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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
[ ] 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 15, 1999, there were 49,041 shares of the registrant's
$1.00 par value Common Stock outstanding. The Common Stock is
privately held by affiliates of the registrant.
Documents incorporated by reference: None
CONTINENTAL RESOURCES, INC.
Annual Report on Form 10 - K
for the Year Ended December 31, 1998
TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
PART I
ITEM 1. BUSINESS
OVERVIEW
Continental Resources, Inc. and its subsidiaries Continental Gas,
Inc. ("CGI") and Continental Crude Co. ("CCC") (collectively
"Continental" or the "Company") are engaged in the exploration,
exploitation, development and acquisition of oil and gas reserves,
primarily in the Rocky Mountains and the Mid-Continent, and to a
growing extent, in the Gulf Coast region of Texas and Louisiana. In
addition to its exploration, development, and acquisition activities,
the Company owns and operates 1,000 miles of natural gas pipelines,
six gas gathering systems and three gas processing plants in its
operating areas. The Company also engages in natural gas marketing,
gas pipeline construction and saltwater disposal. Capitalizing on its
growth through the drill-bit and its acquisition strategy, the
Company has increased its estimated proved reserves from 16.9 million
barrels of oil equivalent ("MMBoe") in 1994 to 29.1 MMBoe in 1998,
and increased its annual production from 2.2 MMBoe in 1994 to 5.1
MMBoe in 1998. As of December 31, 1998, the Company's reserves had a
present value of estimated future net cash flows, discounted at 10%
("PV-10") of $107 million based on Securities and Exchange Commission
(the "Commission" or "SEC") guidelines. Approximately 68% of the
Company's estimated proved reserves were oil and approximately 97% of
its total estimated reserves were classified as proved developed. At
December 31, 1998, the Company had interests in 1,254 producing wells
of which it operated 1,033. The Company was originally formed in
1967 as Shelly Dean Oil Company to explore, develop and produce oil
and gas properties in Oklahoma. In 1991, the Company changed its name
to Continental Resources, Inc. 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.
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,
work overs, 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 to capitalize 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
the Texas Panhandle and, to a lesser extent, in the Arkoma Basin of
southeastern Oklahoma. At December 31, 1998 the Company's Anadarko
Basin properties represented approximately 91% of the PV-10
attributable to the Company's estimated proved reserves in the Mid-
Continent and approximately 40% of the Company's total estimated
proved reserves. In the Anadarko Basin the Company owns
approximately 65,000 net leasehold acres, has interests in 613 gross
(366 net) producing wells and has identified 8 potential drilling
locations.
The Company also owns leasehold interests in the Arkoma Basin and
Gulf Coast region of Texas and Louisiana and expects to expand its
exploration activities in the Gulf Coast region during 1999. 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 no
significant PV10 value but the Company expects these properties to
represent a primary reserve growth opportunity for the Company during
1999. From a combined total of 60 square miles of proprietary 3-D
data, 21 development and 7 exploratory locations have been identified
for drilling on these projects to date. The Company is working to
develop 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 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 41% of the PV10 attributable to the
Company's estimated proved reserves at December 31, 1998. 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 425,000 net leasehold acres and has
interests in 307 gross (236 net) wells, has identified 52 potential
drilling locations and conducts both primary and enhanced recovery
operations. As of December 31, 1998, the Company operated one-half of
the high pressure air injection projects in North America. The
Company recently expanded its activities into the Big Horn Basin
through the acquisition of producing and non-producing properties in
the Worland Field. The Company currently owns approximately 40,000
net leasehold acres in the Big Horn Basin and has interests in 280
gross (122 net) producing wells, 260 company operated, which
represented approximately 12% of the PV10 attributable to the
Company's estimated proved reserves at December 31, 1998. In the Big
Horn Basin the Company has identified 170 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.
In July 1998 the Company completed a private offering of $150
million principal amount of its 10-1/4% Senior Subordinated notes due
2008 (the "Notes").
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. During the five years ended December 31, 1998, the
Company increased its proved reserves by 172% and production by 234%.
SUBSTANTIAL DRILLING INVENTORY. The Company has identified over
230 potential drilling locations based on geological and geophysical
evaluations. As of December 31, 1998 the Company held approximately
551,000 net acres, of which approximately 62% 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 RECORD. The Company has maintained a
successful drilling record. In the blanket type Red River B formation
of the Williston Basin, the Company's success rate during the three
years ended December 31, 1998 was 96%, while in its other areas, the
success rate was 80%, resulting in an overall success rate of 94%.
During the five years ended December 31, 1998, the Company
participated in 264 gross (183 net) wells which resulted in the
addition of 18.8 MMBoe of proved developed reserves at an average
finding cost of $7.22 per Boe.
SIGNIFICANT OPERATIONAL CONTROL. Approximately 95% of the
Company's PV10 at December 31, 1998 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 and precision horizontal drilling, and is among the few
companies in North America to successfully utilize high pressure air
injection ("HPAI") enhance 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 165 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 20 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 20 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, work overs, recompletions and HPAI projects. During 1999 the
Company projects that development drilling will represent 85% of the
wells drilled. The majority of this development drilling will be
focused on the Mid-Continent and Gulf Coast Regions where the Company
has identified 26 drilling opportunities, of which 70% target natural
gas reserves. This drilling inventory is expected to increase during
the year since the Company's geo-scientists currently are focused on
generating opportunities and evaluating 3-D seismic data in the Mid-
Continent and Gulf Coast Regions. Development drilling in the Rocky
Mountain Region will remain nominal without commodity price
improvements over prices at December 31, 1998. Approximately 89% of
the Company's development drilling inventory, representing 210 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 glean opportunities and increase production
from its substantial inventory of 118 work overs and recompletions in
the Rockies as well as the 33 located in the Mid-Continent and Gulf
Coast Regions. The unitization process required to install HPAI in
the Cedar Hills and West Medicine Pole Hills Fields will continue
with target dates for initial injection to begin in quarter four of
2000 and quarter four of 1999, respectively. The following table sets
forth the Company's development inventory as of December 31, 1998.
NUMBER OF DEVELOPMENT PROJECTS
------------------------------------------------
ENHANCED
DRILLING WORK OVERS AND RECOVERY
LOCATIONS RECOMPLETIONS PROJECTS TOTAL
--------- -------------- -------- -----
ROCKY MOUNTAINS:
Williston Basin. . . 48 10 2 60
Big Horn Basin . . . 162 108 - 270
MID-CONTINENT:
Anadarko Basin . . . 5 32 2 39
GULF COAST . . . . . . 21 1 - 22
--- --- --- ---
TOTAL. . . . . . . . . 236 151 4 391
=== === === ===
The Company will initiate, on a priority basis, as many projects
as available cash allows. Based on forecasted cash flow, the Company
anticipates initiating 9 drilling projects, 10 work over projects and
1 enhanced recovery project. In addition, the Company expects to
complete 1 well acquisition and 3 infrastructure development
projects. The Company expects to make $10.7 million in capital
expenditures related to these projects in 1999.
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 1999 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 22 exploratory wells in inventory.
The following table sets forth information pertaining to the
Company's existing exploration project inventory at December 31,
1998:
NUMBER OF EXPLORATION PROJECTS
DRILLING LOCATION 3-D SEISMIC
----------------- -----------
ROCKY MOUNTAINS:
Williston Basin . . . . . . . . 4 2
Big Horn Basin . . . . . . . . 8 1
MID-CONTINENT . . . . . . . . . . 3 -
GULF COAST . . . . . . . . . . . 7 2
--- ---
TOTAL . . . . . . . . . . . . . . 22 5
=== ===
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 utilization 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 15, 1999, the Company employed 194 people, 73 of which
were administrative personnel, 10 of which were geological personnel,
11 of which were engineers and the remainder 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 1998 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 3% of the Company's estimated proved reserves
at December 31, 1998 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 its 10-1/4% Senior Notes due 2008
("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, 1998, the estimated
future net cash flows and PV-10 of $171.3 million and $107.7 million,
respectively, attributable to the Company's proved oil and gas
reserves are based on prices in effect at that date ($10.84 per
barrel ("Bbl") of oil and $1.64 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, 1998, on a consolidated basis, the Company and the
Subsidiary Guarantors had $167.6 million of indebtedness (including
short term debt and current maturities of long-term indebtedness)
compared to the Company's stockholders' equity of $60.3 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 "Unaudited
Consolidated Financial Statements," "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 at 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 15, 1999 was $8.6
million exclusive of $16.4 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 arrange-
ments, 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 $.7 million of transportation costs
and related expenses, was $4.1 million for twelve months ended
December 31, 1998. The Company's current policy is to limit its
exposure from open positions to $1.0 million at any one time. At
December 31, 1998 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 and Properties--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 SHAREHOLDER
At March 15, 1999, Harold Hamm, 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,
Harold Hamm is in a position to control the Company. The Company is
provided oilfield services by several affiliated companies controlled
by Harold Hamm. 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 Harold Hamm 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 465,000 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 68% of its estimated proved reserves on
a BOE basis at December 31, 1998 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, 86% of the Company's drilling inventory is
focused on further expansion and development of its Rocky Mountain
oil fields, and the remaining 14% is focused on natural gas projects
in the Mid-Continent and Gulf Coast. The Company's Gulf Coast
activities are conducted onshore the Texas and Louisiana coasts. In
the Gulf Coast, the Company holds approximately 9,400 net leasehold
acres and has identified 28 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, 1998:
PERCENT OF
DISCOUNTED TOTAL
OIL FUTURE CASH DISCOUNTED
OIL GAS EQUIVALENT FLOWS FUTURE CASH
AREA (MBBL) (MMCF) (MBOE) (M $) FLOWS
- ---- ------ ------ ---------- ----------- -----------
ROCKY MOUNTAINS:
Williston Basin. . 11,923 4,497 12,670 $47,981 44.5%
Big Horn Basin . . 6,053 9,084 7,567 12,417 11.5
MID-CONTINENT:
Anadarko Basin . . 1,930 37,598 8,197 42,627 39.6
Arkoma Basin . . . 2 3,614 604 4,175 3.9
GULF COAST . . . . . 22 426 93 470 0.5
------ ------ ------ -------- -----
TOTALS . . . . . . . 19,930 55,219 29,131 $107,670 100.0%
====== ====== ====== ======== =====
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, 1998 totaled 20.2 MMBoe
and represented 56.1% of the Company's PV-10. Approximately 96% of
these estimated proved reserves are proved developed. During the
twelve months ended December 31, 1998, the average net daily
production was 8,930 Bbls of oil and 1,650 Mcf of natural gas, or
9,205 Boe per day from the Rocky Mountain properties excluding the
Worland Field Properties which were purchased June 1, 1998. As of the
June 1, 1998 acquisition date, the Worland properties added 1,138
Bbls of oil per day and 2,186 Mcf of natural gas, or 1,502 Boe per
day. As of December 31, 1998 the company is producing approximately
9,550 Boe per day with another 750 Boe per day shut in due to the low
oil prices. The Company's leasehold interests include 141,378 net
developed and 323,606 net undeveloped acres, which represent 26% and
59% 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, 1998, the
Company's Rocky Mountain properties included an inventory of 210
development and 12 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, 1998, the Cedar Hills Field properties
produced 6,778 net Boe per day to the Company interests and
represented 41% of the PV-10 attributable to the Company's estimated
proved reserves as of December 31, 1998. 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, 1998, the Company drilled or participated
in 153 gross (103 net) horizontal wells, of which 146 were
successfully completed, for a 95% 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 1999. 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 also claims
that the consultant relied on such false and misleading information
in determining the relative fair values of the oil and gas interests.
The Company seeks a declaratory judgment determining that it is
excused from further performance under its exchange agreement with
Burlington. Burlington has denied the Company's allegations and seeks
specific performance by the Company, plus monetary damages of an
unspecified amount. The progress on the Cedar Hills Unitization
process is expected to continue, as the North Dakota Industrial
Commission has called a hearing for March 31, 1999 to discuss the
status of the unitization process. The timing and probability of
unitization will only be enhanced by the state's objective to invoke
their wide range of authority, including the ability to restrict
production, which will be targeted towards preserving the value of
the field and ensuring that secondary recovery reserves are captured.
As of December 31, 1998, there were 7 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, 1998, these units produced 2,147
Boe per day, net to the Company's interests, and represented .7 MMBoe
or 4% of the PV-10 attributable to the Company's estimated proved
reserves as of December 31, 1998. 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 44 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. The
Company plans to further develop these units and enhance production
by drilling strategically placed horizontal wells. There are
currently 38 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, 1998, produced 280 Bbls per day, net to the Company's
interests. Wells in both the Lustre and Midfork Fields produce from
the Charles "C" dolomite, at depths of 5,500 to 6,000 feet.
Historically, production from the Charles "C" has a low daily
production rate and is long lived. There are currently 21 wells
producing in the two fields, and no secondary recovery is underway in
either field. The Company currently owns 87,000 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 shareholder, for $42.6 million. The
sale of the 50% interest in the Worland Field properties was effected
to reduce the size of the Company's exposure in one area, to reduce
the amount of future capital expenditures by the Company and to
reduce the Company's investment in oil, rather than natural gas,
properties. See "Certain Relationships and Related Transactions." The
Worland Field properties cover 40,000 net leasehold acres in the
Worland Field of the Big Horn Basin in northern Wyoming, of which
16,000 net acres are held by production and 24,000 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 Company's Worland Field properties include interests in
280 producing wells, 260 of which are operated by the Company.
As of December 31, 1998, the estimated net proved reserves
attributable to the Company's Worland Field properties were
approximately 7.6 MMBoe, with an estimated PV-10 of $12.4 million.
Approximately 80% 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 March 1, 2000.
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, eight exploratory drilling
prospects have been identified on the Company's Worland Field
properties in which prospects the Company and its principal
shareholder, together, have 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, 1998, the
Company's estimated proved reserves in the Mid-Continent totaled 8.8
MMBoe, representing 43.5% of the Company's PV-10 at such date. At
December 31, 1998 approximately 78% of the Company's estimated proved
reserves in the Mid-Continent were natural gas. Net daily production
from these properties during 1998 averaged 1,302 Bbls of oil and
15,172 Mcf of natural gas, or 3,830 Boe to the Company's interests.
The Company's Mid-Continent leasehold position includes 67,712 net
developed and 8,927 net undeveloped acres, representing 12% and 2% of
the Company's total leasehold, respectively, at December 31, 1998.
As of December 31, 1998, the Company's Mid-Continent properties
included an inventory of five development drilling locations, all of
them in the Anadarko Basin.
ANADARKO BASIN. The Anadarko Basin properties contained 93% of
the Company's estimated proved reserves for the Mid-Continent and
39.6% of the Company's total PV-10 at December 31, 1998 and at such
date, represented 68% of the Company's estimated proved reserves of
natural gas. During the twelve months ended December 31, 1998, net
daily production from its Anadarko Basin properties averaged 1,231
Bbls of oil and 13,815 Mcf of natural gas, or 3,533 Boe to the
Company's interest from 613 gross (366 net) producing wells, 457 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
work over potential.
ARKOMA BASIN. In the Arkoma Basin, the Company is focused on coal
bed methane, where it owns approximately 12,000 acres and has 44
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, are
being marketed for sale. The PV-10 of the reserves on these
properties is approximately $4.2 million, whereas the Company has an
offer of intent to purchase for $5.8 million from a third party.
Closing on this transaction is scheduled for April 1, 1999.
GULF COAST
The Company's Gulf Coast activities are located in the Jefferson
Island Project, Iberia Parish , Louisiana and in the Pebble Beach
Project , Nueces Co., Texas. These properties currently provide no
significant PV-10 value but do represent significant drilling
opportunities for 1999 and beyond. The Company's Gulf Coast
leasehold position includes 1,235 net developed and 8,169 net
undeveloped acres representing 0.6% and 2.4% of the Company's total
leasehold respectively. From a combined total of 60 square miles
of proprietary 3-D data , 21 development and 7 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 controls 5,062 gross (2,913 net) acres
over the entire salt dome and has identified 19 development and 1
exploratory drilling locations to date from 35 square miles of
proprietary 3-D seismic. The Company has an agreement with a third
party who in return for performing certain obligations will earn 50%
of the project. These obligations require the third party to pay
100% of seismic costs and 100% of drilling costs for the first 5
wells as well as provide the Company with a 16% carried interest in
each of the first 5 wells. Drilling is scheduled to begin early
second quarter 1999.
PEBBLE BEACH. At the Pebble Beach project the Company owns 7,078
gross (6,491 net) acres and is targeting the prolific Frio and
Vicksburg sands underlying the Clara Driscoll field and surrounding
area. These sandstone reservoirs are found at depths of 5000' to
9500' and produce on structures readily defined with 3-D seismic.
Using 20 square miles of proprietary 3-D seismic, 2 development
and 5 exploratory drilling locations have been identified. Drilling
should begin third quarter 1999.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to
oil and gas production, prices and costs attributable to all oil and
gas property interests owned by the Company for the periods shown:
YEAR ENDED DECEMBER 31
---------------------------
1996 1997 1998
---- ---- ----
NET PRODUCTION DATA:
Oil and condensate (MBBL). . . . . . 2,888 3,518 3,981
Natural gas (MMCF) . . . . . . . . . 6,527 5,789 6,755
Total (MBOE) . . . . . . . . . . . . 3,976 4,483 5,107
UNIT ECONOMICS
Average sales price per Bbl. . . . . $ 20.78 $ 18.61 $ 12.38
Average sales price per Mcf. . . . . 2.13 2.21 1.61
Average equivalent price (per Boe) 18.87 17.53 11.78
Lifting cost (per Boe) . . . . . 4.86 4.63 4.43
DD&A expense (per Boe) . . . . . 5.44 6.74 6.78
General and administrative expense
(per Boe) . . . . . . . . . . . 1.64 1.47 1.40
--------- --------- ---------
Gross margin . . . . . . . . . . . . $ 6.93 $ 4.69 $ (0.83)
========= ========= =========
Calculated by dividing oil and gas revenues, as reflected in the
Consolidated Financial Statements, by production volumes on a Boe
basis. Oil and gas revenues reflected in the Consolidated Financial
Statements are recognized as production is sold and may differ from
oil and gas revenues reflected on the Company's production records
which reflect oil and gas revenues by date of production.
See "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
Related to drilling and development activities.
Related to drilling and development activities, net of operating
overhead income.
PRODUCING WELLS
The following table sets forth the number of productive wells in
which the Company owned an interest as of December 31, 1998:
OIL NATURAL GAS
---------------- -------------------
GROSS NET GROSS NET
----- --- ----- ---
ROCKY MOUNTAINS:
Williston Basin . . . 307 236 - -
Big Horn Basin. . 280 122 - -
MID-CONTINENT:
Anadarko Basin . . . 377 258 236 108
Other . . . . . . . . 5 4 39 32
GULF COAST . . . . . . 6 3 4 2
--- --- --- ---
Total . . . . . . . . 975 623 279 142
=== === === ===
Represents Worland Field properties acquired by the Company in
the Worland Field Acquisition.
ACREAGE
The following table sets forth the Company's developed and
undeveloped gross and net leasehold acreage as of December 31, 1998:
DEVELOPED UNDEVELOPED
-------------------- ------------------
GROSS NET GROSS NET
----- --- ----- ---
ROCKY MOUNTAINS:
Williston Basin. . 166,597 125,708 396,805 299,695
Big Horn Basin . . 30,126 15,670 45,690 23,911
MID-CONTINENT:
Anadarko Basin . . 91,546 55,981 14,120 8,551
Other. . . . . . . 12,291 11,731 520 376
GULF COAST . . . . . 1,355 1,235 10,785 8,169
------- ------- ------- -------
Total. . . . . . 301,915 210,325 467,920 340,702
======= ======= ======= =======
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on
its properties for the periods indicated:
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1996 1997 1998
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
DEVELOPMENT WELLS:
Productive. . . . 49 28.43 63 42.41 32 22
Non-productive. . 2 1.48 - - - -
--- ----- --- ----- --- ---
Total . . . . . . 51 29.91 63 42.41 32 22
=== ===== === ===== === ===
EXPLORATORY WELLS:
Productive . . . 8 5.13 15 11.29 5 4.23
Non-productive. . 5 3.17 5 1.98 - -
--- ----- --- ----- --- -----
Total . . . . . . 13 8.30 20 13.27 5 4.23
=== ===== === ===== === =====
OIL AND GAS RESERVES
The following table summarizes the estimates of the Company's net
proved 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 100% of the PV-10
at December 31, 1996, 72% of the PV-10 at December 31, 1997 and
83% of the PV-10 at December 31, 1998. The Company prepared the reserve
and present value data on all other properties.
AS OF DECEMBER 31,
-----------------------------------
1996 1997 1998
---- ---- ----
(DOLLARS IN THOUSANDS)
RESERVE DATA:
Proved developed reserves:
Oil (MBBL) . . . . . . . . . 15,265 19,411 19,097
Natural gas (MMCF) . . . . . 49,082 47,676 54,905
Total (MBOE) . . . . . . . 23,445 27,357 28,248
Proved undeveloped reserves:
Oil (MBBL) . . . . . . . . . 4,227 5,308 833
Natural gas (MMCF) . . . . . 1,453 1,702 314
Total (MBOE) . . . . . . . 4,469 5,592 885
Total proved reserves:
Oil (MBBL). . . . . . . 19,492 24,719 19,930
Natural gas (MMCF) . . . . . 50,535 49,378 55,219
Total (MBOE) . . . . . . . 27,915 32,949 29,133
PV-10 . . . . . . . . . . . $ 177,133 $ 241,625 $ 107,670
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, 1996,
1997 and 1998 were $23.74 per Bbl of oil and $3.35 per Mcf of natural gas,
$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, respectively.
Estimated quantities of proved reserves and future net cash flows
therefrom are affected by oil and gas prices, which have fluctuated
widely in recent years. There are numerous uncertainties inherent in
estimating oil and gas reserves and their values, including many
factors beyond the control of the producer. The reserve data set
forth in this annual report on Form 10-K represent only estimates.
Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in
an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different
engineers, including those used by the Company, may vary. In
addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration
activities, prevailing oil and gas prices, operating costs and other
factors, which revisions may be material. Accordingly, reserve
estimates are often different from the quantities of oil and gas that
are ultimately recovered. The meaningfulness of such estimates is
highly dependent upon the accuracy of the assumptions upon which they
are based.
In general, the volume of production from oil and gas properties
declines as reserves are depleted. Except to the extent the Company
acquires properties containing proved reserves or conducts successful
exploitation and development activities, the proved reserves of the
Company will decline as reserves are produced. The Company's future
oil and gas production is, therefore, highly dependent upon its level
of success in finding or acquiring additional reserves.
GAS GATHERING SYSTEMS
The Company's gas gathering systems are owned by CGI. Natural gas
and casinghead gas are purchased at the wellhead primarily under
either market-sensitive percent-of-proceeds-index contracts or keep-
whole gas purchase contracts. 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.
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, 1998, purchases of the Company's natural gas
production by GPM Gas Corporation accounted for 11.5% of the
Company's total gas sales for such period and for the same period
purchases of the Company's oil production by Koch Oil Company
accounted for 79.8% of the Company's total produced oil sales.
Beginning with December 1998 production, Koch Oil Company was
replaced by EOTT as the major purchaser of the Company's crude oil
production. Due to the availability of other markets, the Company
does not believe that the loss of EOTT or any other crude oil or gas
customer would have a material adverse effect on the Company's
results of operations.
Periodically the Company utilizes various hedging strategies to
hedge the price of a portion of its future oil and gas production.
The Company does not establish hedges in excess of its expected
production. These strategies customarily emphasize forward-sale,
fixed-price contracts for physical delivery of a specified quantity
of production or swap arrangements that establish an index-related
price above which the Company pays the hedging partner and below
which the Company is paid by the hedging partner. These contracts
allow the Company to predict with greater certainty the effective oil
and gas prices to be received for its hedged production and benefit
the Company when market prices are less than the fixed prices
provided in its forward-sale contracts. However, the Company does not
benefit from market prices that are higher than the fixed prices in
such contracts for its hedged production. In August 1998, the
Company began engaging in oil trading arrangements as part of its oil
marketing activities. Under these arrangements, the Company contracts
to purchase oil from one source and to sell oil to an unrelated
purchaser, usually at disparate prices.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is party to litigation or other
legal proceedings that it considers to be a part of the ordinary
course of its business. The Company is not involved in any legal
proceedings nor is it party to any pending or threatened claims that
could reasonably be expected to have a material adverse effect on its
financial condition or results of operations. 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 31, 1999, there were 3 record holders of the
Company's common stock. The Company sold no equity securities during
1998.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected historical consolidated
financial data for the periods ended and as of the dates indicated.
The statements of operations and other financial data for the years
ended December 31, 1994, 1995, 1996, 1997 and 1998, and the balance
sheet data as of December 31, 1994, 1995, 1996, 1997 and 1998 have
been derived from, and should be reviewed in conjunction with, the
consolidated financial statements of the Company, and the notes
thereto, which have been audited by Arthur Andersen LLP, independent
public accountants. The balance sheets as of December 31, 1997, and
1998 and the statements of operations for the years ended December
31, 1996, 1997 and 1998 are included elsewhere in this annual report
on Form 10-K. The data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the Consolidated Financial Statements and
the related notes thereto included elsewhere in this Report.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
(DOLLARS IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales. . . . . $ 21,427 $ 30,576 $ 75,016 $ 78,599 $ 60,162
Crude oil marketing. . . . - - - - 232,216
Gathering, marketing
and processing. . . . . . 14,806 20,639 25,766 25,021 17,701
Oil and gas service operations 5,630 6,148 6,491 6,405 6,689
--------- --------- --------- --------- ---------
Total revenues. . . . . . . 41,863 57,363 107,273 110,025 316,768
Operating costs and expenses:
Production expenses and taxes 6,905 7,611 19,338 20,748 22,611
Exploration expenses . . . 6,338 6,184 4,512 6,806 7,106
Crude oil marketing purchases
and expenses. . . . . . . - - - - 228,797
Gathering, marketing and
processing. . . . . . . . 8,415 13,223 21,790 22,715 15,602
Oil and gas service
operations . . . . . . . 2,708 3,680 4,034 3,654 3,664
Depreciation, depletion and
amortization . . . . . . 6,068 9,614 22,876 33,354 38,716
General and administrative 6,396 8,260 9,155 8,990 10,002
--------- --------- --------- --------- ---------
Total operating costs and
expenses . . . . . . . . . 36,830 48,572 81,705 96,267 326,498
--------- --------- --------- --------- ---------
Operating income (loss) . . 5,033 8,791 25,568 13,758 (9,730)
Interest income . . . . . . 108 137 312 241 967
Interest expense. . . . . . (670) (2,396) (4,550) (4,804) (12,248)
Other revenue (expense),
net. . . . . . . . . . - (411) 233 8,061 3,031
--------- --------- --------- --------- ---------
Income before income taxes. 4,471 6,121 21,563 17,256 (17,980)
Federal and state income
taxes (benefit). . . . 1,596 2,252 8,238 (8,941) -
--------- --------- --------- --------- ---------
Net income (loss) . . . . . $ 2,875 $ 3,869 $ 13,325 $ 26,197 $ (17,980)
========= ========= ========= ========= =========
OTHER FINANCIAL DATA:
Adjusted EBITDA . . . . $ 17,547 $ 24,315 $ 53,502 $ 54,721 $ 40,090
Net cash provided by
operations . . . . . . . . 18,787 18,985 41,724 51,477 25,190
Net cash used in investing (19,256) (58,022) (50,619) (78,359) (112,050)
Net cash provided by (used
in) financing. . . . . . . (1,138) 37,994 10,494 24,863 101,376
Capital expenditures. . 20,143 58,226 50,341 80,937 92,782
RATIOS:
Adjusted EBITDA to interest
expense. . . . . . . . . . 26.2x 10.1x 11.8x 11.4x 3.3x
Total debt to Adjusted EBITDA 0.4x 1.8x 1.0x 1.5x 4.2x
Earnings to fixed charges 7.7x 3.6x 5.7x 4.6x N/A
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents . $ 2,766 $ 1,722 $ 3,320 $ 1,301 $ 15,817
Total assets. . . . . . . . 56,759 107,825 145,693 188,386 253,739
Long-term debt, including
current maturities . . . . 6,272 44,265 54,759 79,632 167,637
Stockholders' equity. . . . 34,883 38,752 52,077 78,264 60,284
In 1997, other income includes $7.5 million resulting from the
settlement of certain litigation matters.
Effective June 1, 1997, the Company elected to be treated as an S
Corporation for federal income tax purposes. The conversion resulted
in the elimination of the Company's deferred income tax assets and
liabilities existing at May 31, 1997 and, after being netted against
the then existing tax provision, resulted in a net income tax benefit
to the Company of $8.9 million.
Adjusted EBITDA represents earnings before interest expense, income
taxes, depreciation, depletion, amortization and exploration expense,
excluding proceeds from litigation settlements. Adjusted EBITDA is
not a measure of cash flow as determined in accordance with GAAP.
Adjusted EBITDA should not be considered as an alternative to, or
more meaningful than, net income or cash flow as determined in
accordance with GAAP or as an indicator of a company's operating
performance or liquidity. Certain items excluded from adjusted EBITDA
are significant components in understanding and assessing a company's
financial performance, such as a company's cost of capital and tax
structure, as well as historic costs of depreciable assets, none of
which are components of Adjusted EBITDA. The Company's computation of
Adjusted EBITDA may not be comparable to other similarly titled
measures of other companies. The Company believes that Adjusted
EBITDA is a widely followed measure of operating performance and may
also be used by investors to measure the Company's ability to meet
future debt service requirements, if any. Even though the volume of
oil and gas produced by the Company during 1998 was greater than in
the comparable period in 1997, the Company's Adjusted EBITDA for the
1998 period was less than in 1997. The decrease in Adjusted EBITDA
for the 1998 period was attributable to declines in oil and gas
prices. Adjusted EBITDA does not give effect to the Company's
exploration expenditures, which are largely discretionary by the
Company and which, to the extent expended, would reduce cash
available for debt service, repayment of indebtedness and dividends.
Capital expenditures include costs related to acquisitions of
producing oil and gas properties.
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.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
Company's consolidated financial statements and notes thereto and the
Selected Consolidated Financial Data included elsewhere herein.
OVERVIEW
The Company's revenue, profitability and cash flow are
substantially dependent upon prevailing prices for oil and gas and
the volumes of oil and gas it produces. Although the Company produced
more oil and gas in the 1998 than in 1997, it experienced a
significant decline in revenues, net income and Adjusted EBITDA in
1998 compared to 1997 because of lower prevailing oil and gas prices.
These lower prices have continued to adversely affect the Company's
revenues and results of operation. Average well head prices as of
December 31, 1998, were $10.84 per Bbl of oil and $1.64 per Mcf of
natural gas compared to $18.06 per Bbl of oil and $2.25 per Mcf of
natural gas as of December 31, 1997. In addition, the Company's
proved reserves and oil and gas production will decline as oil and
gas are produced unless the Company is successful in acquiring
producing properties or conducting successful exploration and
development drilling activities.
The Company uses the successful efforts method of accounting for
its investment in oil and gas properties. Under the successful
efforts method of accounting, costs to acquire mineral interests in
oil and gas properties, to drill and provide equipment for
exploratory wells that find proved reserves and to drill and equip
development wells are capitalized. These costs are amortized to
operations on a unit-of-production method based on petroleum engineer
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 shareholders 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, 1998:
YEAR ENDED DECEMBER 31,
--------------------------------------
1996 1997 1998
---- ---- ----
(Dollars in Thousands, Except Average Price Data)
Revenues . . . . . . . . . . . . $ 107,273 $ 110,025 $ 316,768
Operating expenses . . . . . . . 81,705 96,267 326,498
Non-Operating income (expense) . (4,005) 3,498 (8,250)
Net income after tax . . . . . . 13,325 26,197 (17,980)
Adjusted EBITDA. . . . . . . 53,502 54,721 40,090
Production Volumes:
Oil and condensate (MBBL) . . . 2,888 3,518 3,981
Natural gas (MMCF). . . . . . . 6,527 5,789 6,755
Oil equivalents (MBOE). . . . . 3,976 4,483 5,107
Average Prices:
Oil and condensate (per Bbl). . $ 20.78 $ 18.61 $ 12.52
Natural gas (per Mcf) . . . . . 2.13 2.21 1.61
Oil equivalents (per Boe) . . . 18.87 17.53 11.78
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 1998, on an actual basis, was greater than in the
comparable period in 1997, the Company's Adjusted EBITDA for the
1998 period was less than in 1997. The decrease in Adjusted EBITDA
for the 1998 period was attributable to declines in oil and gas
prices. Adjusted EBITDA does not give effect to the Company's
exploration expenditures, which are largely discretionary by the
Company and which, to the extent expended, would reduce cash
available for debt service, repayment of indebtedness and
dividends.
Production volumes of oil and condensate, and natural gas, are
derived from the Company's production records and reflect actual
quantities produced without regard to the time of receipt of
proceeds from the sale of such production. Production volumes of
oil equivalents (on a Boe basis) are determined by dividing the
total Mcfs of natural gas produced by six and by adding the
resultant sum to barrels of oil and condensate produced.
Average prices of oil and condensate, and of natural gas, are
derived from the Company's production records which are maintained
on an "as produced" basis, which give effect to gas balancing and
oil produced and in the tanks, and, accordingly, may differ from
oil and gas revenues for the same periods as reflected in the
Financial Statements. Average prices of oil equivalents were
calculated by dividing oil and gas revenues, as reflected in the
Financial Statements, by production volumes on a per Boe basis.
Average sale prices per Boe realized by the Company, according to
its production records which are maintained on an "as produced"
basis, for the years ended December 31, 1996, 1997 and 1998, were
$18.59, $17.53 and $11.88, respectively.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
REVENUES
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 reduction 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 production. 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 production 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 million 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 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 Pressure 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 1999
leases on 40,000 net acres in which the company has an investment 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 decrease 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.
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 are 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 will be approximately $1.1 million
per year. An additional $1.1 million in savings could occur due to
temporary payroll reductions and suspension of the Company's
contributions to the 401K plan. The estimated savings for 1999 are
expected to be approximately $2.1 million. The Company plans to
reinstate its contribution to the company 401K plan effective April
1, 1999, if oil pricing continues above $15.00 per barrel. Salaries
could be reinstated when oil prices reach and maintain $17.00 per barrel.
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 Company's interest
costs on the Notes, or an increase in interest expense of
approximately $0.4 million per year through 2008.
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.
The Company is currently negotiating with, and has received an
offer to purchase for $5.8 million all of the Company's interest in
the Arkoma Basin properties in Southeast Oklahoma from an unrelated
third party. The Company expects final details to be concluded prior
to April 1, 1999 and that a gain of approximately $2.0 million will
be recognized during the second quarter of 1999. As of December 31,
1999, these properties represented $4.2 million, or 4%, of the
Company's estimated discounted future net cash flow.
INCOME BEFORE INCOME TAXES
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.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
OIL AND GAS SALES
Oil and gas sales revenue in 1997 was $78.6 million, an increase
of $3.6 million, or 5.0%, over $75.0 million in 1996. In 1997, the
Company sold an aggregate of 3,518 MBbl, a 22% increase over 1996 oil
sales of 2,888 MBbl. The Company's natural gas sales in 1997
aggregated to 5,789 MMcf, an 11% decrease over its 1996 natural gas
sales of 6,527 MMcf. In 1997, the Company received average prices of
$18.61 per Bbl and $2.21 per Mcf, compared to $20.78 per Bbl and
$2.13 per Mcf, respectively, in 1996.
GATHERING, MARKETING AND PROCESSING
Gas gathering, marketing and processing revenue in 1997 was $25.0
million, a decrease of $0.8 million, or 3.0%, from $25.8 million in
1996, which was attributable primarily to lower spot prices for
natural gas.
OIL AND GAS SERVICE OPERATIONS
Oil and gas service operations revenue in 1997 was $6.4 million, a
decrease of $0.1 million, or 1%, compared to $6.5 million in 1996.
PRODUCTION EXPENSES AND TAXES
Production expenses and taxes in 1997 were $20.7 million, an
increase of $1.4 million, or 7%, compared to $19.3 million in 1996,
which was attributable to a 13% increase in production volume offset
by a 5% decrease in production costs per Boe.
EXPLORATION EXPENSES
Exploration expenses were $6.8 million in 1997, an increase of
$2.3 million, or 51%, compared to $4.5 million in 1996, resulting
primarily from a $0.5 million increase in expired lease expense and a
$1.0 million increase in 3-D seismic expenditures.
GATHERING, MARKETING AND PROCESSING EXPENSE
Gathering, marketing and processing expense in 1997 was $22.7
million, a $0.9 million, or 4% increase, compared to $21.8 million,
which in 1996 was attributable to reduced margins on natural gas and
natural gas liquids.
OIL AND GAS SERVICE OPERATIONS EXPENSE
Oil and gas service operations expense in 1997 was $3.7 million, a
$0.3 million, or 9%, decrease from $4.0 million in 1996, attributable
to a reduction in saltwater disposal activity and warehouse activity.
DD&A EXPENSE
DD&A expense in 1997 was $33.4 million, a $10.5 million, or 46%
increase compared to $22.9 million in 1996. DD&A expense related to
oil and gas operations in 1997 was $30.2 million, an $8.6 million, or
40% increase, compared to $21.6 million in 1996, attributable
primarily to higher production levels in 1997. The unit rate of DD&A
expense per Boe in 1997 was $6.74, compared with $5.44 in 1996. The
1997 DD&A rate included $5.0 million of additional impairment for
write-down of certain long-lived assets in accordance with the
provisions of SFAS No. 121, or $1.12 per Boe, while 1996 includes
$2.1 million or $0.53 per Boe. The 1997 per Boe rate of DD&A, before
giving effect to the SFAS 121 write down, increased due to the
increased costs to drill and equip 93 net wells that the Company
completed during 1996 and 1997, and with respect to which the Company
is currently recognizing DD&A expense.
G&A EXPENSE
G&A Expense for 1997 was $9.0 million minus overhead reimbursement
of $2.4 million for a net G&A expense of $6.6 million, which was
equal to net G&A expense of $6.6 million in 1996.
INTEREST EXPENSE
Interest expense in 1997 was $4.8 million, an increase of $0.2
million, or 6%, compared to $4.6 million in 1996, attributable
primarily to higher levels of indebtedness outstanding during 1997.
INTEREST AND OTHER INCOME
Interest and other income in 1997 was $8.3 million, a $7.8
million, or 1,560%, increase over $0.5 million realized in 1996. The
substantial increase in 1997 was primarily attributable to non-
recurring income of approximately $7.5 million resulting from the
settlement of certain litigation matters.
INCOME BEFORE INCOME TAXES
Income before income taxes in 1997 was $17.3 million, a decrease
of $4.3 million, or 20%, from $21.6 million in 1996, attributable
primarily to increased production expenses and taxes, exploration
expenses, gathering, marketing and processing expenses and DD&A
expense, partially offset by an increase in total revenues of
approximately $10.5 million, which included approximately $7.5
million related to the settlement of certain litigation matters.
NET INCOME AFTER TAXES
Net income in 1997 was $26.2 million, an increase of $12.9
million, or 97%, compared to $13.3 million in 1996, primarily
attributable to an $8.9 million tax benefit realized in 1997,
compared to a $8.2 million tax expense in 1996, and the recognition
of approximately $7.5 million related to the settlement of certain
litigation matters.
LIQUIDITY AND CAPITAL ASSETS
The Company's primary sources of liquidity are cash flow from
operating activities, financing provided by its Credit Facility and
by the Company's principal shareholder and a private debt offering.
The Company's cash requirements other than for operations, are
generally for the acquisition, exploration and development of oil and
gas properties, and interest payments.
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $25.2 million for
1998 a 51% and 40% decrease from the $51.5 million and $41.7 million
in 1997 and 1996 respectively. The fluctuation from 1998 to 1997 and
1996 was primarily due to the decreased oil and gas prices offset by
an increase in production volumes. Cash increased to $15.8 million at
December 31, 1998, from $1.3 million at year-end 1997.
RESERVES AND ADDED FINDING COSTS
During 1997 and 1998, the Company spent $59.5 and $85.2,
respectively on acquisitions, exploration, exploitation and
development of oil and gas properties. The 1998 amount includes the
acquisition of the Worland Field properties, net of the sale of
an undivided 50% interest of the Worland properties to Harold Hamm
for $42.6 million. Total estimated proved reserves of natural gas
increased from 49.4 Bcf at year-end 1997 to 55.2 Bcf at December 31,
1998, and estimated total proved oil reserves decreased from 24.7 MMBbls
at year-end 1997 to 19.9 MMBbls at December 31, 1998.
FINANCING
Long-term debt at December 31, 1997 and December 31, 1998 was
$79.3 million and $157.3 million, respectively. The $78.0 million,
or 98% increase was mainly due to the acquisition of approximately
$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 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 paid toward the balance of the Company's line of credit.
CREDIT FACILITY
Long-term debt outstanding at December 31, 1997 and December 31,
1998 included $53.7 and $4.0 million, respectively, of revolving
debt under the Credit Facility. The effective rate of interest under
the Credit Facility was 7.7% at December 31, 1997 and was 7.75% at
December 31, 1998. On July 24, 1998, the balance under the Credit
Facility of $162.8 million was paid off with $19.6 million in
proceeds from the sale of 50% interest in the Worland Properties and
$143.2 million of the proceeds from the issuance of the Notes. Upon
issuance of the Notes and payment of the outstanding balance on the
Credit Facility, the Credit Facility was amended to a $75.0 million
Credit Facility with a $75.0 million borrowing base. Effective
November 1, 1998, the borrowing base was voluntarily lowered to $25
million. This Credit Facility 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 principal
amount based on the prime interest rate. Interest is payable monthly
with all outstanding principal and interest due at maturity on May
14, 2001. As of March 15, 1998 the Company has borrowed $8.6 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 under Securities Act Rule 144 A. Interest
on the Notes is payable semi annually on each February 1 and August
1. Approximately $143.2 million of the net proceeds for the sale of
the Notes was used to reduce the indebtedness under the Credit
Facility. 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,
described above. Due to changes in treasury note rates, the Company
paid $3.9 million to settle the forward interest rate swap contract.
This payment will result 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 next ten years. The issuance of the
Notes and the application of the net proceeds therefrom has not
adversely impacted the Company's liquidity.
CAPITAL EXPENDITURES
In 1998, the Company incurred $50.2 million of capital
expenditures, exclusive of acquisitions. The Company will initiate,
on a priority basis, as many projects as cash flow allows. It is
anticipated that approximately 23 projects will be initiated in 1999
for a projected investment of $10.7 million. The Company expects to
fund the 1999 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 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 applied to the outstanding
balance on the Credit Facility on July 24, 1998. Based on current
production levels and a new marketing contract effective February 1,
1999, proceeds from the sale of oil and gas produced by the Worland
Field properties are sufficient to cover operating costs and interest
expense on debt associated with the purchase. The Company expects
that the development potential of its Worland Field properties will
result in the field becoming a primary reserve growth area and should
increase future cash flows from such development.
SHAREHOLDER DISTRIBUTION
The 1997 tax returns of the Company's shareholders were filed on
October 15, 1998. The Company did not distribute a dividend to its
shareholders for the shareholders' 1997 tax liability. There will be
no dividend distributions to the shareholders for any 1998 tax
liability of the stockholders.
HEDGING
From time to time, the Company may use energy swap and forward
sale arrangements to reduce its sensitivity to oil and gas price
volatility. In July, 1998, the Company began engaging in oil trading
arrangements as part of its oil and gas marketing activities.
The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119 "Disclosure About Derivative
Financial Instruments and Fair Value of Financial Instruments" 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 per year through 2008. The Company has no present plans to
engage in further interest rate hedges.
OTHER
The Company follows the "sales method" of accounting for its gas
revenue, whereby the Company recognizes sales revenue on all gas
sold, regardless of whether the sales are proportionate to the
Company's ownership in the property. A liability is recognized only
to the extent that the Company has a net imbalance in excess of its
share of the reserves in the underlying properties. The Company's
historical aggregate imbalance positions have been immaterial. The
Company believes that any future periodic settlements of gas
imbalances will have little impact on its liquidity.
The Company has sold a number of non-strategic oil and gas
properties and other properties over the past three years,
recognizing pretax gains of approximately $233,000, $674,000 and
$2,614,000 in 1996, 1997 and 1998 respectively. Total amounts of oil
and gas reserves associated with these dispositions during the last
three years were 471 Bbls of oil and 2,463 Mmcf of natural gas. The
Company recently initiated, and is currently pursuing, litigation
with Burlington in connection with the agreement date May 15, 1998,
which provided for the exchange of undivided interest in the Cedar
Hills Field. In the event the Company is unsuccessful in such
litigation, Management does not believe that such adverse result
would have a material adverse impact upon the financial position,
results of operations and liquidity of the Company in the future.
However, should the Company be unable to complete the exchange of
undivided interest in the Cedar Hills Field with Burlington, it is
possible that the Company's ultimate recovery from its interests in
the Cedar Hills Field would be limited to reserves recovered through
primary drilling activities.
YEAR 2000 ISSUES
The Company is reviewing its computer software and hardware,
telecommunications systems, process control systems and business
relationships to locate potential operational problems associated
with the year 2000.
The Company's computer consultant has reviewed the Company's
mainframe hardware and operating software and updates to both have
been performed. All additional programming changes have been
provided for the operating system and have been installed.
Management believes the mainframe computer system will be year 2000
compatible. The financial software package utilized on the mainframe
computer has already been tested and updated by the software vendor.
The Company is in the process of developing a plan to further test
the financial software during the second quarter of 1999 to insure
the compatibility of the software with the year 2000. Assessment of
other less critical software systems and various types of computer
equipment is continuing and should be completed by the second quarter
of 1999. The Company believes that the potential impact, if any, of
these systems not being year 2000 compliant may, at most, require
employees to manually complete otherwise automated tasks or
calculations.
The telephone system billing software utilized in tracking
telephone usage is known to be incompatible with the year 2000. A
plan is already in place to increase the capacity of the telephone
system and new software will be installed at that time to make the
system year 2000 compatible. The cost of this update will be
$20,000. The Company believes that the radios being used for
communications with field operations will not be impacted. The
Company also relies on various public telephone companies to supply
normal voice and electronic data service and service to operating
locations which utilize process control alarms. These alarms notify
company personnel if there are operations abnormalities that need to
be checked and, if necessary, corrected. If the telephone service
were disrupted, the operations would need to be more closely monitored
by Company personnel, but because the operations are not actually
controlled through the phone systems, there should be no interruption
in operations. Surveys will be made of all telephone companies to
determine their system readiness and contingency plans will be developed
for those areas where service that is year 2000 compliant has not been
verified.
The gas measurement systems and gas processing facilities that the
Company operates use various Program Logic Controllers (PLC's) and
alarm mechanisms. The Company has been verbally notified that the
measurement systems that it currently uses are year 2000 compatible and
Company tests have been done to verify that information.
There can be no guarantee that the systems of other companies on
which the Company's systems rely will be timely converted, or that a
failure to convert by another company, or a conversion that is
incompatible with the Company's systems would not have a material
adverse effect on the Company. The Company will be evaluating its
relationships with third parties to determine any critical services,
suppliers, or customers. The third parties will include financial
services, utility services, oil and gas purchasers and parts and
supply vendors. Once critical relationships have been identified the
third parties will be surveyed and their preparedness for year 2000
evaluated. If the Company believes that the third parties have not
minimized risk satisfactorily it will evaluate alternatives to the
current relationships. The survey and evaluation of preparedness
should be completed by June 30, 1999.
The Company believes that there is minimal risk associated with
internal operating systems in relation to year 2000 compatibility.
Plans are already in place to address known areas of incompatibility
at costs estimated to be less than $100,000. Because of the
immaterial nature of the expenditures on an individual basis, the
Company plans to finance all costs through normal operating funds.
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. Due to the size of purchase and sells
transactions and certain restraints imposed by contract and by
Company guidelines, as of December 31, 1998, the Company had no
material risk from its trading activity.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX OF FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 1997 and 1998
Consolidated Statements of Operations for the Years Ended December
31, 1996, 1997 and 1998
Consolidated Statements of Stockholders' Equity
for the Years Ended December 31, 1996, 1997 and 1998
Consolidated Statements of Cash Flows for the Years Ended December
31, 1996, 1997 and 1998
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Continental
Resources, Inc. (an Oklahoma corporation) and subsidiaries as of December 31,
1997 and 1998, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. 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 generally accepted auditing
standards. 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, 1997 and 1998,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
February 19, 1999
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
ASSETS
December 31,
-------------------
1997 1998
---- ----
CURRENT ASSETS:
Cash. . . . . . . . . . . . . . . $ 1,301 $ 15,817
Accounts receivable-
Oil and gas sales. . . . . . . 11,432 7,255
Joint interest and other, net. 13,711 7,733
Inventories . . . . . . . . . . . 3,549 4,627
Prepaid expenses. . . . . . . . . 383 168
Advances to affiliates. . . . . . 59 1
-------- --------
Total current assets . . . 30,435 35,601
-------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful
efforts method)-
Producing properties . . . . . 195,785 241,358
Nonproducing leaseholds . . . 17,047 47,583
Gas gathering and processing facilities 20,795 24,709
Service properties, equipment and other 12,849 15,989
-------- --------
Total property and equipment 246,476 329,639
Less--Accumulated depreciation,
depletion and amortization (88,559) (121,061)
-------- --------
Net property and equipment 157,917 208,578
-------- --------
OTHER ASSETS:
Debt issuance costs. . . . . . . --- 9,023
Other assets . . . . . . . . . . 34 537
-------- --------
Total other assets. . . . 34 9,560
-------- --------
Total assets. . . . . . . $188,386 $253,739
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable . . . . . . . . $ 19,614 $ 10,532
Current portion of long-term debt 315 337
Revenues and royalties payable . 7,497 5,855
Accrued liabilities and other. . 3,165 9,224
Short-term debt - stockholder. . --- 10,000
-------- --------
Total current liabilities 30,591 35,948
-------- --------
LONG-TERM DEBT, net of current portion 79,317 157,302
OTHER NONCURRENT LIABILITIES . . . 214 205
COMMITMENTS AND CONTINGENCIES (Note 6) --- ---
STOCKHOLDERS' EQUITY:
Common stock, $1 par value, 75,000
shares authorized, 49,045 and
49,041 shares issued at December
31, 1997 and 1998, respectively,
and 49,041 shares outstanding 49 49
Additional paid-in-capital. . . . 2,731 2,721
Treasury stock, 4 shares, at December
31, 1997, at cost (10) ---
Retained earnings . . . . . . . . 75,494 57,514
-------- --------
Total stockholders' equity 78,264 60,284
-------- --------
Total liabilities and stock-
holders' equity . . . . . $188,386 $253,739
======== ========
The accompanying notes are an integral part of these consolidated
balance sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except for per share information)
December 31,
----------------------------------
1996 1997 1998
---- ---- ----
REVENUES:
Oil and gas sales. . . . . . $ 75,016 $ 78,599 $ 60,162
Crude oil marketing. . . . . --- --- 232,216
Gas gathering, marketing and
processing 25,766 25,021 17,701
Oil and gas service operations 6,491 6,405 6,689
-------- -------- --------
Total revenues. . . . . . 107,273 110,025 316,768
-------- -------- --------
OPERATING COSTS AND EXPENSES:
Production expenses . . . . . 15,462 16,825 19,028
Production taxes. . . . . . . 3,876 3,923 3,583
Exploration expenses. . . . . 4,512 6,806 7,106
Crude oil marketing purchases
and expenses . . . . . . . . --- --- 228,797
Gas gathering, marketing and
processing . . . . . . . . . 21,790 22,715 15,602
Oil and gas service operations 4,034 3,654 3,664
Depreciation, depletion and
amortization . . . . . . . . 22,876 33,354 38,716
General and administrative. . 9,155 8,990 10,002
-------- -------- --------
Total operating costs and expenses 81,705 96,267 326,498
-------- -------- --------
OPERATING INCOME (LOSS) . . . . . 25,568 13,758 (9,730)
-------- -------- --------
OTHER INCOME AND EXPENSES:
Interest income . . . . . . . 312 241 967
Interest expense. . . . . . . (4,550) (4,804) (12,248)
Other income (expense), net . 233 8,061 3,031
-------- -------- --------
Total other income and (expenses) (4,005) 3,498 (8,250)
-------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES 21,563 17,256 (17,980)
-------- -------- --------
INCOME TAX BENEFIT (EXPENSE). . . (8,238) 8,941 ---
-------- -------- --------
NET INCOME (LOSS) . . . . . . . . $13,325 $26,197 $(17,980)
======== ======== ========
EARNING (LOSS) PER COMMON SHARE . $271.69 $534.18 $(366.63)
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
(in thousands)
Total
Additional Stock-
Common Paid-in Treasury Retained holders'
Stock Capital Stock Earnings Equity
------ ---------- -------- -------- --------
Balance, December 31, 1995 $49 $2,731 $ --- $35,972 $38,752
Net income -- --- --- 13,325 13,325
----- ------ ------ ------- -------
Balance, December 31, 1996 49 2,731 --- 49,297 52,077
Purchase shares of
treasury stock (10) --- (10)
Net income -- --- --- 26,197 26,197
----- ------ ------ ------- -------
Balance, December 31, 1997 49 2,731 (10) 75,494 78,264
Retirement of treasury
stock (10) 10 --- ---
Net loss -- --- --- (17,980) (17,980)
----- ------ ------ ------- -------
Balance, December 31, 1998 $49 $2,721 $ --- $57,514 $60,284
===== ====== ====== ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
(in thousands)
1996 1997 1998
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $13,325 $26,197 ($17,980)
Adjustments to reconcile net income/
(loss) to net cash provided by
operating activities-
Depreciation, depletion and
amortization 22,876 33,354 38,716
Gain on sale of assets (233) (674) (2,539)
Dry hole cost and impairment of
undeveloped leases 1,167 1,468 2,880
Deferred income taxes 8,238 (11,979) ---
Other noncurrent assets and
liabilities --- --- (3)
Changes in current assets and
liabilities-
Decrease/(increase) in accounts
receivable (10,238) (3,971) 9,645
Decrease/(increase) in inventories (624) 8 (1,078)
Decrease/(increase) in prepaid
expenses 1,246 3,454 215
Increase/(decrease) in accounts
payable 265 1,979 (9,082)
Increase/(decrease) in revenues and
royalties payable 5,230 689 (1,642)
Increase/(decrease) in accrued
liabilities and other 472 952 6,059
------- ------- -------
Net cash provided by operating
activities 41,724 51,477 25,191
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (43,589) (63,702) (42,715)
Gas gathering and processing facilities
and service properties, equipment
and other (3,428) (16,760) (7,517)
Purchase of producing properties (3,324) (475) (85,100)
Cash received on note receivable -
stockholder --- --- 19,582
Proceeds from sale of assets 182 2,177 3,641
Advances from (to) affiliates (460) 401 58
------- ------- -------
Net cash used in investing
activities (50,619) (78,359) (112,051)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 14,144 33,493 266,515
Repayment of line of credit and other (3,651) (30,570) (165,539)
Debt issuance costs --- --- (9,600)
Proceeds from short-term debt due to
stockholder --- 21,950 10,000
Purchase of treasury stock --- (10) ---
------- ------- -------
Net cash provided by financing
activities 10,493 24,863 101,376
------- ------- -------
NET INCREASE (DECREASE) IN CASH $ 1,598 $(2,019) $14,516
CASH, beginning of year 1,722 3,320 1,301
------- ------- -------
CASH, end of year $ 3,320 $1,301 $15,817
======= ======= =======
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 4,550 $ 4,302 $12,248
Income taxes paid $ 589 $ 300 $ ---
NONCASH INVESTING AND FINANCING
ACTIVITIES:
Sale of 50% interest in producing
properties to principal
stockholder:
Satisfaction of note payable --- --- $22,969
Issuance of note receivable --- --- $19,582
Conversion of account receivable to
note receivable --- --- $ 510
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION:
Continental Resources, Inc. ("CRI") was incorporated in Oklahoma on
November 16, 1967, as Shelly Dean Oil Company. On September 23, 1976, the
name was changed to Hamm Production Company. In January 1987, the Company
acquired all of the assets and assumed the debt of Continental Trend
Resources, Inc. Affiliated entities, J.S. Aviation and Wheatland Oil Co. were
merged into Hamm Production Company, and the corporate name was changed to
Continental Trend Resources, Inc. at that time. In 1991, the Company's name
was changed to Continental Resources, Inc.
CRI has two wholly-owned subsidiaries, Continental Gas, Inc. ("CGI") and
Continental Crude Co. ("CCC"). CGI was incorporated in April 1990. CCC was
incorporated in May 1998. Since its incorporation, CCC has had no operations,
has acquired no assets and has incurred no liabilities.
CRI's principal business is oil and natural gas exploration, development
and production. CRI has interests in approximately 1,200 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 and Texas. 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 operates six gas gathering systems and two gas
processing plants in Oklahoma. 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, 1997 and 1998, are
recorded net of an allowance for doubtful accounts of approximately $467,000
and $400,000, 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, 1997 and 1998, tubular goods and production equipment totaled
approximately $2,692,000 and $3,913,000, respectively; crude oil in tanks
totaled approximately $856,000 and $714,000, respectively.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
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, deferred income taxes were provided for
temporary differences between financial reporting and income tax bases of
assets and liabilities. The estimated Federal and state income taxes on
income or loss generated between June 1 and December 31 is included in
deferred income taxes at each calendar year end prior to December 31, 1997.
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 49,045
in 1996, 49,042 in 1997 and 49,041 in 1998.
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, 1997 and 1998, 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,
1996, 1997 and 1998.
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 accounts for these
contracts utilizing the settlement method of accounting in the month of
physical delivery. At December 31, 1998, the Company did not have a material
net position on outstanding crude oil purchase and sales contracts.
Gas Balancing Arrangements
The Company follows the "sales method" of accounting for its gas revenue
whereby the Company recognizes sales revenue on all gas sold to its
purchasers, regardless of whether the sales are proportionate to the Company's
ownership in the property. A liability is recognized only to the extent that
the Company has a net imbalance in excess of their share of the reserves in
the underlying properties. The Company's aggregate imbalance positions at
December 31, 1997 and 1998 were not material.
Significant Customer
During 1996, 1997 and 1998, approximately 41.3%, 46.6% and 24.2%,
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 1998
presentation.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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 No. 133 ("SFAS No. 133"),
"Accounting for Derivative Instruments and for Hedging Activities." Adoption
of SFAS No. 133 is required for fiscal years beginning after June 15, 1999.
The Company will adopt this new standard effective January 1, 2000.
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.
In December 1998, the FASB Emerging Issues Task Force reached consensus on
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities ("EITF 98-10"). EITF 98-10 is effective for fiscal
years beginning after December 15, 1998. EITF 98-10 requires energy trading
contracts to be recorded at fair value on the balance sheet, with changes in
fair value included in earnings. The effect of initial application of EITF
98-10 will be reported as a cumulative effect of a change in accounting
principle. The Company will adopt EITF 98-10 effective January 1, 1999.
Management believes the adoption of EITF 98-10 will not have a material
impact on its consolidated financial position or results of operations.
3. ACQUISITION OF PRODUCING PROPERTIES:
On May 18, 1998, the Company consummated the purchase for approximately
$86.5 million of producing and non-producing oil and gas properties and
certain other related assets in the Worland Properties effective as of June 1,
1998, which the Company funded through borrowings on its line of credit.
Subsequently, and effective June 1, 1998, the Company sold an undivided 50%
interest in the Worland Properties (excluding inventory and certain equipment)
to the Company's principal stockholder for approximately $42.6 million. Of
the total sale price to the stockholder, approximately $23.0 million plus
interest of approximately $0.3 million was offset against the outstanding
balance of notes payable to the stockholder and approximately $19.6 million
was recorded as an increase in advances to affiliates.
This acquisition has been recorded using the purchase method of accounting.
The following presents unaudited pro forma results of operations for the years
ended December 31, 1997 and 1998 as if these acquisitions had been consummated
as of January 1, 1997. These pro forma results are not necessarily indicative
of future results.
(in thousands, except per share data) Pro Forma (Unaudited)
--------------------
1997 1998
---- ----
Revenues . . . . . . . . . . . . . . . . . $120,151 $318,895
======== ========
Net income (loss). . . . . . . . . . . . . $ 19,618 ($21,184)
======== ========
Earnings (loss) available to common
stock. . . . . . . . . . . . . . . . . . . $ 19,618 ($21,184)
======== ========
Earnings (loss) per common share . . . . . $ 400.03 ($431.97)
======== ========
4. LONG-TERM DEBT:
Long-term debt as of December 31, 1997 and 1998, consists of the following (in
thousands):
1997 1998
---- ----
Senior Subordinated Notes (a) $ --- $150,000
Line of credit agreement (b) 53,725 4,000
Notes payable to majority stockholder (c) 21,950 ---
Note payable to General Electric
Capital Corporation (d) 3,866 3,582
Capital lease agreements (e) 91 57
-------- --------
Outstanding debt 79,632 157,639
Less-Current portion 315 337
-------- --------
Total long-term debt $ 79,317 $157,302
======== ========
(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 Old 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, described above. Due to changes in
treasury note rates, the Company paid $3.9 million to settle the
forward interest rate swap contract. This payment results in an
increase of approximately 0.5% to the Company's effective interest rate
or an increase of approximately $0.4 million per year over the next ten
years. Effective November 14, 1998, the Company registered these 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
redetermination 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 % and non-use fee %. 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 principal amount based on the prime
interest rate. At December 31, 1998 interest was based on prime
(7.75%). Interest is payable monthly with all outstanding principal and
interest due at maturity on May 14, 2001.
(c) During 1997, CRI and CGI entered into various notes with the majority
stockholder of the Company. These notes bear interest at 8.25% with
interest payments due monthly or quarterly for twenty-four to thirty-six
months. On December 31, 1997, the notes between CRI and the majority
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 balance of notes was paid in full in connection
with the sale of the undivided 50% interest in the Worland Properties to
the majority stockholder in 1998, as discussed above.
(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.
(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 for forty-two and sixty
months, respectively.
The Company's line of credit agreement contains certain negative
financial and certain information reporting covenants. At December 31, 1998,
the Company was in violation of one negative and one information reporting
covenant. However, the bank has waived these violations through March 31,
1999 and the Company expects to be in compliance thereafter; therefore the
outstanding line of credit balance has been classified according to the
original terms.
The annual maturities of debt subsequent to December 31, 1998, are as
follows (in thousands):
1999 $ 337
2000 357
2001 4,359
2002 387
2003 and thereafter 152,199
--------
Total maturities $157,639
========
At December 31, 1998, the Company had $1,055,000 of outstanding letters of
credit which expire during 1999.
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 years ended
December 31, 1996 and 1997, are as follows:
(In thousands)
1996 1997
---- ----
Current $ --- $ 3,038
Deferred 8,238 (11,979)
------ -------
Income tax expense (benefit) $8,238 ($8,941)
====== =======
The provision for income taxes differs from an amount computed at the
statutory rates at December 31, 1996 and 1997 as follows:
(In thousands)
1996 1997
---- ----
Federal income tax at statutory rates $7,547 $6,040
State income taxes 647 518
Nondeductible expenses 21 30
Conversion to S-corporation -- (15,529)
Other 23 --
------ -------
Income tax expense (benefit) $8,238 ($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 1996, 1997 and
1998, contributions to the plan were 4%, 4% and 5%, respectively, of eligible
employees' compensation. Pension expense for the years ended December 31,
1996, 1997 and 1998, was approximately $152,000, $242,000 and $374,000,
respectively.
The Company and other affiliated companies participate jointly in a
self-insurance pool (the "Pool") covering health and workers' compensation
claims made by employees up to the first $50,000 and $500,000, respectively,
per claim. Any amounts paid above these are reinsured through third-party
providers. Premiums charged to the Company are based on estimated costs per
employee of the Pool. Premiums are expensed as incurred. No additional
premium assessments are anticipated for periods prior to December 31, 1998.
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. No amounts were included in the
1996 consolidated financial statements for this judgment as the ultimate
outcome was uncertain at that time. 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. It 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 declaratory judgment
action against the unrelated third party in the Oklahoma District Court. The
Company seeks a declaratory judgment determining that it is excused from
further performance under its exchange agreement with the third party. The
third party has denied the Company's allegations and seeks specific
performance by the Company, plus monetary damages of an unspecified amount.
The progress on the Cedar Hills Unitization process is expected to continue,
as the North Dakota Industrial Commission has called a hearing for March 31,
1999 to discuss the status of the unitization process. The timing and
probability of unitization will only be enhanced by the state's objective to
invoke their wide range of authority, including the ability to restrict
production, which will be targeted towards preserving the value of the field
and ensuring that secondary recovery reserves are captured.
Due to the nature of the oil and gas business, the Company is exposed to
possible environmental risks. The Company has implemented various policies
and procedures to avoid environmental contamination and risks from
environmental contamination. The Company is not aware of any material
potential environmental issues or claims.
7. RELATED PARTY TRANSACTIONS:
In December 1998, the Company borrowed $10,000,000 from their majority
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 $5,870,000, $11,852,000
and $12,842,000 during the years ended December 31, 1996, 1997 and 1998,
respectively. These services are provided at amounts which management
believes approximate the costs which would have been paid to an unrelated
party for the same services. At December 31, 1997 and 1998, the Company owed
approximately $1,094,000 and $876,000, 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 majority stockholder also own interests in wells operated by the
Company. At December 31, 1997 and 1998, approximately $336,000 and $340,000
respectively, from affiliated companies is included in joint interest 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.
During the years ended December 31, 1997 and 1998, CRI and CGI advanced
certain amounts to affiliates primarily for operating expenditures. The
advances outstanding to affiliates at December 31, 1997 and 1998, totaled
approximately $60,000 and $700, respectively. Interest income earned during
the years ended December 31, 1996, 1997 and 1998, was approximately $33,000,
$33,000 and $296,000, respectively, on advances to affiliates.
The Company leases office space under operating leases directly or
indirectly from the majority stockholder. Rents paid associated with these
leases totaled approximately $232,000, $294,000 and $363,000 for the years
ended December 31, 1996, 1997 and 1998, respectively.
During the years ended December 31, 1997 and1998, advances were made to
the Company from the majority stockholder. Interest expense related to these
advances totaled approximately $744,000 in 1997 and $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, 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 Harold Hamm equals the Company's cost basis in such leasehold acres.
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." The Company adopted SFAS No. 121 in the year ended December 31, 1996.
During 1996,1997 and 1998 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 1996, 1997 and 1998
of approximately $2,100,000, $5,000,000 and $7,900,000, respectively.
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 as of December 31, 1997, 1998 and for the three years in the period
ended December 31, 1996:
(In thousands)
1996 1997 1998
---- ---- ----
AS OF DECEMBER 31,
Current assets . . . . . . . . . . $ 3,094 $ 2,493
Noncurrent assets . . . . . . . . 20,263 22,263
--------- ---------
Total assets . . . . . . . . . 23,357 24,756
========= =========
Current liabilities . . . . . . . 11,043 13,503
Non current liabilities . . . . . 200 616
Stockholder's equity . . . . . . . 12,114 10,637
--------- ---------
Total liabilities and
stockholder's equity. . . . . 23,357 24,756
========= =========
FOR THE YEAR ENDED DECEMBER 31,
Total revenues . . . . . . . . . . $32,068 29,656 20,859
Operating costs and expenses . . . 28,151 29,122 21,703
--------- --------- ---------
Operating income (loss) . 3,917 534 (844)
Other income and (expenses) 95 (17) (633)
Income tax benefit (expense) . . . (1,404) 2,028 --
--------- --------- ---------
Net Income (loss) . . . . . . . . $ 2,608 $ 2,545 $ (1,477)
========= ========= =========
At December 31, 1997 and 1998, current liabilities payable to CRI
totaled approximately $7,313,000 and $10,100,000, respectively. For the years
ended December 31, 1996, 1997 and 1998, depreciation, depletion and
amortization, included in operating costs, totaled approximately $899,000,
$1,560,000 and $2,178,000, respectively.
Since its incorporation, CCC has had no operations, has acquired no
assets and has incurred no liabilities.
10. SUBSEQUENT EVENTS:
In January, 1999, the Company's Borrowing Base on its line of credit
with a bank was lowered from $75 million to $25 million. The next scheduled
Borrowing Base Redetermination Date is scheduled for April 1, 1999.
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. This reduction was accomplished
through a combination of personnel and payroll reductions and the temporary
suspension of the Company's contributions to the company 401K plan. The
estimated savings for 1999 are approximately $2.1 million.
On March 2, 1999, the Company received a bid of $5.8 million for 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, 1998 attributable to
these properties is approximately $4 million. Closing on this transaction
is tentatively scheduled for April 1, 1999.
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 and 1998, 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. Information prior to December 31, 1996, was
determined from the Company's production, drilling, acquisition and sale data
as applied to the December 31, 1996, reserve reports as reports on a December
31 year-end basis prior to 1996 were not available.
Crude Oil and
Natural Gas Condensate
(MMCF) (BBLS in thousands)
----------- -------------------
Proved reserves as of December 31, 1995 54,820 17,501
Revisions of previous estimates - -
Extensions, discoveries and other additions 2,232 4,874
Production (6,527) (2,888)
Sale of minerals in place (387) (236)
Purchase of minerals in place 397 241
------ ------
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)
Purchase of minerals in place - -
------ ------
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
====== ======
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves. Oil and gas reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
precisely measured, and estimates of engineers other than the Company's might
differ materially from the estimates set forth herein. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Results of drilling,
testing and production subsequent to the date of the estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
Gas imbalance receivables and liabilities for each of the three years
ended December 31, 1996, 1997 and 1998, were not material and have not been
included in the reserve estimates.
Proved Developed Oil and Gas Reserves (Unaudited)
The following reserve information was developed by the Company and set
forth the estimated quantities of proved developed oil and gas reserves of the
Company as of the beginning of each year.
Crude Oil and
Natural Gas Condensate
Proved Developed Reserves (MMCF) (BBLS in thousands)
- ------------------------- ----------- -------------------
January 1, 1996 52,588 12,627
January 1, 1997 49,082 15,265
January 1, 1998 47,676 19,411
January 1, 1999 54,901 19,095
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.
1996 1997 1998
---- ---- ----
Property acquisition costs:
Proved $ 3,327 $ 476 $ 85,100
Unproved 6,085 4,641 3,770
-------- -------- --------
Total property acquisition costs 9,412 5,117 88,870
Exploration costs 16,901 9,792 4,801
Development costs 20,600 49,268 34,144
-------- -------- --------
Total $46,913 $64,177 $127,815
======== ======== ========
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):
1997 1998
---- ----
Proved oil and gas properties $195,785 $270,708
Unproved oil and gas properties 17,047 18,233
-------- --------
Total 212,832 288,941
Less- Accumulated DD&A 82,157 111,618
-------- --------
Net capitalized costs $130,675 $177,323
======== ========
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):
1996 1997 1998
---- ---- ----
Revenues $ 75,016 $ 78,599 $ 60,162
Production costs 19,338 20,748 22,611
Exploration expenses 4,512 6,806 7,106
DD&A and valuation provision(1) 21,635 30,202 34,662
-------- -------- -------
Income (loss) 29,531 20,843 (4,217)
Income tax expense(2) 11,222 3,300 ---
-------- -------- -------
Results of operations from
producing activities (excluding
corporate overhead and interest
costs) $ 18,309 $ 17,543 ($4,217)
======== ======== =======
- ---------------
(1) Includes $2.1 million, $5.0 million and $7.9 million in 1996, 1997 and
1998, respectively, of additional DD&A as a result of adoption of SFAS
No. 121.
(2) The 1997 income tax provision was computed based on estimated oil and
gas operations income for the five months ended May 31, 1997, times the
estimated effective income tax rate. The Company's S-Corporation status
was effective June 1, 1997.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Unaudited)
The following information is based on the Company's best estimate of
the required data for the Standardized Measure of Discounted Future Net
Cash Flows as of December 31, 1996, 1997 and 1998 as required by Financial
Accounting Standards Board's Statement of Financial Accounting Standards
No. 69. The Standard requires the use of a 10% discount rate. This
information is not the fair market value nor does it represent the expected
present value of future cash flows of the Company's proved oil and gas
reserves (in thousands of dollars).
1996 1997 1998
---- ---- ----
Future cash inflows $612,158 $576,330 $328,333
Future production and development costs (191,947) (189,520) (157,003)
Future income tax expenses (141,487) --- ---
-------- -------- --------
Future net cash flows 278,724 386,810 171,330
10% annual discount for estimated
timing of cash flows (101,591) (145,185) (63,660)
-------- -------- -------
Standardized measure of discounted
future net cash flows $177,133 $241,625 $107,670
======== ======== ========
Future cash inflows are computed by applying year-end prices of oil and
gas relating to the Company's proved reserves to the year-end quantities
of those reserves. The year-end weighted average oil price utilized in
the computation of future cash inflows was approximately $23.00, $18.06
and $10.84 per BBL at December 31, 1996, 1997 and 1998, respectively.
The year-end weighted average gas price utilized in the computation of
future cash inflows was approximately $3.28, $2.25 and $1.64 per MCF at
December 31, 1996, 1997 and 1998, 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.
Future income tax expenses at December 31, 1996 was computed by applying
the appropriate year-end statutory tax rates to the future pretax net
cash flows relating to the Company's proved oil and gas reserves, less
the tax bases of the properties involved. The future income tax expenses
give effect to tax credits and allowances, but do not reflect the impact
of general and administrative costs and exploration expenses of ongoing
operations relating to the Company's proved oil and gas reserves. Income
taxes were not computed at December 31, 1997 or 1998, 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):
1996 1997 1998
---- ---- ----
Standardized measure of discounted
future net cash flows at the
beginning of the year $154,527 $177,133 $241,625
Extension, discoveries and improved
recovery, less related costs 28,815 16,352 7,088
Revisions of previous quantity
estimates --- 58,001 (34,228)
Changes in estimated future
development costs --- (36,901) 2,506
Purchases/sales of minerals in place --- (3,233) 11,815
Net changes in prices and production
costs --- (51,456) (116,458)
Accretion of discount 15,453 17,713 24,163
Sales of oil and gas produced, net of
production costs (55,678) (57,851) (37,551)
Development costs incurred during the
period 23,212 32,474 22,960
Net change in income taxes 3,200 89,915 ---
Change in timing of estimated future
production, and other 7,604 (522) (14,250)
------- ------- -------
Standardized measure of discounted
future net cash flows at the end of
the year $177,133 $241,625 $107,670
======== ======== ========
The standardized measure and changes in standardized measure prior to
December 31, 1996, were determined from production, drilling, acquisition
and sale records of the Company applied to the reserve reports as of
December 31, 1996, without revision for oil and gas price assumptions.
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
- ----------------- --- ----------------------------------------------------
[S] [C] [C]
Harold Hamm(1)(2) 53 Chairman of the Board of Directors, President, Chief
Executive Officer and Director
Jack Stark(1)(3) 43 Senior Vice President--Exploration and Director
Jeff Hume(1)(4) 48 Senior Vice President--Drilling Operations and
Director
Randy Moeder(1)(2) 38 Senior Vice President, General Counsel, Secretary
and Director
Roger Clement(1)(3) 54 Senior Vice President, Chief Financial Officer,
Treasurer and Director
Tom Luttrell 41 Senior Vice President--Land
Jeff White (5) 32 Senior Vice President--Business Development
Tom Myers 53 Manager of Production Operations
(1) Member of the Executive, Compensation and Audit Committees.
(2) Term expires in 2001.
(3) Term expires in 2000.
(4) Term expires in 1999.
(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
Underlying
Other Annual Option All Other
Name Year Annual Compensation Compensation Awards Compensation
Salary($) Bonus ($) ($)(1) (# of shares) ($)(2)
____ ____ ___________________ _____________ _____________ ______________
Harold Hamm 1998 $250,000.00 $ - $ - $ - $ -
1997 187,506.00 - - - 857.12
1996 (3) - - - - -
Jack Stark 1998 139,964.00 - - - 12,831.80
1997 116,550.32 10,249.50 - - 9,815.92
1996 113,225.00 10,575.00 - - 8,035.30
Jeff Hume 1998 123,584.00 - - - 17,226.00
1997 113,350.64 10,249.50 - - 11,162.12
1996 105,022.00 4,050.00 - - 10,851.04
Tom Myers 1998 105,513.32 - - - 11,942.46
1997 102,679.00 7,289.00 - - 346.72
1996 (4) - - - - -
Roger Clement 1998 98,476.00 - - - 4,823.80
1997 89,968.00 9,718.83 - - 3,118.72
1996 81,750.00 - - - 2,870.00
Randy Moeder 1998 91,333.35 - - - 19,566.72
1997 90,743.18 10,436.86 - - 18,666.78
1996 86,502.00 5,468.00 - - 11,790.39
- -------------------
Represents the value of Perquisites and other
personal benefits in excess of 10% of annual
salary and bonus for the year ended December 31,
1998, the Company paid no other annual
compensation to its named Executive Officers.
Represents contributions made by the Company to
the accounts of the executive officer under the
Company's profit sharing plan and under the
Company's nonqualified compensation plan.
Received no compensation during the calendar
year 1996.
Commenced employment in January 1997.
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 1998. 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 work over of oil and gas wells and the rental
of oil field tools and equipment. Harold Hamm is the chief executive
officer and principal shareholder of each of these related companies.
The aggregate amounts paid by Continental to these related companies
during 1998 was $12.8 million and at December 31, 1998 the Company
owed these companies approximately $0.9 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 his own interests in
wells operated by the Company. At December 31, 1998, the Company owed
such persons an aggregate of $373,000, representing their shares of
oil and gas production sold by the Company.
SHAREHOLDER LOANS AND ADVANCES. In 1998, the Company obtained
loans and advances from Harold Hamm and certain of his affiliates.
Such loans and advances were unsecured and were repaid from time to
time in varying amounts, with interest at an annual rate of 8.25%.
The maximum aggregate amount of such loans and advances outstanding
at any time during 1998 was $23.0 million.
OFFICE LEASE. The Company leases office space under operating
leases directly or indirectly from Harold Hamm and Continental
Management Company, L.L.C., a Company owned in part by Harold Hamm.
In 1998, the Company paid rents associated with these leases of
approximately $332,000. 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 Mr. Hamm's case the
acquisition of properties. At December 31, 1998, the aggregate unpaid
balance owed to the Company by such officers and directors was
$965,000, none of which was past due. Of the amount due from
directors and officers at December 31, 1998, $963,000 is associated
with Mr. Hamm's ownership in the Worland field.
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 shareholder, 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 Harold
Hamm equals the Company's cost basis in such leasehold acres. Harold
Hamm paid $19.3 million of the purchase price in cash and the balance
of $23.3 million by the cancellation of indebtedness owed to Harold
Hamm by the Company. Harold Hamm is subject to the applicable unit
agreements in place with respect to his interests in the Worland
Field. Harold Hamm intends to sell some or all of the interests
acquired from the Company, although no arrangements, understandings
or agreements for any such sale currently exist.
OIL TRADING. During 1998, the Company bought 120 Mbls of oil at a
cost of $1.5 million and sold 491 Mbls of oil for revenue of $5.7
million to Independent Trading and Transportation ("ITT"), an
affiliated of the Company through its marketing activities. There
was no gain or loss recognized due to these transactions.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following financial statements of the Company and the Report
of the Company's Independent Public Accountants thereon are included
on pages F-1 through F-22 of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheet as of December 31, 1997 and 1998
Consolidated Statement of Operations for the three years in the
period ended December 31, 1998
Consolidated Statement of Cash Flows for the three years in the
period ended December 31, 1998
Consolidated Statement of Changes in Equity for the three years in
the period ended December 31, 1998
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:
The Company filed no reports on Form 8K during the quarter ended
December 31, 1998.
(c) EXHIBITS:
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc. (1) [3.1]
3.2 Amended and Restated Bylaws of Continental Resources, Inc. (1) [3.2]
3.3 Certificate of Incorporation of Continental Gas, Inc. (1) [3.3]
3.4 Bylaws of Continental Gas, Inc., as amended and restated.(1) [3.4]
3.5 Certificate of Incorporation of Continental Crude Co.(1) [3.5]
3.6 Bylaws of Continental Crude Co.(1) [3.6]
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")(1) [4.1]
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.
4.2 Form of Revolving Note under the Credit Agreement (1) [4.2]
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 (1) [4.3]
4.4 Exchange and Registration Rights Agreement dated July 24, 1998
between Continental Resources, Inc., the Subsidiary Guarantors
named therein and Chase Securities, Inc.(1) [4.4]
10.1 Purchase and Sale Agreement dated March 28, 1998 by and between
Bass Enterprises Production Co., et al. As Sellers and
Continental Resources, Inc. as Buyer (1) [10.1]
10.2 Worland Area Purchase and Sale Agreement, as amended, dated June
25, 1998 by and between Continental Resources, Inc. as Seller
and Harold G. Hamm, Trustee of the Harold G. Hamm Revocable
Intervivos Trust dated April 23, 1984 as Buyer.(1) [10.2]
10.3* Illinois Purchase and Sale Agreement dated October 7, 1998 by
and between Continental Resources, Inc. as Seller and Farrar
Oil Company as Buyer
12.1* Statement re computation of ratio of debt to Adjusted EBITDA
12.2* Statement re computation of ratio of earnings to fixed charges
12.3* Statement re computation of ratio of Adjusted EBITDA to
interest expense
21* Subsidiaries
27* Financial Data Schedule
- -------------------
* Filed herewith
(1) Filed as an exhibit to the Company's Form S-4 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 incorporated by reference
herein.
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 30, 1999 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 Chairman of the Board, March 30, 1999
Harold Hamm President, Chief Executive
Officer (principal executive
officer) and Director
ROGER V. CLEMENT Senior Vice President and March 30, 1999
Roger V. Clement Chief Financial Officer
(Principal financial officer
and principal accounting
officer), Treasurer,
Secretary and Director
JACK STARK Senior Vice President and March 30, 1999
Jack Stark Director
RANDY MOEDER Senior Vice President and March 30, 1999
Randy Moeder Director
JEFF HUME Senior Vice President and March 30, 1999
Jeff Hume Director
Supplemental information to be Furnished With Reports Pursuant
to Section 15(d) of the Act by Registrants Which have Not Registered
Securities Pursuant to Section 12 of the Act.
The Company has not sent, and does not intend to send, an annual
report to security holders covering its last fiscal year, nor has the
Company sent a proxy statement, form of proxy or other proxy
soliciting material to its security holders with respect to any
annual meeting of security holders.
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
- -------- ------------ ----------------
3.1 Amended and Restated Incorporated herein by
Certificate of Incorpo- reference
ration of Continental
Resources, Inc.
3.2 Amended and Restated Incorporated herein by
Bylaws of Continental reference
Resources, Inc.
3.3 Certificate of Incorpo- Incorporated herein by
ration of Continental reference
Gas, Inc.
3.4 Bylaws of Continental Incorporated herein by
Gas, Inc., as amended reference
and restated.
3.5 Certificate of Incorpo- Incorporated herein by
ration of Continental reference
Crude Co.
3.6 Bylaws of Continental Incorporated herein by
Crude Co. reference
4.1 Restated Credit Agree- Incorporated herein by
ment dated May 12, 1998 reference
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
4.1.1 First Amendment to the Filed herewith electronically
Credit Agreement be-
tween Registrant, the
financial institutions
named therein and Bank
One, Oklahoma, N.A.,
as Agent dated February
10, 1999
4.2 Form of Revolving Note Incorporated herein by
under the Credit Agree- reference
ment
4.3 Indenture dated as of Incorporated herein by
July 24, 1998 between reference
Continental Resources,
Inc., as Issuer, the
Subsidiary Guarantors
named therein and the
United States Trust
Company of New York, as
Trustee
4.4 Exchange and Registra- Incorporated herein by
tion Rights Agreement reference
dated July 24, 1998
between Continental
Resources, Inc., the
Subsidiary Guarantors
named therein and Chase
Securities, Inc.
10.1 Purchase and Sale Incorporated herein by
Agreement dated March reference
28, 1998 by and between
Bass Enterprises
Production Co., et al.
as Sellers and Continental
Resources, Inc. as Buyer
10.2 Worland Area Purchase Incorporated herein by
and Sale Agreement, as reference
amended, dated June
25, 1998 by and between
Continental Resources,
Inc. as Seller and
Harold G. Hamm, Trustee
of the Harold G. Hamm
Revocable Intervivos
Trust dated April 23,
1984 as Buyer
10.3 Illinois Purchase and Filed herewith electronically
Sale Agreement dated
October 7, 1998 by
and between Continental
Resources, Inc. as
Seller and Farrar Oil
Company as Buyer
12.1 Statement re computation Filed herewith electronically
of ratio of debt to
Adjusted EBITDA
12.2 Statement re computa- Filed herewith electronically
tion of ratio of earnings
to fixed charges
12.3 Statement re computation Filed herewith electronically
of ratio of Adjusted
EBITDA to interest expense
21 Subsidiaries Filed herewith electronically
27 Financial Data Schedule Filed herewith electronically