set forth on Schedule 1.1.1 hereto; (iv) division
orders and sales contracts terminable without penalty upon no more than 120
days notice to the Purchaser; (v) Preferential Rights and required Consents
and similar agreements with respect to which waivers or consents are obtained
from the appropriate parties or the appropriate time period concerning any
Preferential Right has expired without an exercise of the Preferential Right;
(vi) rights to consent by, required notices to, filings with, or other actions
by governmental entities in connection with the sale or conveyance of oil and
gas leases or interests therein if they are customarily obtained subsequent to
the sale or conveyance; (vii) conventional rights of reassignment requiring
notice to the holders of the rights; (viii) easements, rights-of-way,
servitude, permits, surface leases, and other rights in respect of surface
operations; (ix) all other liens, charges, encumbrances, contracts,
agreements, instruments, obligations, defects and irregularities affecting the
leases or the wells which individually or in the aggregate are not such as to
interfere substantially with the operation, value or use of any of the leases
or wells located thereon listed on Schedule 1.1.1 hereto, do not substantially
prevent Purchaser from receiving the proceeds of the production from any of
the leases or wells listed on Schedule 1.1.1 hereto, do not substantially
reduce the interest of Sellers with respect to all oil and gas produced from
any lease or well listed in Schedule 1.1.1 below "Net Revenue Interest" set
forth in Schedule 1.1.1 hereto for such lease or well and do not substantially
increase the portion of the costs and expenses related to the lease or well
listed on Schedule 8.1 hereto that Sellers is obligated to pay above the
"Working Interest" set forth on Schedule 1.1.1 hereto for such lease or well
without a corresponding increase in the Net Revenue Interest for such lease or
well; (x) rights reserved to or vested in any governmental, statutory or
public authority to control or regulate any of the Assets in any manner, and
all applicable laws, rules and orders of governmental authority; (xi) any
Title Defects as Purchaser may have expressly waived in writing or which are
deemed to have been waived and (xii) the terms and conditions of all leases,
agreements, orders, instruments and documents expressly described in or
referred to in Schedule 1.1.1 hereto and the production imbalances listed in
Schedule 1.1.1 hereto; or
(c) An Asset that has been cited in writing by any
governmental or regulatory authority for a violation of any applicable
Environmental Laws.
8.2 Notice of Title Defects Purchaser may, to the extent it
deems appropriate, conduct such title examination or investigation, or such
other examinations and investigations, as it may choose to conduct with
respect to the Assets. Should, as a result of any such examination or
investigation or otherwise, matters come to Purchaser's attention which would
constitute Title Defects that Purchaser is unwilling to waive, Purchaser shall
notify Sellers in writing of the existence of such Title Defects promptly
after discovering such Title Defects, but in no event later than ten business
days prior to the Closing Date.
8.3 Remedies for Title Defects. In the event that Purchaser
timely notifies Sellers of any Title Defect in accordance with the provisions
of Section 8.2 hereof, then Sellers shall have the right, but not the
obligation, to attempt to cure, prior to the Closing, such asserted Title
Defect, and shall also have the right (which may be exercised at any time
before the Closing Date) to postpone the Closing by designating a new Closing
Date not later than 30 days after the Closing Date set forth in Section 11.1
hereof if Sellers desire additional time to attempt to cure (including
determining if it will attempt to cure) one or more asserted Title Defects.
With respect to any Title Defect that Sellers elect not to cure or that
Sellers fail to cure within 30 days after receiving notice of the Title
Defect, the Purchase Price shall be adjusted in accordance with the following
guidelines:
(a) If the Title Defect is based upon Purchaser's notice that
Sellers own a lesser Net Revenue Interest than that shown on Schedule 1.1.1
hereto, then the portion of the Purchase Price allocated on Schedule 2.3
hereto to the affected Asset shall be reduced in the same proportions that the
actual Net Revenue Interest bears to the Net Revenue Interest shown on
Schedule 2.3 hereto for such Assets dollar for dollar.
(b) If the Title Defect cannot be accommodated pursuant to
clause (a) above and the parties cannot otherwise agree upon appropriate
adjustment to the Purchase Price or Sellers cannot or do not cure the Title
Defect to the reasonable satisfaction of Purchaser prior to the Closing for
the Asset affected by the Title Defect such Asset shall be excluded from the
Assets sold and purchased at the Closing, and the Purchase Price shall be
reduced by an amount allocated to the affected Asset on Schedule 2.3.
(c) Purchaser may only adjust the Purchase Price for Title
Defects at the Closing if the cumulative amount of such Title Defects equals
or exceeds one--quarter of one percent (1/4 of 1%) of the Base Purchase Price.
Such percentage is a threshold, and when exceeded adjustments to the Purchase
Price shall be made in the amount of the Title Defects.
(d) If the Purchase Price is adjusted at the Closing as a result
of an Asset affected by a Title Defect being excluded from the Assets sold and
purchased at the Closing, and if Sellers can demonstrate to Purchaser's
reasonable satisfaction that the Title Defect has been cured within 90 days
after the Closing Date, then Purchaser shall be obligated to purchase such
Asset and to pay to Sellers the amount of the adjustment to the Purchase Price
as a result of the exclusion of the Asset from the sale and purchase at the
Closing, without interest, within 30 business days from the date the parties
agree the Title Defect has been cured.
8.4 Casualty Loss. If, prior to the Closing, any of the Assets
are damaged or destroyed by fire, storms, floods, washouts, lightening,
earthquakes, or other casualty resulting from acts of god or sabotage,
insurrections, civil disturbance, riots, or vandalism ("Casualty Defects") in
an amount exceeding one percent (1%) of the Base Purchase Price, Sellers shall
notify Purchaser promptly after Sellers learn of such event. Sellers shall
have the right, but not the obligation, to cure any such Casualty Defect by
repairing such damage or, in the case of personal property or fixtures,
replacing the Assets affected thereby with equivalent items, no later than the
Closing Date. If any uncured Casualty Defect exists at the Closing, Purchaser
shall proceed to purchase the Assets affected thereby, and the Purchase Price
shall be reduced by the aggregate reduction in the value of the Assets on
account of such Casualty Defects, as determined by mutual agreement of the
parties. If the parties fail for any reason to agree prior to the Closing on
the amount of any Purchase Price adjustment on account of any Casualty Defect,
Purchaser shall exclude any Asset affected by a Casualty Defect from the
Assets to be purchased and sold at the Closing, and the affected Asset shall
be treated as if it had a Title Defect and the procedure provided in Section
8.3 hereof shall be applicable thereto.
8.5 Gas Imbalances. Purchaser and Sellers agree that the
Purchase Price shall be adjusted at the Closing to account for gas imbalances
affecting the Assets. If the total amount of overproduced gas exceeds the
total amount of underproduced gas, then the Purchase Price shall be reduced by
the product of (i) an amount (in MCF) equal to (A) the total amount of
overproduced gas related to the Assets as of the Effective Date, less (B) the
total amount of total underproduced gas related to the Assets as of the
Effective Date, as set forth on Schedule 8.5 hereto, multiplied by (ii)
$2.00 per MCF. The Purchase Price may be adjusted at the Closing for gas
imbalances only if, and only to the extent that, the aggregate amount of such
gas imbalances exceeds 10,000 MCF.
SECTION 9. CONDITIONS PRECEDENT TO THE OBLIGATIONS OF SELLERS
The obligations of Sellers to sell and deliver the Assets to Purchaser
and to perform its other obligations hereunder are subject to the fulfillment
(or waiver in writing by Sellers) at or prior to the Closing of each of the
following conditions:
9.1 Representations and Warranties. Each and every representation
and warranty of Purchaser set forth in this Agreement shall be true and
correct in all material respects as of the date when made and as of the
Closing, except for changes in the ordinary course of business consistent with
past practices and except to the extent contemplated by this Agreement.
9.2 Performance. Purchaser shall have performed, satisfied and
complied in all material respects with all covenants, agreements, obligations
and conditions under this Agreement which are to be performed, satisfied or
complied with by Purchaser at or prior to the Closing.
9.3 Pending Matters. No action, suit or other proceeding shall
be pending or overtly threatened against Sellers or Purchaser by or before any
court or governmental authority which seeks to restrain, enjoin or otherwise
prohibit the consummation of the transactions contemplated by this Agreement.
9.4 Deliveries at Closing. Purchaser shall have delivered to
Sellers at the Closing the Purchase Price as adjusted and each of the
certificates, instruments, documents and writings required hereunder.
SECTION 10. CONDITIONS PRECEDENT TO THE OBLIGATIONS OF PURCHASER
The obligations of Purchaser to purchase and acquire the Assets from
Sellers and to perform its other obligations hereunder are subject to the
fulfillment (or waiver in writing by Purchaser) at or prior to the Closing of
each of the following conditions:
10.1 Representations and Warranties. Each and every
representation and warranty of Sellers wherever they might appear in this
Agreement shall be true and correct in all material respects as of the date
when made and as of the Closing, except for changes in the ordinary course of
business.
10.2 Performance. Sellers shall have performed, satisfied and
complied in all respects with all covenants, agreements, obligations and
conditions under this Agreement which are to be performed, satisfied or
complied with by Sellers at or prior to the Closing.
10.3 Pending Matters. No action, suit or other proceeding shall
be pending or overtly threatened against Sellers or Purchaser by or before any
court or governmental authority which seeks to restrain, enjoin or otherwise
prohibit the consummation of the transactions contemplated by this Agreement.
10.4 Deliveries at Closing. Sellers shall have delivered to
Purchaser at the Closing the Assets and each of the certificates, instruments,
documents, and writings required hereunder, and an executed bill of sale or
warranty deed.
SECTION 11. CLOSING
11.1 Time and Place. The consummation of the sale and purchase of
the Assets contemplated hereby (the "Closing") shall take place at the offices
of Patrick Energy Corp., at 5:00 p.m. Central time, on the later of (a)
January 18, 2000 or (b) such other time, date or place as the parties shall
mutually agree but no later April 5, 2000. The date and time of the Closing
is sometimes herein referred to as the "Closing Date."
11.2 Deliveries by Sellers. At the Closing, Sellers shall deliver
to Purchaser the following:
(a) Possession of the Assets;
(b) Duly executed deeds, bills of sale, assignments and such
other instruments of sale, assignment and transfer in order to vest in
Purchaser all of Sellers' right, title and interest in and to the Assets; the
Assets shall be conveyed by Sellers to Purchaser by assignment and conveyance
in the form set forth in Exhibit A, attached hereto and incorporated herein by
reference; the rights-of-way and easement shall be conveyed by Sellers to
purchaser by an assignment and conveyance in the form set forth in Exhibit B,
attached hereto and incorporated herein by reference; the existing gas
purchase contract rights shall be assigned by Sellers to Purchaser utilizing
the form set forth in Exhibit C attached hereto and incorporated herein
reference;
(c) To the extent then available, duly executed transfer orders,
letters in lieu of transfer orders or similar documentation in form mutually
acceptable to Purchaser and Sellers to direct that all distribution of
production from the Oil and Gas Properties be made for the benefit of
Purchaser;
(d) To the extent then available and at Purchaser's option, duly
executed change of operator forms on all wells (active or inactive) operated
by Sellers, as required by the applicable state regulatory body, to effect a
change of operator for the Oil and Gas Properties to the extent any applicable
operating agreement authorizes such a change of operator; and
(e) A Certificate of Good Standing issued by the Secretary of
State of Oklahoma confirming that the Companies are duly incorporated, validly
existing and in Good Standing;
(f) All other items required to be delivered by Sellers to
Purchaser pursuant to any provision of this Agreement; and
(g) The existing Operating Agreements.
11.3 Deliveries by Purchaser At the Closing, Purchaser shall
deliver to Sellers the following:
(a) By wire transfer of immediately available funds to an
account designated by Sellers, an amount equal to (i) the Base Purchase Price
as adjusted, less (ii) the Deposit;
(b) Evidence of any appropriate bond, surety letters or letters
of credit as may be required by any federal or state governmental or
regulatory authority dealing with plugging of any dry or inactive wells
including any Assets;
(c) Duly executed forms as Sellers may reasonably require for
Purchaser to succeed Sellers with respect to the Assets under the rules and
regulations of applicable authorities and for Purchaser to assume any plugging
liabilities with respect to Sellers with respect to the wells located on the
Assets or in units in which the Assets participate if applicable; and
(d) All other items required to be delivered by Purchaser to
Sellers pursuant to any provision of this Agreement.
11.4 Effectiveness of Closing No action to be taken or delivery
to be made at the Closing shall be effective until all the actions to be taken
and delivery to be made at the Closing complete.
SECTION 12. FURTHER ASSURANCES
At any time and from time to time after the Closing, Sellers and
Purchaser shall execute, acknowledge and deliver all such further conveyances,
deeds, assignments, consents, permits, transfer orders, notices, assumptions
and releases, and such other documents and instruments, and shall take such
further actions, as (i) Purchaser reasonably requests and at its expense, in
order to more fully and effectively vest in Purchaser and its successors and
assigns all of Sellers' right, title and interest in and to the Assets.
SECTION 13. Intentionally Left Blank
SECTION 14. POST-CLOSING ADJUSTMENTS AND OTHER FINANCIAL MATTERS
14.1 Calculation of Adjustment to Purchase Price. Within 90 days
after the Closing, Sellers shall prepare, in accordance with the provisions of
this Agreement, and deliver to Purchaser a statement (the "Closing Statement")
setting forth each adjustment to the Purchase Price required under Sections
8.3(f) or 14.3 hereof hereunder, and showing the calculation of such
adjustments. Within 30 days of receipt of the Closing Statement, Purchaser
shall deliver to Sellers a written report ("Purchaser Report") containing all
changes with explanations therefor that Purchaser proposes to be made in the
Closing Statement, it being agreed that Purchaser's failure to deliver the
Purchaser Report to Sellers within such time period shall constitute
acceptance by Purchaser of the adjustments set forth in the Closing Statement
as prepared by Sellers. In the event of timely delivery within 30 days by
Purchaser to Sellers of the Purchaser Report no additional changes to the
Closing Statement provided by Sellers shall be considered by the parties. The
parties hereto shall use their best efforts to reach agreement on the final
Closing Statement within 30 days after the Sellers' receipt of the Purchaser
Report. If a written agreement determining the final adjustments to the
Purchase Price has not been reached within 30 days after Sellers' receipt of
the Purchaser Report, then either party may, by notice to the other, submit
for determination to a big five accounting firm selected by drawing straws,
and if such firm has worked with a party before they shall be excluded (the
"Arbitrator") the adjustments, if any, to be made to the Purchase Price in
accordance with the provisions of this Agreement. Any such determination made
by the Arbitrator shall be conclusive and binding on the parties. Nothing
herein shall be construed to (a) authorize or permit the Arbitrator to
determine any question or matter under or in connection with this Agreement,
except that the determination of what adjustments, if any, must be made in the
Purchase Price in accordance with the provisions of this Agreement, or (b)
require the Arbitrator to follow the rules and procedures of the American
Arbitration Association. The cost of any determination made by the Arbitrator
pursuant to this Section 14.1 shall be borne equally by the Purchaser and
Sellers. Within five business days after the final determination of the
adjustments to the Purchase Price by the Arbitrator or by mutual agreement, an
adjusting payment shall be made by Sellers to Purchaser or by Purchaser to
Sellers, as appropriate, in cash equal to the sum of the adjustments to the
Purchase Price.
14.2 Suspended Funds. With respect to any wells for which
operations are to be transferred to Purchaser the Sellers shall have the
responsibility for making distribution of production proceeds from the wells.
Sellers shall provide the Purchaser a listing showing all proceeds from
production attributable to the leasehold interest related to wells described
in Schedule 1.1.1 hereto which are currently held in suspense. As to those
wells, Sellers shall be responsible for proper distribution of all such
suspended proceeds to the parties lawfully entitled to them, and hereby agrees
to indemnify, defend and hold harmless Purchaser from and against any and all
Claim, liabilities, losses, costs and expenses (including without limitation
courts costs and reasonable attorney's fees) arising out of or relating to
those suspended proceeds prior to the Closing.
14.3 Receipts and Credits Subject to the terms hereof, all monies,
proceeds, receipts, credits and income attributable to the Assets for all
periods of time subsequent to the Effective Date shall be the sole property
and entitlement of Purchaser, and, to the extent received by Sellers, Sellers
shall fully disclose, account for and transmit the same to Purchaser promptly
after the Closing. All monies, proceeds, receipts and income attributable to
the Assets for all periods of time prior to the Effective Date shall be the
sole property and entitlement of Sellers and, to the extent received by
Purchaser, Purchaser shall fully disclose, account for and transmit same to
Sellers promptly. All costs, expenses, disbursements, and obligations
attributable to the Assets for periods of time prior to the Effective Date,
regardless of when due or payable, shall be a sole obligation of Sellers, and
Sellers shall promptly pay, or if paid by Purchaser, Sellers shall promptly
reimburse Purchaser for and hold Purchaser harmless from and against the same.
All costs, expenses, disbursements, obligations and liabilities attributable
to the Assets for all periods of time subsequent to the Effective Date,
regardless of when due or payable, shall be the sole obligation of the
Purchaser, and the Purchaser shall promptly pay, or if paid by Sellers,
promptly reimburse Sellers for and hold Sellers harmless from and against the
same. Sellers shall be entitled to a credit for and reimbursement in an
amount equal to any amount received by Purchaser after Closing for any
delivery or performance by Sellers prior to the Effective Date. Any
uncollected oil and gas receivables attributable to the Assets after the
Effective Date shall be assigned to Purchaser.
SECTION 15. TERMINATION
15.1 Events of Termination This Agreement may be terminated at any
time prior to the Closing:
(a) By mutual written agreement of Sellers and Purchaser;
(b) By either Sellers or Purchaser if the Closing shall not have
occurred by April 5, 2000, or such later date as mutually agreed in writing;
provided, however, that the right to terminate this Agreement under this
Section 15.1 shall not be available to any party whose breach of, or default
under, or intentional failure to fulfill its obligations under, any portion of
this Agreement has been the cause of, or resulted in, the failure of the
Closing to occur on or before such date;
(c) By Sellers if on the Closing Date any of the conditions
specified in Section 9 hereof have not been satisfied or waived or if
Purchaser shall have failed to perform, satisfy or comply with any of its
obligations, agreements or covenants to be performed, satisfied or complied
with at or prior to the Closing;
(d) By Purchaser if on the Closing Date any of the conditions
specified in Section 10 hereof have not been satisfied or waived or if Sellers
shall have failed to perform, satisfy or comply with any of its obligations,
agreements or covenants to be performed, satisfied or complied with at or
prior to the Closing;
(e) By either Sellers or Purchaser if any court of
competent jurisdiction or other governmental or regulatory authority shall
have issued, enacted, entered, promulgated or enforced any final and non-
appealable order, judgment, decree, injunction, ruling or other action
restraining, enjoining or otherwise prohibiting the purchase and sale of the
Assets contemplated hereby; or
(f) By Purchaser pursuant to Section 5.1(b).
15.2 Effect of Termination. In the event this Agreement is
terminated pursuant to Section 15.1 hereof, this Agreement shall become void
and have no further force or effect (except for the provisions of Section 2.5,
6, 17, 18.10, 18.17 and 18.18 hereof which shall survive such termination and
continue in full force and effect), without any liability on the party of any
party hereto; provided, however, that if either party hereto is in breach of
or material default under its obligations set forth in this Agreement at the
time this Agreement is so terminated, such defaulting party shall continue to
be liable to the other party for damages (but in no event for specific
performance and subject to Section 18.17 hereto) in respect of such breach or
default, and such liability shall not be affected by such termination.
SECTION 16. TAXES
16.1 Apportionment of Ad Valorem and Property Taxes All ad valorem
taxes, real property taxes, personal property taxes and similar obligations
(excluding income taxes) ("Property Taxes") with respect tot eh Assets for the
tax period in which the Effective Date occurs shall be apportioned as of the
Effective Date between Sellers and Purchaser. The owner of record as of the
assessment date shall file or cause to be filed all required reports and
returns incident to the Property Taxes and shall pay or cause to be paid to
the taxing authorities all property taxes relating to the tax period on which
the Effective Date occurs. If Sellers are the owners of record on the
assessment date, Purchaser shall pay to Sellers Purchaser's pro rata portion
of Property Taxes within 30 days after receipt of Sellers' invoice therefor.
If Purchaser is the owner of record as of the assessment date then Sellers
shall pay to Purchaser Sellers pro rata portion of Property Taxes within 30
days after receipt of Purchaser's invoice therefor. The party paying such
taxes shall supply the other party with copies of the filed reports and proof
of payment promptly after filing and paying the same. Notwithstanding the
foregoing Sellers shall be responsible for all Property Taxes on Assets
purchased by Purchaser through its ownership of the Assets and Oil and Gas
Properties due or incurred prior to the Effective Date.
16.2 Sales Taxes. The Purchase Price provided for hereunder excludes
any sales taxes or other taxes required to be paid in connection with the
purchase and sale of Assets pursuant to this Agreement. Purchaser shall be
liable for all sale and use taxes, conveyance, transfer and recording fees and
real estate transfer stamps or other taxes that may be imposed on any transfer
of property pursuant to this Agreement. Purchaser shall indemnify and hold
Sellers harmless with respect to, and promptly reimburse Sellers for, the
payment of any of these taxes including any interest or penalties assessed
thereon.
16.3 Other Taxes. All taxes (other than income taxes) which are
imposed on or with respect to the production of oil, natural gas or other
hydrocarbons or minerals or the receipt of proceeds therefrom (including but
not limited to severance, production and excise taxes) shall be apportioned
between the parties based upon the respective shares of production taken by
the parties. All such taxes which have accrued prior to the Effective Date
have been or will be properly paid or withheld by Sellers and all statements,
returns and documents pertinent thereto have been or will be properly filed.
Purchaser shall be responsible for paying or withholding or causing to be paid
or withheld all such taxes which have accrued after the Effective Date and for
tiling all statements, returns and documents incident thereto.
16.4 Cooperation. Each party to this Agreement shall provide the
other party with reasonable access to all relevant documents, data and other
information which may be required by the other party for the purpose of
preparing tax returns and responding to any audit by any taxing jurisdiction.
Each party to this Agreement shall cooperate with all reasonable requests of
the other party made in connection with contesting the imposition of taxes.
SECTION 17. DOCUMENT RETENTION
17.1 Inspection. As used in this Section 17, "Documents" means all
files, documents, books and records delivered to Purchaser by Sellers pursuant
to the provisions of this Agreement, including, but not limited to:
financial and tax accounting records; land, title and division of interest
files; contracts; engineering and well files; and books and records related to
the operation of the Assets. Subject to the provisions of Section 17.2
hereof, Purchaser agrees that the Documents shall be open for inspection by
the officers, employees and representatives of Sellers at reasonable times and
upon reasonable notice during regular business hours for a period of three
years following the Closing Date (or for such longer period as may be required
by law or governmental regulation), and that Sellers may during such period at
its expense make such copies thereof as it may reasonably request. Sellers
agree that such Documents as shall be retained by Sellers and that are related
to the Assets and the Companies, the conduct of Business or the operation of
the Assets and the Companies shall be open for inspection by the officers,
employee and representatives of Purchaser at reasonable times and upon
reasonable notice during regular business hours for a period of three years
following the Closing Date and that Purchaser may during such period at its
expense make such copies thereof as it may reasonable request. It is
understood and agreed for purposes of this Agreement that Sellers and
Purchaser may maintain and preserve such Documents by way of microfilm or
microfiche.
17.2 Destruction. Without limitation the generality of the
foregoing, for a period of three years after the Closing Date (or for such
longer period as may be required by law or governmental regulation), Purchaser
shall not destroy or give up possession of any original or final copy of the
Documents without first offering Sellers the opportunity, at Sellers' expense
(without any payment to Purchaser), to obtain such original or final copy or a
copy thereof. After the conclusion of such period, Purchaser shall offer to
deliver to Sellers, at Sellers' expense (without any payment to Purchaser),
the Documents prior to destroying the same.
17.3 Access. Sellers and Purchaser each shall use its best efforts
to afford the other access to (i), in the case of Sellers, employees of
Sellers who remain employees of Sellers following the date of Closing but are
familiar with the operation of the Assets and (ii), in the case of Purchaser,
employees of Purchaser which Sellers shall reasonably request for its proper
corporate purposes, including without limitation, the defense of legal
proceedings. Such access may include interviews or attendance to depositions
or legal proceedings; provide, however, that in any event all out of pocket
expenses (including wages and salaries) reasonably incurred by any party in
connection with this Section 17.3 shall be paid or promptly reimbursed by the
party requesting such services.
17.4 Delivery of Files. As soon as reasonably practicable, but no
later than 30 days after the Closing Date, Sellers shall deliver to Purchaser
copies of all files, books, records, documents, data and other information
included in the Assets, insofar as they relate to the Assets. After the
Closing, prior to such date, Sellers shall make good faith efforts to provide
any copies of such files, books, records, documents, data or information
specifically requested by Purchaser in writing. All copying and other out-of-
pocket costs incurred in connection with delivery of such files and records
hereunder shall be borne equally by Purchaser and Sellers.
SECTION 18. GENERAL PROVISIONS
18.1 Governing Law. This Agreement and all instruments executed in
accordance herewith shall be governed by and construed in accordance with the
internal laws of the State of Oklahoma, without regard to conflict of laws
provisions that would otherwise require the application of the laws of any
other jurisdiction.
18.2 Entire Agreement. This Agreement, including all Schedules
hereto, together with any confidentiality agreement, if any, relating to the
Assets hereafter or previously executed by Purchaser, constitute the entire
agreement and understanding of the parties with respect to the transactions
contemplated hereby and supersede all prior agreements, understandings,
negotiations, discussions, representations and warranties, whether oral or
written, between the parties.
18.3 Waiver. The obligations of any party hereto may be waived only
with the written consent of the party giving the waiver. Any waiver of a
breach or violation of or default under any provision of this Agreement shall
not operate as a waiver of any other breach or violation of or default under
that provision or of any other provision of this Agreement. Failure of any
party to insist on strict adherence of or compliance with any provision of
this Agreement on any one or more occasions shall not be considered a
continuing waiver or deprive the party of the right to insist upon strict
adherence or compliance with that provision in the future or with any other
provision of this Agreement.
18.4 Severability. If any term or other provision of this Agreement
is deemed or held to be invalid, illegal or unenforceable in any situation,
such illegality, invalidity or unenforceability shall not affect or impair the
legality, validity or enforceability of that provision in any other situation
or any other provision of this Agreement in any situation, and all of the
provisions of this Agreement shall nevertheless remain in full force and
effect and this Agreement shall be construed as if such a illegal, invalid, or
inenforceable provision were omitted.
18.5 Notices. All notices and other communications required or
permitted to be given under this Agreement shall be deemed to have been duly
given if in writing and if delivered personally, or by facsimile transmission
(upon confirmation of receipt), or on the first business day following the
date of dispatch if delivered by a nationally recognized next-day courier
service, or on the third business day after being sent by registered or
certified mail, return receipt request, postage pre-paid, to the parties at
the following addresses:
If to Sellers:
Continental Resources, Inc.
P.O. Box 1032
Enid, Oklahoma 73702
Attention: Tom Luttrell
Facsimile: (580) 548-5182
and to
Continental Gas, Inc.
P.O. Box 5103
Enid, Oklahoma 73702
Attention:
Facsimile: (580) 548-5188
If to Purchaser:
Patrick Energy Corp.
6120 S. Yale, Suite 810
Tulsa, Oklahoma 74136
Attention: Mark A. Patrick
Facsimile: (918) 491-6680
and to
Chester, Willcox, and Saxbe
17 South High Street, Suite 900
Columbus, Ohio 73215
Attention: J. Richard Emens
Facsimile: (614) 221-4012
Any party hereto may send any notice or any other communication to the
intended recipient using any other means, but no such notice or other such
communication shall be deemed to have been duly given until it is received by
the recipient. Any party may change its designated address by giving written
notice thereof to the other party hereto in the manner herein above provided.
18.6 Amendments. This Agreement may be amended, modified,
supplemented or restated only by an instrument in writing signed by all
parties hereto which specifically states that it amends this Agreement.
18.7 Headings. The headings set forth in this Agreement are intended
for convenience of reference only and shall not in any way be considered a
part of or affect the meaning or interpretation of any provision of this
Agreement.
18.8 Assignment. Neither party hereto shall assign this Agreement or
any of its rights or obligations hereunder without the prior written consent
of the other party hereto, and any such assignment made without such consent
shall be void (except as to an affiliate owned fifty percent (50%) or more by
the assigning party).
18.9 Successors and Assigns. This Agreement shall inure to the
benefit and be binding upon the parties hereto and their respective heirs,
successors and permitted assigns.
18.10 Expenses. Except as otherwise provided herein, each party
shall be solely responsible for all expenses incurred by it in connection with
the negotiation, preparation and execution of this Agreement and the purchase
and sale of Assets and the other transactions contemplated hereby, including,
but not limited to, all fees and expenses of its own agents, representatives,
counsel and accountants.
18.11 No Third Party Beneficiaries. Nothing in this Agreement,
express or implied, is intended or shall be construed to provide, create or
confer upon any person or entity other than the parties hereto and their
respective successors and permitted assigns any right, benefit, or remedies.
18.12 Pronouns. The number and gender of each pronoun used in this
Agreement and the term "person" or "persons" or the like shall be construed to
mean both the number and gender of the individual, corporation, partnership,
firm, trust, agency or other entity as the context, circumstance or its
antecedent may require. The terms "herein", "hereof", "hereto" and the like
refer to this Agreement as a whole.
18.13 Schedules. The Schedules attached to this Agreement are
incorporated into and made a part of this Agreement as if they were fully set
forth herein.
18.14 Counterparts. This Agreement may be executed in one or more
counterparts (including counterparts executed by one party), each of which
shall be deemed an original, but all of which together shall constitute one
and the same agreement.
18.15 Construction of Ambiguity. Sellers and Purchaser have
participated jointly in the negotiation and drafting of this Agreement. In
the event any ambiguity or question of intent or interpretation arises with
respect to any provisions of this Agreement, including any Schedules hereto,
this Agreement shall be construed as if drafted jointly by Sellers and
Purchaser and no presumption or burden of proof shall arise favoring or
disfavoring either party hereto by virtue of the authorship of any of the
provisions of this Agreement.
18.16 Consequential Damages. Except as provided elsewhere in this
Agreement, Sellers and Purchaser hereby covenant and agree that the recovery
by either party hereto of any damages suffered or incurred by it as a result
of any breach by the other party of any provision of this Agreement shall be
limited to the actual damages suffered or incurred by the non-breaching party
as a result of the breach by the breaching party, and in no event shall the
breaching party be liable to the non-breaching party for any indirect,
consequential, special, exemplary or punitive damages suffered or incurred by
the non-breaching party as a result of the breach by the breaching party.
18.17 Joint Venture, Partnership and Agency. Nothing contained
in this Agreement shall be deemed to create a joint venture, partnership, tax
partnership or agency relationship between the parties of any kind.
18.18 Time. Time is of the essence in connection with the Closing of
the sale and purchase of the Assets hereunder.
IN WITNESS WHEREOF, the parties hereto have caused this Asset Purchase
Agreement to be executed and delivered by their respective duly authorized
officers or representatives effective as of the Effective Date.
SELLERS PURCHASER
Continental Resources, Inc. Patrick Energy Corp.
HAROLD HAMM MARK PATRICK
By: Harold Hamm By: Mark Patrick
Its: President Its: Officer - Owner
Continental Gas, Inc.
RANDY MOEDER
By: Randy Moeder
Its: President
Exhibit 12.1
<TABLE>
COMPUTATION OF DEBT TO ADJUSTED EBITDA
CONTINENTAL RESOURCES, INC.
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
NET INCOME 3,869 13,325 26,197 (17,980) 3,920
INCOME TAXES 2,252 8,238 (8,941) - -
INTEREST EXPENSE 2,396 4,550 4,804 12,248 16,534
DD&A 9,614 22,876 33,354 38,716 20,385
EXPLORATION EXPENSE 6,184 4,513 6,807 7,106 7,750
LITIGATION SETTLEMENT (7,500) -
------ ------ ------ ------- ------
ADJUSTED EBITDA<F1> 24,315 53,502 54,721 40,090 48,589
TOTAL DEBT 44,265 54,759 79,632 167,639 170,637
TOTAL DEBT TO ADJUSTED EBITDA 1.8 1.0 1.5 4.2 3.5
- ----------------
<FN>
<F1> 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 by generally accepted accounting
principles ("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
computations 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.
</FN>
</TABLE>
Exhibit 12.2
<TABLE>
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGE
CONTINENTAL RESOURCES, INC.
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
EARNINGS<F1> 6,121 21,563 17,256 (17,980) 3,920
FIXED CHARGES<F2> 2,396 4,550 4,804 12,704 16,990
----- ------ ------ ------ ------
TOTAL EARNINGS & FIXED CHARGES 8,517 26,113 22,060 (5,276) 20,910
RATIO 3.6 5.7 4.6 n/a 1.2
Earnings insufficient to cover fixed charges by 17,980
_______________
<FN>
<F1> "Earnings" represents income (loss) before provision for federal and
state income taxes or income tax benefits. "Fixed charges" consist of
interest expense and amortization of costs incurred in connection with the
Offering.
<F2> To give effect to the issuance of $150 million of Senior Subordinated
Notes due 2008 with an interest rate of 10.25%. For purposes of computing
the Ratio of Earnings to Fixed Charges, interest expense includes interest
on the Senior Subordinated notes together with amortization of the under-
writing discounts and expenses of the Offering; for the period ended
December 31 1998 and 1999, amortization expense was $460,000 and $456,000,
respectively.
</FN>
</TABLE>
Exhibit 12.3
<TABLE>
COMPUTATION OF RATIO OF ADJUSTED EBITDA TO INTEREST EXPENSE
CONTINENTAL RESOURCES, INC.
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
NET INCOME 3,869 13,325 26,197 (17,980) 3,920
INCOME TAXES 2,252 8,238 (8,941) 0 0
INTEREST EXPENSE 2,396 4,550 4,804 12,248 16,534
DD&A 9,614 22,876 33,354 38,716 22,385
EXPLORATION EXPENSE 6,184 4,513 6,807 7,106 7,750
LITIGATION SETTLEMENT 0 0 (7,500) 0 0
------ ------ ------ ------ ------
ADJUSTED EBITDA<F1> 24,315 53,502 54,721 40,090 48,589
TOTAL ADJUSTED EBITDA TO
INTEREST EXPENSE 10.1 11.8 11.4 3.3 3.0
- ---------------
<FN>
<F1> ADJUSTED EBITDA represents earnings before interest expense, income
taxes, depreciation, depletion, amortization and exploration expense,
excluding proceeds from litigation settlements. EBITDA is not a measure
of cash flow as determined by generally accepted accounting principles
("GAAP"). Adjusted EBITDA should not be considered as an alternative to,
or more meaningful than, net income or cash flow as determined in ac-
cordance with GAAP or as an indicator of a company's operating per-
formance or liquidity. Certain items excluded from Adjusted EBITDA are
significant components in understanding and assessing a company's finan-
cial performance, such as a company's cost of capital and tax structure,
as well as historic costs of depreciable assets, none of which are com-
ponents of Adjusted EBITDA. The Company's computations 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.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
audited consolidated balance sheet at December 31, 1999 and consolidated
statement of operations at December 31, 1999 and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 10,421,333
<SECURITIES> 0
<RECEIVABLES> 20,025,470
<ALLOWANCES> 0
<INVENTORY> 4,111,648
<CURRENT-ASSETS> 36,248,422
<PP&E> 377,173,049
<DEPRECIATION> (138,872,122)
<TOTAL-ASSETS> 282,558,585
<CURRENT-LIABILITIES> 25,445,447
<BONDS> 150,000,000
0
0
<COMMON> 49,041
<OTHER-SE> 86,616,698
<TOTAL-LIABILITY-AND-EQUITY> 282,558,585
<SALES> 329,141,738
<TOTAL-REVENUES> 335,460,535
<CGS> 273,352,965
<TOTAL-COSTS> 313,535,236
<OTHER-EXPENSES> (266,607)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,533,973
<INCOME-PRETAX> 5,968,789
<INCOME-TAX> 0
<INCOME-CONTINUING> 5,968,789
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 2,048,455
<NET-INCOME> 3,920,335
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
