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, 2003
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to __________________
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, Enid, Oklahoma 73701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (580) 233-8955
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ ] No [X]
The Registrant is not subject to the filing requirements of Section 13 and 15(d)
of the Securities Exchange Act of 1934, but files reports required by those
sections pursuant to contractual obligations.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act.) Yes [ ] No [X]
As of March 28, 2004, there were 14,368,919 shares of the registrant's common
stock, par value $.01 per share, outstanding. All outstanding shares of our
common stock are privately held by affiliates of the registrant.
Document incorporated by reference: None
CONTINENTAL RESOURCES, INC.
Annual Report on Form 10 - K
For the Year Ended December 31, 2003
TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS ......................................................... 3
ITEM 2. PROPERTIES ....................................................... 13
ITEM 3. LEGAL PROCEEDINGS ................................................ 21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .............. 21
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES ................ 21
ITEM 6. SELECTED FINANCIAL DATA .......................................... 22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS ............................................ 24
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ....... 32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ...................... 33
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE ............................................. 33
ITEM 9A. CONTROLS AND PROCEDURES .......................................... 33
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ............... 33
ITEM 11. EXECUTIVE COMPENSATION ........................................... 36
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS .................................. 37
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ................... 38
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES ........................... 38
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K . 39
SIGNATURES ................................................................ 41
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain of the statements in this Form 10-K are "forward-looking statements" as
defined in 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, our financial position, oil and gas reserve estimates, business
strategy and other plans and objectives for future operations, are
forward-looking statements. Although we believe that the expectations reflected
in such forward-looking statements are reasonable, we 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 our control. Reserve engineering is
a subjective process of estimating underground accumulation of oil and natural
gas that cannot be measured in an exact way, and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates made by different
engineers often vary from one another. In addition, results of drilling, testing
and production subsequent to the date of an estimate may justify revisions of
such estimates and such revisions, if significant, would change the schedule of
any further production and development drilling. Accordingly, reserve estimates
are generally different from the quantities of oil and natural gas that are
ultimately recovered. Additional important factors that could cause actual
results to differ materially from our 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, our
actual results and plan for 2004 and beyond could differ materially from those
expressed in forward-looking statements. All subsequent written and oral
forward-looking statements by us or by persons acting on our behalf are
expressly qualified in their entirety by such factors.
ITEM 1. BUSINESS
OVERVIEW
We are engaged in the exploration, exploitation, development and
acquisition of oil and gas reserves, primarily in the Rocky Mountain and
Mid-Continent regions of the United States, and to a lesser but growing extent,
in the Gulf Coast region of Texas and Louisiana. In addition to our exploration,
development, exploitation and acquisition activities, we currently own and
operate 750 miles of natural gas pipelines, seven gas gathering systems and
three gas processing plants in our operating areas. We also engage in natural
gas marketing, gas pipeline construction and saltwater disposal. We conduct
these activities through two business segments: exploration and production and
gas gathering, marketing and processing. Our reportable business segments have
been identified based on the differences in products or services provided.
Revenues from our exploration and production segment are derived from the
production and sale of crude oil and natural gas. Revenues from our gas
gathering, marketing and processing segment are derived from the transportation
and sale of natural gas and natural gas liquids. The financial information and
other disclosures related to these segments are incorporated by reference from
the audited consolidated financial statements included in Item 8.
Capitalizing on our growth through the drill-bit and our acquisition
strategy, we have increased our estimated proved reserves from 26.6 million
barrels of oil equivalent, or MMBoe in 1995 to 84.2 MMBoe at year-end 2003, and
have increased our annual production from 2.2 MMBoe in 1995 to 5.2 MMBoe in
2003. As of December 31, 2003, our reserves had a present value of estimated
future net cash flows, discounted at 10%, which we refer to as PV-10 of $812.4
million calculated in accordance with the guidelines of the Securities and
Exchange Commission, or the Commission or SEC. At that date, approximately 87%
of our estimated proved reserves were oil and approximately 55% of our total
estimated proved reserves were classified as proved developed. At December 31,
2003, we had interests in 2,207 producing wells of which we operated 1,745. We
were originally formed in 1967 to explore, develop and produce oil and gas
properties in Oklahoma. Through 1993 our activities and growth remained focused
primarily in Oklahoma. In 1993, we expanded our activity into the Rocky Mountain
and Gulf Coast regions. Through drilling success and strategic acquisitions, 86%
of our estimated proved reserves as of December 31, 2003 are now found in the
Rocky Mountain region. Our growth in the Gulf Coast region during the mid-1990's
was slowed due to the rapid growth of the Rocky Mountain region. Since 1999, we
have increased our drilling activity in the Gulf Coast region and we expect the
Gulf Coast region to be another core operating area for us. To further expand
our Mid-Continent operations, we acquired the assets of Mt. Vernon, Illinois
based Farrar Oil Company and its wholly owned subsidiary, Har-Ken Oil Company in
2001. Farrar had been one of our long time partners and our acquisition of
Farrar provides us with the assets and experienced personnel from which we can
expand our operations into the Illinois and Appalachian basins of the eastern
United States.
BUSINESS STRATEGY
Exploration and Production. Our business strategy is to increase
production, cash flow and reserves through the exploration, development,
exploitation and acquisition of properties in our core operating areas. We seek
to increase production and cash flow, and develop additional reserves by
drilling new wells (including horizontal wells), secondary recovery operations,
workovers, recompletions of existing wells and the application of other
techniques designed to increase production. Our acquisition strategy includes
seeking properties that have an established production history, have undeveloped
reserve potential and, through use of our technical expertise in horizontal
drilling and secondary recovery, will allow us to maximize the utilization of
our infrastructure in core operating areas. Our exploration strategy is designed
to combine the knowledge of our professional staff with our competitive and
technical strengths to pursue new field discoveries in areas that may be out of
favor or overlooked. This strategy enables us to build a controlling lease
position in targeted projects and to realize the full benefit of any project
success. We try to maintain an inventory of three or four new exploratory
projects at all times for future growth and development. On an ongoing basis, we
evaluate and consider divesting oil and gas properties that we consider to be
non-core to our reserve growth plans with the goal that all of our assets are
contributing to our long-term strategic plan.
Gas Gathering, Marketing and Processing Our business strategy is to
increase system throughput and cash flow through the construction and
acquisition of gas gathering and gas processing assets in our core operating
areas. We seek to expand system throughput and cash flow by building
low-pressure gas gathering systems in areas with little or no effective
competition. We are able to compete effectively against larger competitors by
offering a better or comparable range of services at a lower cost to the
producer. Our acquisition strategy is to acquire assets in our core operating
areas that can be integrated with our existing assets at little or no additional
cost.
PROPERTY OVERVIEW
Exploration and Production
Rocky Mountain Region. Our Rocky Mountain properties are concentrated in
the North Dakota, South Dakota and Montana portions of the Williston Basin, and
in the Big Horn Basin in Wyoming. These properties represented 86% of our
estimated proved reserves and 75% of the PV-10 of our proved reserves as of
December 31, 2003. We own approximately 569,000 net leasehold acres, have
interests in 645 gross (575 net) producing wells, are the operator of 96% of
these wells, and have identified 90 potential drilling locations in the Rocky
Mountain region.
Our Williston Basin properties represented 76% of our estimated proved
reserves and 69% of the PV-10 of our proved reserves at December 31, 2003. In
the Williston Basin, we own approximately 474,000 net leasehold acres, have
interests in 332 gross (296 net) producing wells, and we are the operator of
100% of these wells, and have identified 54 potential drilling locations. Our
principal properties in the Williston Basin include eight high-pressure air
injections, or HPAI, secondary recovery units located in the Cedar Hills,
Medicine Pole Hills and Buffalo Fields. Our extensive experience has
demonstrated that our secondary recovery methods have increased our reserves
recovered from existing fields by 200% to 300% through the injection and
withdrawal of fluids or gases. The combination of injection and withdrawal also
recovers additional oil from the reservoir that cannot be recovered by primary
recovery methods. The Buffalo Field units are the oldest of our secondary
recovery projects and have been in operation since 1978. The Cedar Hills Field
units are the most recent and largest of our secondary recovery units
representing approximately 50% of the proved reserves and 49% of the PV-10
attributable to our proved reserves at December 31, 2003. Combined, our eight
HPAI secondary recovery projects represent 80% of all HPAI projects in North
America.
Our properties in the Big Horn Basin are focused in and around the Worland
Field. The Worland Field represents 10% of our estimated proved reserves and 6%
of the PV-10 of our proved reserves at December 31, 2003. In the Worland Field,
we own approximately 78,000 net leasehold acres and have interests in 313 gross
(279 net) producing wells, of which 297 are operated by us. In the Worland
Field, we have identified 36 potential infill-drilling locations.
Mid-Continent Region. Our Mid-Continent properties are located primarily in
the Anadarko Basin of western Oklahoma, southwestern Kansas, Illinois, and in
the Texas Panhandle. At December 31, 2003, our estimated proved reserves in the
Mid-Continent region represented 14% of our total estimated proved reserves, 65%
of our natural gas reserves and 22% of the PV-10 attributable to our proved
reserves. In the Mid-Continent region, we own approximately 164,000 net
leasehold acres, have interests in 1,447 gross (937 net) producing wells and
have identified 77 potential drilling locations. We operate 71% of the gross
wells in which we have interests in the Mid-Continent region.
Gulf Coast Region. Our Gulf Coast properties are located primarily onshore,
along the Texas and Louisiana coasts, and include the Pebble Beach and Luby
projects in Nueces County, Texas and the Jefferson Island project in Iberia
Parish, Louisiana. We also participate in Gulf of Mexico drilling ventures as
part of our ongoing expansion in the Gulf Coast region. During 2003, our Gulf
Coast producing wells represented only 5% of our total producing well count, but
produced 33% of our total gas production for the year. As of December 31, 2003,
our Gulf Coast properties represented 1% of our total estimated proved reserves,
6% of our estimated proved gas reserves and 3% of our PV-10 attributable to our
proved reserves. In the Gulf Coast, we own approximately 22,000 net leasehold
acres; have interests in 115 gross (93 net) producing wells and have identified
39 potential drilling locations from 95 square miles of proprietary 3-D data and
several hundred miles of non-proprietary 2-D and 3-D seismic data. We operate
85% of the gross wells in which we have interests in the Gulf Coast region.
Gas Gathering, Marketing and Processing
Mid-Continent Region. Our Mid-Continent region gas gathering and gas
processing assets are located primarily in Oklahoma. We own and operate
approximately 570 miles of gas gathering lines and purchase gas from more than
350 wells. The gas is gathered in low-pressure pipelines and is transported to
our gas plants for the extraction of natural gas liquids.
Rocky Mountain Region. Our Rocky Mountain region gas gathering and gas
processing assets are located primarily in North Dakota. We own and operate
approximately 180 miles of gas gathering lines and purchase gas from more than
150 wells. The gas is gathered in low-pressure pipelines and is transported to
our gas plants for the extraction of natural gas liquids.
We and our subsidiaries are headquartered in Enid, Oklahoma and Mt. Vernon,
Illinois, with additional offices in Baker, Montana; Buffalo, South Dakota; and
field offices located within our various operating areas.
BUSINESS STRENGTHS
We believe that we have certain strengths that provide us with competitive
advantages and provide us with diversified growth opportunities, including the
following:
Proven Growth Record. We have demonstrated consistent growth through a
balanced program of development, exploitation and exploratory drilling and
acquisitions. We have increased our proved reserves 217% from 26.6 MMBoe in 1995
to 84.2 MMBoe as of December 31, 2003.
Substantial and Diversified Drilling Inventory. We are active in seven
different geologic basins in 11 states and have identified 206 potential
drilling locations based on geological and geophysical evaluations. As of
December 31, 2003, we held approximately 755,000 net leasehold acres, of which
approximately 63% were classified as undeveloped. Our management believes that
our current inventory and acreage holdings could support three to five years of
drilling activities depending upon oil and gas prices.
Long-Life Nature of Reserves. Our producing reserves are primarily
characterized by relatively stable, mature production that is subject to gradual
decline rates. As a result of the long-lived nature of our properties, we have
relatively low reinvestment requirements to maintain reserve quantities and
production levels. Our properties have an average reserve life of approximately
16 years.
Successful Drilling and Acquisition Record. We have maintained a successful
drilling record. During the five years ended December 31, 2003, we participated
in 282 gross wells of which 83% were completed as producers. During this time,
the reserves we added from drilling, workovers and related activities totaled
47.9 MMBoe of proved developed reserves at an average finding cost of $6.45 per
barrel of oil equivalent, or Boe. During 2003, we spent $41.4 million on the
development of the Cedar Hills field; $20.5 million drilling injection wells and
$20.7 million on infrastructure, including compressors and pipelines. Excluding
these costs, our five-year average finding cost would be $5.59 per Boe. During
the same period, we acquired 13.2 MMBoe at an average cost of $6.50 per Boe.
Including major revisions of 20.3 MMBoe due primarily to fluctuating prices, we
added a total of 81.3 MMBoe at an average cost of $4.85 per Boe during the last
five years.
Significant Operational Control. Approximately 97% of our PV-10 at December
31, 2003, was attributable to wells that we operate, giving us significant
control over the amount and timing of our capital expenditures and production,
operating and marketing activities.
Technological Leadership. We have demonstrated significant expertise in the
continually evolving technologies of 3-D seismic, directional drilling, and
precision horizontal drilling, and are among the few companies in North America
to successfully utilize high pressure air injection enhanced recovery technology
on a large scale. Through the use of precision horizontal drilling we have
experienced a 400% to 700% increase in initial flow rates. Since our inception,
we have drilled approximately 250 horizontal wells in our Rocky Mountain and
Mid-Continent regions. Through the combination of precision horizontal drilling
and secondary recovery technology, we have significantly enhanced the
recoverable reserves underlying our oil and gas properties. Since our inception,
we have experienced a 300% to 400% increase in recoverable reserves through use
of these technologies.
Experienced and Committed Management. Our senior management team has
extensive expertise in the oil and gas industry. Our Chief Executive Officer,
Harold Hamm, began his career in the oil and gas industry in 1967. Our eight
senior officers have an average of 25 years of oil and gas industry experience.
Additionally, our technical staff, which includes 19 petroleum engineers and 11
geoscientists, has an average of more than 26 years experience in the industry.
DEVELOPMENT, EXPLORATION AND EXPLOITATION ACTIVITIES
Capital Expenditures. We expect our projected capital expenditures for
development, exploitation and exploration activities in 2004 to total $81.9
million. Approximately $55.4 million (68%) is targeted for drilling outside of
Cedar Hills Field, $6.1 million for the completion of Cedar Hills Field, $7.7
million (9%) for lease acquisitions, $7.2 million (9%) for workovers,
recompletions, and secondary recovery projects. The remaining $5.5 million of
the budget will be spent by our subsidiaries on their projected capital
expenditures. Funding for these expenditures will come from a combination of
cash flow and our credit facility.
Included in our expected capital expenditures in 2004 is $6.1 million for
completion of the Cedar Hills project, with an estimated project completion date
of April 30, 2004. This will bring the total HPAI project cost to $119.9
million, including capital leases.
Expenditures on projects outside of Cedar Hills are discretionary and may
vary from projections in response to commodity prices and available cash flow.
Development and Exploitation. Our development and exploitation activities
are designed to maximize the value of our existing properties. Activities
include the drilling of vertical, directional and horizontal development wells,
workovers and recompletions in existing well-bores, and secondary recovery water
flood and HPAI projects. During 2004, we expect to invest $39.1 million drilling
43 development-drilling projects, representing 64% of our total 2004 drilling
budget. Within the development drilling budget, 16% will be spent drilling
injector wells within the Cedar Hills units, 55% on other projects in the
Williston and Big Horn Basins, 13% in the Gulf Coast region and 16% in the
Mid-Continent region. We also expect to invest $7.2 million during 2004 on
workovers, recompletions and secondary recovery projects. The following table
sets forth our development inventory as of December 31, 2003:
Drilling
ROCKY MOUNTAIN REGION Locations
--------------
Williston Basin 29
Cedar Hills 4
Big Horn Basin 36
--------------
Total Rocky Mountain 69
MID-CONTINENT REGION
Anadarko Basin 27
Black Warrior Basin 1
Illinois Basin 5
--------------
Total Mid-Continent 33
GULF COAST REGION
Texas 22
Louisiana 1
Gulf of Mexico 0
--------------
Total Gulf Coast 23
TOTAL 125
Exploration Activities. Our exploration projects are designed to locate new
reserves and fields for future growth and development. Our exploration projects
vary in risk and reward based on their depth, location and geology. We routinely
use the latest in technology, including 3-D seismic, horizontal drilling and new
completion technologies to enhance our exploration projects. We intend to
continue to build exploratory inventory throughout the year for future drilling.
The following table sets forth information pertaining to our existing
exploration project inventory at December 31, 2003:
Drilling 3-D
Locations Seismic
-------------- ------------
ROCKY MOUNTAIN REGION
Williston Basin 21 4
Big Horn Basin 0 1
-------------- ------------
Total Rocky Mountain 21 5
MID-CONTINENT REGION
Anadarko Basin 22 0
Black Warrior Basin 5 0
Illinois Basin 17 0
-------------- ------------
Total Mid-Continent 44 0
GULF COAST REGION
Texas 7 2
Louisiana 2 0
Gulf of Mexico 7 4
-------------- ------------
Total Gulf Coast 16 6
TOTAL 81 11
We will initiate, on a priority basis, as many projects as cash flow
prudently justifies. We anticipate investing as much as $22.3 million to drill
45 exploratory projects during 2004, representing 36% of our total 2004 drilling
budget, with 35% in the Rocky Mountain region, 19% in the Mid-Continent region,
and 46% in the Gulf Coast region.
ACQUISITION ACTIVITIES
On July 9, 2001, our newly formed, wholly owned subsidiary purchased the
assets of Farrar Oil Company and its wholly owned subsidiary, Har-Ken Oil
Company, for $33.7 million. These were oil and gas operating companies in
Illinois and Kentucky, respectively. On August 1, 2003, another of our wholly
owned subsidiaries acquired the Carmen Gathering System located in western
Oklahoma for a net price after adjustments of $12.0 million.
We seek to acquire properties that have the potential to be immediately
positive to cash flow, have long-lived, lower risk, relatively stable production
potential, and provide long-term growth in production and reserves. We focus on
acquisitions that complement our existing exploration program, provide
opportunities to utilize our technological advantages, have the potential for
enhanced recovery activities, and /or provide new core areas for our operations.
RISK FACTORS
Oil and natural gas prices are volatile. The future volatility of prices
for oil and natural gas may have a significant effect upon our revenues,
profitability and rate of growth. Any significant decline in the market prices
for oil and natural gas could materially and adversely affect our results of
operation and financial condition.
Our revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices for oil, gas and natural gas liquids, which, in
turn, are dependent upon numerous factors such as weather, economic, political
and regulatory developments and competition from other sources of energy. We are
affected more by fluctuations in oil prices than natural gas prices, because a
majority of our production is oil. The volatile nature of the energy markets and
the unpredictability of actions of OPEC members makes it particularly difficult
to estimate future prices of oil, 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 it is possible that future
prolonged decreases in such prices could occur. All of these factors are beyond
our control. Any significant decline in the market prices for oil and, to a
lesser extent, natural gas would have a material adverse effect on our results
of operations and financial condition. Although we may enter into hedging and
other arrangements to manage the risk of volatility of market prices of our oil
and gas sales, our price risk management arrangements are likely to apply to
only a portion of our production and provide only limited price protection
against fluctuations in market prices for oil and gas. See more discussion in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".
We may be unable to replace our reserves on terms satisfactory to us. If we
cannot replace our reserves as we deplete them, it could prevent us from
continuing our business strategy and could reduce our cash flow and revenues.
Our future success depends upon our ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless we
successfully replace the reserves that we produce (through successful
development, exploration or acquisition), our proved reserves will decline. We
can provide no assurance that we will continue to be successful in our efforts
to increase or replace our proved reserves. To the extent we are unsuccessful in
replacing or expanding our estimated proved reserves, we may be unable to repay
the principal of and interest on our senior subordinated notes and other
indebtedness in accordance with their terms, or otherwise to satisfy certain of
the covenants contained in the indenture governing our senior subordinated notes
and the terms of our other indebtedness.
Estimating reserves and future net oil and natural gas revenues is
difficult to do with any certainty. Our actual drilling results are likely to
differ from our estimates of proved reserves. We may experience production that
is less than is estimated in our reserve reports. Any material inaccuracies in
reserve estimates or underlying assumptions will materially affect the
quantities and net present value of our reserves.
The estimates of our oil and gas reserves and the future net cash flows
included in this report have been prepared and, at our request, by 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 our control. Each of the estimates of proved oil
and gas reserves, future net cash flows and discounted present values rely upon
various assumptions, including assumptions required by the Commission as to
constant oil and gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The process of estimating oil and
gas reserves is complex, requiring significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data
for each reservoir. As a result, such estimates are inherently imprecise. Actual
future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves may vary substantially from those estimated. 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, our 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 our control. The PV-10 of our proved oil
and gas reserves does not necessarily represent the current or fair market value
of those proved reserves, and the 10% discount rate required by the Commission
may not reflect current interest rates, our cost of capital or any risks
associated with the development and production of our proved oil and gas
reserves. At December 31, 2003, the estimated future net cash flow of $1,574
million and PV-10 of $812.4 million attributable to our proved oil and gas
reserves are based on prices at the date ($30.49 per barrel, or Bbl. of oil and
$4.64 per thousand cubic feet, or Mcf of natural gas), which may be materially
different from actual future prices.
If we are unable to successfully identify, finance or complete acquisition
opportunities, our future results of operations and financial condition may be
adversely affected.
Our growth strategy includes the acquisition of oil and gas properties. In
the future, we may be unable to identify attractive acquisition opportunities,
obtain financing for acquisitions on satisfactory terms or successfully acquire
identified targets. In addition, we may be unable to successfully integrate any
acquired business into our existing operations, and such integration may result
in unforeseen operational difficulties or require a disproportionate amount of
our management's attention. We may finance future acquisitions through the
incurrence of additional indebtedness to the extent permitted under the
instruments governing our indebtedness or through the issuance of capital stock.
Furthermore, that the competition for acquisition opportunities in these
industries may escalate, thereby increasing our cost or making further
acquisitions not feasible, or causing us to refrain from making additional
acquisitions.
We are subject to risks that properties, which we may acquire, 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 acquired properties. In addition,
expansion of our operations may place a significant strain on our management,
financial and other resources. Our ability to manage future growth will depend
upon our ability to monitor operations, maintain effective cost and other
controls and significantly expand our 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 our business could have a material adverse effect on our 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 our
operating results.
If we are unable to finance our planned growth, our operations may be
adversely impacted.
We have made, and will continue to make, substantial capital expenditures
in connection with the acquisition, development, exploitation, exploration and
production of our oil and gas properties. Historically, we have funded these
capital expenditures through borrowings from banks and from our principal
stockholder, and from cash flow from operations. Our 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 our success in locating and producing new oil and gas reserves. If
our revenues were to decrease as a result of lower oil and gas prices, decreased
production or otherwise, and if we do not have availability under our bank
credit facility or other sources of borrowings, we could have limited ability to
replace our oil and gas reserves or to maintain production at current levels,
resulting in a decrease in production and revenues over time. If our cash flow
from operations and availability under our credit facility are not sufficient to
satisfy our capital expenditure requirements, we may be unable to obtain
sufficient additional debt or equity financing to meet our planned growth.
We have a significant amount of indebtedness. If we are unable to
substantially reduce our indebtedness, as substantial portion of our operating
cash flows will be dedicated to debt service and this could make it more
difficult for us to survive a downturn in our business.
At December 31, 2003, on a consolidated basis, we had $290.9 million in
indebtedness, including short-term indebtedness and current maturities of
long-term indebtedness, compared to our stockholder's equity of $116.9 million.
Although our cash flow from operations has been sufficient to meet our debt
service obligations in the past, our future cash flow from operations may not be
sufficient to permit us to meet our debt service obligations.
The degree to which we are leveraged could have important consequences to
our future results of operations and financial condition. These potential
consequences could include:
o Our 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 our cash flow from operations must be
dedicated to the payment of principal and interest on our senior
subordinated notes and to borrowings under the our credit facility,
thereby reducing funds available to us for our operations and other
purposes;
o Certain of our borrowings are and will continue to be at variable
rates of interest, which expose us to the risk of increased interest
rates; and
o We may be substantially more leveraged than certain of our
competitors, which may place us in a relative competitive disadvantage
and make us more vulnerable to changes in market conditions and
regulations.
Our ability to make scheduled payments or to refinance our indebtedness
will depend on our 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
our control. If our cash flow and capital resources are insufficient to fund our
debt service obligations, we may be forced to sell assets, obtain additional
debt or equity financing or restructure our 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 us. In the absence of such operating results and
resources, we could experience substantial liquidity problems and might be
required to dispose of material assets or operations to meet our debt service
and other obligations, we cannot provide you with any assurance that the timing
of such sales or the adequacy of the proceeds that we could realize from such
sales would be sufficient or would not adversely affect our results of operation
and financial condition.
The instruments governing our outstanding indebtedness contain certain
covenants that may inhibit our ability to make certain investments, incur
additional indebtedness and engage in certain other transactions, which could
adversely affect our ability to meet our future goals.
Our credit facility and the indenture governing our senior subordinated
notes include certain covenants that, among other things restrict:
o Our investments, loans and advances and the paying of dividends and
other restricted payments;
o Our 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 substantial part of our
business or property;
o The hedging, forward sale or swap of our production of crude oil or
natural gas or other commodities;
o The sale of assets; and
o Our capital expenditures.
Our credit facility requires us to maintain certain financial ratios,
including interest coverage and leverage ratios. All of these restrictive
covenants may restrict our ability to expand or pursue our business strategies.
Our ability to comply with these and other provisions of our credit facility may
be impacted by changes in economic or business conditions, results of operations
or other events beyond our control. The breach of any of these covenants could
result in a default under our 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 our credit facility,
together with accrued interest, to be due and payable, and we could be
prohibited from making payments with respect to our senior subordinated notes
until the default is cured or all senior debt is paid or satisfied in full. If
we were unable to repay such borrowings, our lenders could proceed against their
collateral. If the indebtedness under our credit facility were to be
accelerated, our assets may not be sufficient to repay in full such indebtedness
and our other indebtedness. Drilling wells is speculative, often involving
significant risks and costs, and may not result in additions to our production
or reserves. Our operations also involve significant risks and costs.
Oil and gas drilling activities are subject to numerous risks, many of
which are beyond our 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. Our 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.
Our 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 us 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, we maintain insurance against some of the risks described above. The
insurance that we do maintain may not be adequate to cover our losses or
liabilities. We cannot predict the continued availability of insurance, or its
availability at premium levels that justify its purchase.
Our natural gas gathering and marketing operations depend on our ability to
obtain satisfactory contracts with producers and are subject to changes in
regulations governing gathering and marketing of natural gas.
Our gas gathering and marketing operations depend in large part on our
ability 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 our natural gas supply and the sales price for
such natural gas. In addition, our operations are subject to changes in
regulations relating to gathering and marketing of oil and gas. Our inability to
attract new sources of third party natural gas or to promptly respond to
changing market conditions or regulations in connection with our gathering and
marketing operations could have a material adverse effect on our financial
condition and results of operations.
Our hedging activities may result in losses.
From time to time we use energy swaps, collars and forward sales
arrangements to reduce our sensitivity to oil and gas price volatility. If our
reserves are not produced at the rates we have estimated due to inaccuracies in
the reserve estimation process, operational difficulties or regulatory
limitations, or otherwise, we could be required to satisfy our obligations under
potentially unfavorable terms. All derivatives must be marked to market under
the provisions of statement of Financial Accounting Standards No. 133,
"Accounting for Derivatives" ("SFAS No. 133"). If we enter into qualifying
derivative instruments for the purpose of hedging prices and the derivative
instruments are not perfectly effective in hedging the underlying risk, all
ineffectiveness will be recognized currently in earnings. The effective portion
of the gain or loss on qualifying derivative instruments will be reported as
other comprehensive income and reclassified to earnings in the same period as
the hedged production takes place. Physical delivery contracts, which are deemed
to be normal purchases or normal sales, are not accounted for as derivatives.
Furthermore, under financial instrument contracts, we 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. From time to time we
will attempt to mitigate basis differential risk by entering into basis swap
contracts. Substantial variations between the assumptions and estimates used by
us in the hedging activities and actual results experienced could materially
adversely affect our anticipated profit margins and our ability to manage risk
associated with fluctuations in oil and gas prices. Furthermore, the fixed price
sales and hedging contracts limit the benefits we will realize if actual prices
rise above the contract prices.
We may incur substantial write-downs of the carrying value of our oil and
natural gas properties.
We periodically review the carrying value of our oil and gas properties in
accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of
Long-Lived Assets". SFAS No. 144 requires that we review our long-lived assets,
including proved oil and gas properties, and certain identifiable intangibles to
be held and used by us for impairment whenever events or changes in
circumstances indicate that the carrying amount of the assets may not be
recoverable. In performing the review for recoverability, we estimate the future
cash flows, including cash flows from risk-adjusted probable reserves, 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 that the carrying value of the asset, an impairment loss is recognized. Our
measurement of an impairment loss for proved oil and gas properties is
calculated on a field-by-field 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.
We may be required to write down the carrying value of our 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.
We are subject to complex laws and regulations including environmental
regulations, which can adversely affect the cost, manner or feasibility of doing
business.
Our oil and gas operations are subject to various federal, state and local
governmental regulations that 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--Regulations."
We are subject to a variety of federal, state and local governmental
regulations related to the storage, use, discharge and disposal of toxic,
volatile of otherwise hazardous materials. These regulations subject us 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 our financial condition or results of
operations, these laws and regulations may require us 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 us.
Our 21 years of experience with the use of HPAI technology has not resulted
in any known environmental claims. Our saltwater injection operations pose
certain risks of environmental liability to us. Although we monitor the
injection process, any leakage from the subsurface portions of the wells could
cause degradation of fresh ground water 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, our
sale of residual crude oil that we collected as part of the saltwater injection
process could impose a liability on us 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.
If we fail to obtain required permits for, control the use of, or
adequately restrict the discharge of, hazardous substances under present or
future regulations could subject us to substantial liability or could cause our
operations to be suspended. Such liability or suspension of operations could
have a material adverse effect on our business, financial condition and results
of operations.
Competition in our industry is intense. We are smaller and have a more
limited operating history than some of our competitors, and we may not be able
to compete effectively.
The oil and gas industry is highly competitive. We compete 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 ours. Our ability to
acquire additional oil and gas properties and to discover reserves in the future
will depend upon our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
Our President and Chief Executive Officer owns substantially all of our
outstanding common stock, giving him influence and control in corporate
transactions and other matters.
At March 28, 2004, Harold Hamm, our principal shareholder, President and
Chief Executive Officer and a Director, beneficially owned 13,037,328 shares of
our outstanding common stock, representing, in the aggregate, approximately
90.7% of our outstanding common stock. As a result, Mr. Hamm is our controlling
stockholder. The Harold Hamm DST Trust and Harold Hamm HJ Trust, together own
the remaining 9.3% of our outstanding common stock. An independent third party
is the trustee for both of these trusts and Harold Hamm has no beneficial
ownership in them. Several affiliated companies controlled by Mr. Hamm provide
us oilfield services. We expect these transactions will continue in the future
and may result in conflicts of interest between Mr. Hamm's affiliated companies
and us even though these arrangements are negotiated at arms length. We can
provide no assurance that any such conflicts will be resolved in our favor. If
Mr. Hamm ceases to be one of our executive officers, such would constitute an
event of default under our credit facility, unless waived by the requisite
percentage of banks.
REGULATION
General. Various aspects of our 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 statue to
issue, and have issued, rules and regulations binding upon the oil and gas
industry and its individual members.
Regulations of Sales and Transportation of Natural Gas. The Federal Energy
Regulatory Commission, or the FERC regulates the transportation and sale or
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. Our sales of natural gas are affected by
the availability, terms and cost of transportation. The price and terms for
access to pipeline transportation are subject to extensive regulation and
proposed regulation designed to increase competition within the natural gas
industry, to remove various barriers and practices that historically limited
non-pipeline natural gas sellers, including producers, from effectively
competing with interstate pipelines for sales to local distribution companies
and large industrial and commercial customers and to establish the rates
interstate pipelines may charge for their services. Similarly, the Oklahoma
Corporation Commission and the Texas Railroad Commission have been reviewing
changes to their regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers. While the changes being
considered by these federal and state regulators would affect us only
indirectly, they are intended to further enhance competition in natural gas
markets. We cannot predict what further action the FERC or state regulators will
take on these matters; however, we do not believe that any actions taken will
have an effect materially different from the effect on other natural gas
producers with whom we compete.
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. Our sales of crude oil,
condensate and gas liquids are not currently regulated and are made at market
prices. The price we receive from the sale of these products may be affected by
the cost of transporting the products to market.
Environmental. Our oil and gas operations are subject to pervasive federal,
state and local laws and regulations concerning the protection and preservation
of the environment (e.g., ambient air, and surface and subsurface soils and
waters), human health, worker safety, natural resources, and wildlife. These
laws and regulations affect virtually every aspect of our oil and gas
operations, including our exploration for, and production, storage, treatment,
and transportation of, hydrocarbons and the disposal of wastes generated in
connection with those activities. These laws and regulations increase our costs
of planning, designing, drilling, installing, operating, and abandoning oil and
gas wells and appurtenant properties, such as gathering systems, pipelines, and
storage, treatment and salt water disposal facilities.
We have expended and will continue to expend significant financial and
managerial resources to comply with applicable environmental laws and
regulations, including permitting requirements. If we fail to comply with these
laws and regulations, we may be subject to substantial civil and criminal
penalties, claims for injury to persons and damage to properties and natural
resources, and clean up and other remedial obligations. Although we believe that
the operation of our properties generally complies with applicable environmental
laws and regulations, the risk of incurring substantial costs and liabilities
are inherent in the operation of oil and gas wells and appurtenant properties.
We could also be subject to liabilities related to the past operations conducted
by others at properties now owned by us, without regard to any wrongful or
negligent conduct by us.
We cannot predict what effect future environmental legislation and
regulation will have upon our oil and gas operations. The possible legislative
reclassification of certain wastes generated in connection with oil and gas
operations as "hazardous wastes" would have a significant impact on our
operating costs, as well as the oil and gas industry in general. The cost of
compliance with more stringent environmental laws and regulations, or the more
vigorous administration and enforcement of those laws and regulations, could
result in material expenditures by us to remove, acquire, modify, and install
equipment, store and dispose of waters, remediation of facilities, employ
additional personnel, and implement systems to ensure compliance with those laws
and regulations. These accumulative expenditures could have a material adverse
effect upon our profitability and future capital expenditures.
Regulation of Oil and Gas Exploration and Production. Our exploration and
production operations are subject to various types of regulation at the federal,
state and local levels. Such regulations include requiring permits and drilling
bonds for the drilling of wells, regulating the location of wells, the method of
drilling and casing wells, and the surface use and restoration of properties
upon which wells are drilled. Many states also have statutes or regulations
addressing conservation matters, including provisions for the unitization or
pooling of oil and gas properties, the establishment of maximum rates of
production from oil and gas wells and the regulation of spacing, plugging and
abandonment of such wells. Some state statutes limit the rate at which oil and
gas can be produced from our properties.
EMPLOYEES
As of March 29, 2004, we employed 302 people, including 112 administrative
personnel, 11 geoscientists, 19 engineers and 160 field personnel. Our future
success will depend partially on our ability to attract, retain and motivate
qualified personnel. We are not a party to any collective bargaining agreements
and have not experienced any strikes or work stoppages. We consider our
relations with our employees to be satisfactory. From time to time we utilize
the services of independent contractors to perform various field and other
services.
ITEM 2. PROPERTIES
EXPLORATION AND PRODUCTION SEGMENT
Our oil and gas properties are located in selected portions of the
Mid-Continent, Rocky Mountains and Gulf Coast regions. Through 1993, most of our
activities and growth were focused in the Mid-Continent region. In 1993 we
expanded our drilling and acquisition activities into the Rocky Mountain and
Gulf Coast regions seeking added opportunity for production and reserve growth.
The Rocky Mountain region was targeted for oil reserves with good secondary
recovery potential and, therefore, long life reserves. The Gulf Coast region was
targeted for natural gas reserves with shorter reserve life but high current
cash flow. As of December 31, 2003, our estimated net proved reserves from all
properties totaled 84.2 MMBoe with 85% of these reserves located in the Rocky
Mountain region, 14% in the Mid-Continent region and 1% in the Gulf Coast
region. At December 31, 2003, 87% of our net proved reserves were oil and 13%
were natural gas. Our oil reserves are confined primarily to the Rocky Mountain
region and our natural gas reserves are primarily from the Mid-Continent and
Gulf Coast regions. Approximately $40.0 million, or 49%, of our projected $81.9
million capital expenditures for 2004 are focused on expansion and development
of our oil properties in the Rocky Mountain region while the remaining $41.9
million, or 51%, is focused primarily on our natural gas projects in the
Mid-Continent and Gulf Coast regions.
The following table provides information with respect to our net proved
reserves for our principal oil and gas properties as of December 31, 2003:
% of Total
Oil Present Value Present Value
Oil Gas Equivalent Of Future Cash of Future Cash
Area (MBbl) (MMcf) (MBoe) Flows(M$) Flows
- ------------------------------ ------------- --------------- ------------- ------------------ ------------------
ROCKY MOUNTAIN REGION:
Williston Basin 61,731 13,210 63,932 $ 559,312 68.8%
Big Horn Basin 7,013 6,346 8,071 50,521 6.2%
------------- --------------- ------------- ------------------ ------------------
Total ROCKY MOUNTAINS 68,744 19,556 72,003 609,833 75.0%
MID-CONTINENT REGION:
Anadarko Basin 1,418 39,968 8,079 143,153 17.6%
Black Warrior Basin 0 678 113 1,789 0.2%
Texas Panhandle 11 2,276 390 5,190 0.6%
Illinois Basin 2,723 533 2,812 31,870 3.9%
------------- --------------- ------------- ------------------ ------------------
Total MID-CONTINENT 4,152 43,455 11,394 182,002 22.3%
GULF COAST REGION:
Luby 16 1,687 297 8,596 1.2%
Pebble Beach 42 1,313 261 5,935 0.7%
Texas Onshore 0 144 24 551 0.1%
Louisiana Onshore 35 20 38 857 0.1%
Offshore 11 921 165 4,646 0.6%
------------- --------------- ------------- ------------------ ------------------
Total GULF COAST 104 4,085 785 20,585 2.7%
TOTALS 73,000 67,096 84,182 $ 812,420 100.0%
============= =============== ============= ================== ==================
Future estimated net cash flows discounted at 10%
ROCKY MOUNTAIN REGION
Our 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 our Rocky Mountain properties at December 31,
2003, totaled 72.0 MMBoe and represented 75% of our PV-10. Approximately 48% of
these estimated proved reserves are proved developed. During the twelve months
ended December 31, 2003, our average net daily production from the Rocky
Mountain properties was 7,294 Bbls of oil and 4,022 Mcf of natural gas, or 7,964
Boe per day. Our leasehold interests include 172,000 net developed and 397,000
net undeveloped acres, which represent 23% and 53% of our total leasehold,
respectively. This leasehold is expected to be developed utilizing 3-D seismic,
precision horizontal drilling and secondary recovery technologies, where
applicable. As of December 31, 2003, our Rocky Mountain properties included an
inventory of 69 development and 21 exploratory drilling locations.
WILLISTON BASIN
Cedar Hills Field. The Cedar Hills Field was discovered in November 1994.
During the twelve months ended December 31, 2003, the Cedar Hills Field
properties produced 3,092 net Boe per day to our interests. 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 us 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.
From April 1995through December 31, 2003, we drilled or participated in 229
gross (224 net) horizontal wells, of which 222 were successfully completed, for
a 97% net success rate. We believe that the Red River "B" formation in the Cedar
Hills Field is well suited for enhanced secondary recovery using either HPAI
and/or traditional water flooding technology. Both technologies have been
applied successfully in adjacent secondary recovery units for over 30 years and
have proven to increase oil recoveries from the Red River "B" formation by 200%
to 300% over primary recovery. We are proficient using either technology and are
in the process of implementing both as part of our secondary recovery operations
in the Cedar Hills Field. Effective March 1, 2001, we obtained approval for two
secondary recovery units in the Cedar Hills Field; the Cedar Hills North-Red
River "B" Unit, or the CHNRRU located in Bowman and Slope Counties, North Dakota
and the West Cedar Hills Unit, or WCHU located in Fallon County, Montana. We own
96% of the working interest in the CHNRRU and are the operator of the unit. The
CHNRRU contains 143 wells and 50,000 acres. We own 100% of the working interest
in the WCHU and are the unit operator. The WCHU contains 14 wells and 8,000
acres. An estimated $6.1 million will need to be invested during 2004 to fully
implement our secondary recovery operations in the Cedar Hills Field. By the
second quarter of 2004, we expect to have completed the 65 required injectors
and installed facilities to begin injection in 100% of the units. The north half
of the Cedar Hills Field began showing response to HPAI in November 2003. This
increase in production should continue through 2006 when the field should be
fully responding to HPAI. The Cedar Hills Field represents 50% of our estimated
proved reserves and $401.9 million, or 49%, of the PV-10 of our proved reserves
at December 31, 2003.
Medicine Pole Hills, Medicine Pole Hills West, Medicine Pole Hills South,
Buffalo, West Buffalo and South Buffalo Units. In 1995, we 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, 2003, these units produced 2,264 Boe
per day, net to our interests, and represented 11.6 MMBoe and $77.9 million, or
9%, of the PV-10 attributable to our estimated proved reserves as of December
31, 2003. These units are HPAI enhanced recovery projects that produce from the
Red River "B" formation and are operated by us. All were discovered and
developed with conventional vertical drilling. The oldest vertical well in these
units has been producing for 47 years, demonstrating the long-lived production
characteristic of the Red River "B" formation. There are 131 producing wells in
these units and current estimates of remaining reserve life range from four to
13 years. We subsequently expanded the Medicine Pole Hills Unit through
horizontal drilling into the Medicine Pole Hills West Unit, or MPHWU, which
became effective April 1, 2000. The MPHWU produces from 18 wells and encompasses
an additional 22 square miles of productive Red River "B" reservoir. We own
approximately 80% of the MPHWU and began secondary injection November 22, 2000.
The MPHWU was the first in a scheduled two-phase expansion of the Medicine Pole
Hills Unit. Phase two of the expansion plan was successfully completed during
2001 delineating another 20 square miles of productive Red River B reservoir
through horizontal drilling. The Medicine Pole Hills South Unit, or the MPHSU
became effective October 1, 2002, and injection started in 2003.
Lustre and Midfork Fields. In January 1992, we acquired the Lustre and
Midfork Fields, which during the twelve months ended December 31, 2003, produced
367 Bbls per day, net to our 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 44 wells producing in the two fields. We
currently own 99,000 net acres in the Lustre and Midfork Field area of which
70,000 net leasehold acres remain undeveloped.
We believe new reserves can be found on this undeveloped leasehold from the
Charles C, Mission Canyon, Lodgepole, and Nisku reservoirs. These new reservoirs
would come from drilling 12 exploratory locations identified from our 60 square
miles of proprietary 3-D seismic data. During 2002, we tested the first of these
locations and made a modest discovery in the Lodgepole formation. The discovery
is significant since it established production 200 miles from the prolific
Lodgepole fields near Dickinson, North Dakota. A development well drilled by us
in 2003, offsetting the discovery was unsuccessful in establishing commercial
production. We are assessing results and contemplating plans for further testing
and development, but have no drilling scheduled for 2004.
MB Project, Richland County, Montana. During 2003, we commenced operations
in a new area that based on information developed to date, we expect to be
another significant discovery of oil in the Rocky Mountain Region. We believe
that the potential recoverable reserves of oil in this area could exceed 100
million gross barrels of oil, which potentially, could result in the addition of
25 million net barrels to our proved reserve base. The producing reservoir is
the Bakken Formation which is a widespread, Devonian age shale deposited within
the central portions of the Williston Basin. The Bakken is known to contain
hydrocarbons throughout the Williston Basin and is considered to be one of the
primary source rocks for the basin. Within the MB Project area, the Bakken is
over-pressured and contains commercially producible quantities of oil and gas.
Although this is a new venture for us, the activity in this area has been
emerging over the last two years through the efforts of other operators. We
delayed entry into this area and elected to monitor activity until the economics
could be supported by results. Approximately 50 wells have been drilled by other
operators in this area to date, with 100% success and initial flow rates of up
to 1500 barrels of oil per day, or BOPD. Combined, these wells are currently
producing in excess of 300,000 barrels of oil per month. The area is being
developed using a combination of horizontal drilling and fracture technology at
a cost of $2.0-$2.5 million per well. Wells are drilled to a vertical depth
averaging 9,500' from which two opposing horizontal legs are drilled. Each
horizontal leg is approximately 5,000 feet in length for a total footage drilled
of 19,500 per well. Wells typically take 45 days to drill and 30 days to
complete. A total of 10 rigs are drilling in this area and we believe over 200
wells will ultimately be drilled within the potentially productive area.
During 2003, we assembled approximately 65,000 net acres and successfully
drilled and completed four producers in the MB Project. These producers were
completed flowing 400 to 1200 BOPD and assigned gross proved developed reserves
averaging 500,000 barrels of oil, or 500 MBO, per well. We have identified an
additional 54 wells to drill in the MB Project over the next 2 years. Of these
54 wells, 21 have been classified as PUD and assigned gross reserves of 500 MBO
per well in our 2003 reserve report. We anticipate most of the remaining
locations will be classified as proved undeveloped, or PUD, by year-end 2004.
Our average working interest in these wells should exceed 70%. At this time we
have one rig drilling continuously in the MB Project and we plan to add a second
rig in April 2004 with a third rig possibly moving in during the fourth quarter
2004.
BIG HORN BASIN
Worland Field During the twelve months ended December 31, 2003, the Worland
Field properties produced 1,510 Boe per day, net to our interests. These
properties cover 78,000 net leasehold acres in the Worland Field of the Big Horn
Basin in northern Wyoming, of which 27,000 net acres are held by production and
51,000 net acres are non-producing or prospective. Approximately two-thirds of
our producing leases in the Worland Field are within five federal units, the
largest of which, the Cottonwood Creek Unit, has been producing for more than 40
years. All of the units produce principally from the Phosphoria formation, which
is the most prolific oil producing formation in the Worland Field. Four of the
units are unitized as to all depths, with the Cottonwood Creek Field Extension
(Phosphoria) Unit being unitized only as to the Phosphoria formation. We are the
operator of all five of the federal units. We also operate 38 producing wells
located on non-unitized acreage. Our Worland Field properties include interests
in 313 producing wells; and we operate 297, or 95% of these wells.
As of December 31, 2003, the estimated net proved reserves attributable to
our Worland Field properties were approximately 8.1 MMBoe, with an estimated
PV-10 of $50.5 million. Approximately 87%, by volume, of these proved reserves
consist of oil, principally in the Phosphoria formation. Oil produced from our
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. Oil from the Worland
Field is sold at a price based on NYMEX less a differential ranging from $4.00 -
$6.00 per barrel. 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.
We believe that secondary and tertiary recovery projects have significant
potential for the addition of reserves in the Worland Field area fields. We
continue to seek the best method for increasing recovery from the producing
reservoirs. Currently, we have one Tensleep waterflood project and one pilot
imbibitions flood underway. We implemented water injection into five wells in
late 2002 to evaluate secondary and pressure recovery techniques that will best
process the Phosphoria dolomite oil reserves. Production should be enhanced in
as many as 20 offset wells. We have installed the system for expansion if the
results meet expectations. In addition to the secondary and pressure recovery
projects, we have evaluated infill drilling opportunities identifying 36
locations scheduled for drilling beginning in 2006, which we estimate will add
3.5 MMBoe to our proved reserves. As evidenced by past infill drilling and acid
fracturing stimulations, reserve growth can be significant.
MID-CONTINENT REGION
Our Mid-Continent properties are located primarily in the Anadarko Basin of
western Oklahoma and the Texas Panhandle. During 2001, we expanded our
operations in the Mid-Continent through the acquisition of Farrar Oil Company's
assets in the Anadarko and Illinois Basins and expanding exploration into the
Black Warrior Basin. At December 31, 2003, our estimated proved reserves in the
Mid-Continent totaled 11.4 MMBoe and represented 22% of our PV-10. At December
31, 2003, approximately 65% of our estimated proved reserves in the
Mid-Continent were natural gas. Net daily production from these properties
during 2003 averaged 1,895 Bbls of oil and 15,517 Mcf of natural gas, or 4,481
Boe to our interests. Our Mid-Continent leasehold position includes 99,000 net
developed and 65,000 net undeveloped acres, representing 13% and 9% of our total
net leasehold, respectively, at December 31, 2003. As of December 31, 2003, our
Mid-Continent properties included an inventory of 33 development and 44
exploratory drilling locations.
Anadarko Basin. The Anadarko Basin properties contained 71% of our
estimated proved reserves for the Mid-Continent region and 18% of our total
PV-10 at December 31, 2003, and represented 60% of our estimated proved reserves
of natural gas. During the twelve months ended December 31, 2003, net daily
production from our Anadarko Basin properties averaged 767 Bbls of oil and
14,020 Mcf of natural gas, or 3,103 Boe to our interests from 649 gross (302
net) producing wells, 352 of which are operated by us. Our Anadarko Basin wells
produce from a variety of sands and carbonates in both stratigraphic and
structural traps in the Arbuckle, Oil Creek, Viola, Mississippian, Springer,
Morrow, Red Fork, Oswego, Skinner and Tonkawa formations, at depths ranging from
6,000 to 12,000 feet. These properties have been a steady source of cash flow
for us and are continually being developed by infill drilling, recompletions,
workovers, new leasing and exploratory drilling. Average net daily production
for 2003 was up approximately 4% over 2002, but increased significantly more
during the fourth quarter of 2003 with the completion of two wells, each capable
of producing up to 5,000 Mcf daily. During 2003, we drilled 13 wells, with 11
completed as producers and two dry holes. As of December 31, 2003, we had
identified 27development and 22 exploratory drilling locations on our properties
in the Anadarko Basin. We plan to drill 20 wells in 2004 with a majority of the
drilling focused in the prolific Morrow-Springer reservoirs of Blaine County,
Oklahoma.
Illinois Basin. Our Illinois Basin properties contained 25% of our
estimated proved reserves for the Mid-Continent region and 4% of our total PV-10
at December 31, 2003. Net daily production during the twelve months ended
December 31, 2003, averaged 1,124 Bbls of oil and 203 Mcf of natural gas, or
1,157 Boe to our interests from 761 gross (613 net) producing wells, 651, or 86%
of which are operated by us. Approximately 77% of our net oil production in this
basin comes from 32 active secondary recovery projects. Our expertise results in
very efficient operations combined with low decline rates which make most of the
properties very long lived. Many of the projects have been active for over 16
years with many years of economic life remaining. Two new secondary recovery
projects are planned for implementation during 2004. All properties are
constantly being evaluated and we are continually performing numerous workovers
and making injection enhancements. As of December 31, 2003, we had five
development and 17 exploratory drilling locations. All of the exploratory drill
sites were selected from interpretations utilizing detailed geological studies
and computer mapping with all but one defined by seismic programs shot by us. In
addition, we have six active exploration project areas with seismic programs to
cover the majority of these areas to be shot during 2004. Included in this
seismic program are three projects where the use of 3-D seismic technology will
be employed.
Black Warrior Basin. In April 2000, we began a grass roots effort to expand
our exploration program into the Black Warrior Basin located in eastern
Mississippi and western Alabama. The basis for the expansion was to capitalize
on our in-house geologic expertise and add opportunities for shallow gas to our
drilling program. The play offers significant upside, with minimal competition,
low acreage and drilling costs as well as substantial room for expansion given
success. Reservoirs are Pennsylvanian and Mississippian age sands found at
depths of 2,500 feet to 4,500 feet with reserves of .75 Bcf per well on average.
As of December 31, 2003, we had acquired 26,000 net acres and acquired licenses
to approximately 1,500 miles of 2-D seismic data across the basin.
Results to date have not met with expectations and we are contemplating
exiting the play. Net daily production during the twelve months ended December
31, 2003, averaged 514 Mcf of natural gas or 86 Boe to our interests. During
2003, we drilled two wells and established one producer. We plan to drill two
wells during 2004 and the results of these wells will dictate our continued
commitment to the basin.
GULF COAST
Our Gulf Coast activities are located primarily in South Texas and include
the Pebble Beach and Luby Projects located in Nueces County, Texas. We also own
a majority position in and operate the Jefferson Island Project in Iberia
Parish, Louisiana and we participate in non-operated shallow Gulf of Mexico
wells through a joint venture arrangement with Challenger Minerals, Inc. At
December 31, 2003, our estimated proved reserves in the Gulf Coast totaled .8
MMBoe (87% gas) representing 3% of our total PV-10 and 6% of our estimated
proved reserves of natural gas. During 2003, our Gulf Coast producing wells
represented only 5% of our total producing well count, but produced 33% of our
total gas production for the year. Net daily production from these properties is
281 Bbls of oil and 9,489 Mcf of natural gas or 1,862 Boe to our interests from
115 gross (93 net) producing wells. Our leasehold position includes 8,000 net
developed and 14,000 net undeveloped acres representing 1% and 2% of our total
leasehold respectively. From a combined total of 160 square miles of proprietary
3-D data, a total of 23 development and 16 exploratory locations have been
identified for drilling on these projects.
South Texas. The Pebble Beach and Luby projects target the prolific Frio
and Vicksburg sands underlying and surrounding the Clara Driscoll and Luby
fields in Nueces County, Texas. These sandstone reservoirs produce on structures
readily defined by seismic and remain largely untested below the existing
producing reservoirs in the fields at depths ranging from 6,000 feet to 13,000
feet. At December 31, 2003, our estimated proved reserves in the Pebble
Beach/Luby fields totaled 3,000 MMcf or 4% of our estimated proved reserves of
natural gas. Net daily production during the twelve months ended December 31,
2003, averaged 96 Bbls of oil and 6,977 Mcf of gas, or 1,259 Boe to our
interests. We own 20,000 gross and 16,000 net acres and have acquired 95 square
miles of proprietary 3-D seismic data in these two projects. From the
proprietary 3-D data, we have identified 22 development and 7 exploratory
locations for drilling from the proprietary 3-D data.
During 2003, we drilled 12 wells in the Pebble Beach and Luby projects with
10 being completed as producing wells and two dry holes. Two significant
recompletions were also conducted during the year. The drilling and
recompletions activity increased net average daily production by 140% over 2002
production levels. We also expanded our exploration efforts in the Nueces County
area by acquiring an additional 65 square miles of proprietary 3-D seismic data
across our new Oakmont Project. The seismic data has identified several
potential drilling opportunities in the Oakmont Project and we have leased or
are in the process of acquiring leases on each. Efforts to expand our activity
in South Texas are ongoing and we expect to drill five development and two
exploratory wells in the Pebble Beach and Luby projects during 2004.
Jefferson Island. Our Jefferson Island project is an underdeveloped salt
dome that produces from a series of prolific Miocene sands. To date the field
has produced 111.2 MMBoe from approximately one quarter of the total dome. The
remaining three quarters of the faulted dome complex are essentially unexplored
or underdeveloped. We control 1,300 gross and 1,000 net acres in the project and
own 35 square miles of proprietary 3-D seismic covering the property. During
2003, we drilled one dry hole and conducted 1 recompletion of a successful
exploratory well originally completed in 2002. This recompletion proved
successful flowing 320 barrels of oil per day. The exploratory well was
successful and penetrated 180 feet of pay in multiple sands underlying a 3-D
imaged salt overhang along the flank of the salt dome complex. The discovery is
quite significant in that it confirmed our ability to image the salt and
encounter pay in sand reservoirs not previously known to produce in the field.
We have identified two additional exploratory drilling locations and plan to
drill one development and one exploratory well in 2004.
Gulf of Mexico. In July 1999 we elected to expand our drilling program into
the shallow waters of the Gulf of Mexico, or GOM through a joint venture
arrangement with Challenger Minerals, Inc. This was part of our ongoing strategy
to build our opportunity base of high rate of return, natural gas reserves in
the Gulf Coast region. The expansion into the GOM has proven successful and as
of December 31, 2003, we have participated in 19 wells that have resulted in 10
producers, eight dry holes, and one well junked and abandoned. During 2003, we
participated in three wells of which two were completed as producers and one was
junked and abandoned with plans to be redrilled in 2004. We currently have seven
wells in inventory of which five are to be drilled during 2004. Working interest
should average approximately 20% with risked investments limited to
approximately $1.0 million per well.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to our oil
and gas production, prices and costs attributable to all oil and gas property
interests owned by us for the periods shown:
Year Ended December 31,
----------------------------------------------
NET PRODUCTION DATA: 2001 2002 2003
-------------- -------------- ---------------
Oil and condensate (MBbl) 3,489 3,810 3,463
Natural gas (MMcf) 8,411 9,229 10,751
Total (MBoe) 4,893 5,352 5,255
UNIT ECONOMICS
Average sales price per Bbl (w/o hedges) $ 23.79 $ 24.05 $ 28.88
Average sales price per Bbl (with hedges) $ 23.87 $ 22.56 $ 25.98
Average sales price per Mcf $ 3.41 $ 2.46 $ 4.55
Average sales price per Boe (w/o hedges) $ 22.82 $ 21.36 $ 28.35
Average sales price per Boe (with hedges) $ 22.92 $ 20.32 $ 26.44
Production expense and taxes $ 7.52 $ 6.75 $ 9.11
DD&A expense per Boe $ 4.90 $ 5.04 $ 7.10
General and administrative expense per Boe $ 1.79 $ 1.99 $ 2.13
-------------- -------------- ---------------
Gross Margin $ 8.71 $ 6.54 $ 8.10
PRODUCING WELLS
The following table sets forth the number of our productive wells,
exclusive of injection wells and water wells, as of December 31, 2003. In the
table "gross" refers to total wells in which we had a working interest and "net"
refers to gross wells multiplied by our working interest.
OIL WELLS GAS WELLS TOTAL WELLS
-------------------------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
------------- ------------- ------------- ------------ ------------- -------------
ROCKY MOUNTAIN REGION
Williston Basin 331 296 1 0 332 296
Big Horn Basin (1) 312 278 1 1 313 279
------------- ------------- ------------- ------------ ------------- -------------
Total ROCKY MOUNTAIN 643 574 2 1 645 575
MID-CONTINENT REGION
Anadarko Basin 363 216 286 86 649 302
Texas Panhandle 10 5 20 12 30 17
Illinois Basin 718 572 43 41 761 613
Black Warrior Basin 1 1 6 4 7 5
------------- ------------- ------------- ------------ ------------- -------------
Total MID-CONTINENT 1,092 794 355 143 1,447 937
GULF COAST REGION
Louisiana Onshore 2 1 7 3 9 4
Luby 32 32 38 38 70 70
Offshore 2 0 9 1 11 1
Pebble Beach 3 3 20 13 23 16
Texas Onshore 0 0 2 2 2 2
------------- ------------- ------------- ------------ ------------- -------------
Total GULF COAST 39 36 76 57 115 93
TOTAL 1,774 1,404 433 201 2,207 1,605
============= ============= ============= ============ ============= =============
ACREAGE
The following table sets forth our developed and undeveloped gross and net
leasehold acreage as of December 31, 2003. In the table "gross" refers to total
acres in which we had a working interest and "net" refers to gross acres
multiplied by our working interest.
Developed Undeveloped Total
------------------------------- ------------------------ -------------------------------
Gross Net Gross Net Gross Net
--------------- --------------- ------------ ----------- --------------- ---------------
Rocky Mountain Region
Williston Basin 159,585 144,507 417,351 329,088 576,936 473,595
Big Horn Basin 28,568 27,489 52,872 50,971 81,440 78,460
Canada 0 0 17,117 17,117 17,117 17,117
Total Rocky Mountain 188,153 171,996 487,340 397,176 675,493 569,172
Mid-Continent Region
Anadarko Basin 106,889 67,493 32,862 24,694 139,751 92,187
Black Warrior Basin 2,441 1,501 36,452 24,467 38,893 25,968
Illinois Basin 39,422 29,997 9,963 9,963 49,385 39,960
New Mexico 0 0 560 560 560 560
Other 0 0 5,081 5,079 5,081 5,079
--------------- --------------- ------------ ----------- --------------- ---------------
Total Mid-Continent 148,752 98,991 84,918 64,763 233,670 163,754
Gulf Coast Region 20,064 8,002 25,813 13,708 45,877 21,710
--------------- --------------- ------------ ----------- --------------- ---------------
Total Gulf Coast 20,064 8,002 25,813 13,708 45,877 21,710
Grand Total Acreage 356,969 278,989 598,071 475,647 955,040 754,636
=============== =============== ============ =========== =============== ===============
DRILLING ACTIVITIES
The following table sets forth our drilling activity on its properties for
the periods indicated. In the table "gross" refers to total wells in which we
had a working interest and "net" refers to gross wells multiplied by our working
interest.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
2001 2002 2003
--------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
----------- ---------- ----------- ---------- ----------- ----------
DEVELOPMENT WELLS:
Productive 32 25.4 52 46.4 48 40.7
Non-productive 15 7.2 5 4.3 3 2.9
----------- ---------- ----------- ---------- ----------- ----------
Total 47 32.6 57 50.7 51 43.6
=========== ========== =========== ========== =========== ==========
EXPLORATORY WELLS:
Productive 11 5.7 16 12.8 11 7.8
Non-productive 10 5.5 9 6.2 4 2.8
----------- ---------- ----------- ---------- ----------- ----------
Total 21 11.2 25 19.0 15 10.6
=========== ========== =========== ========== =========== ==========
OIL AND GAS RESERVES
The following table summarizes the estimates of our net proved oil and gas
reserves and the related PV-10 of such reserves at the dates shown. Ryder Scott
Company Petroleum Engineers prepared the reserve and present value data with
respect to certain of our oil and gas properties, which represented 97.6% of our
PV-10 at December 31, 2001, 89.0% of our PV-10 at December 31, 2002, and 83.4%
of our PV-10 at December 31, 2003. We prepared the reserve and present value
data on all other properties.
(Dollars in thousands) December 31,
-----------------------------------------
Proved developed reserves: 2001 2002 2003
-------------- ------------ -------------
Oil (MBbl) 31,325 33,626 36,106
Natural Gas (MMcf) 56,647 69,273 63,327
Total (MBoe) 40,766 45,172 46,660
Proved undeveloped reserves:
Oil (MBbl) 28,406 29,655 36,894
Natural Gas (MMcf) (4,381) 674 3,769
Total (MBoe) 27,676 29,767 37,522
Total proved reserves:
Oil (MBbl) 59,731 63,281 73,000
Natural Gas (MMcf) 52,266 69,947 67,096
Total (MBoe) 68,442 74,939 84,182
PV-10$308,604 $633,396 $812,420
PV-10 represents the present value of estimated future net cash flows
before income tax discounted at 10%. In accordance with applicable
requirements of the Commission, estimates of our 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, 2001, 2002, and 2003 were $18.67 per Bbl of oil and
$1.96 per Mcf of natural gas, $29.04 per Bbl of oil and $3.33 per Mcf of
natural gas, and $30.49 per Bbl of oil and $4.64 per Mcf of natural gas,
respectively.
Estimated quantities of proved reserves and future net cash flows there
from 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
us, 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 we acquire properties containing
proved reserves or conduct successful exploitation and development activities,
our proved reserves will decline as reserves are produced. Our future oil and
gas production is, therefore, highly dependent upon our level of success in
finding or acquiring additional reserves.
GAS GATHERING, MARKETING AND PROCESSING SEGMENT
GAS GATHERING SYSTEMS
Eagle Chief Gas Plant and Gas Gathering System. In 1995 we completed
construction and commenced operation of our Eagle Chief Gas Processing Plant.
The plant is utilized to process gas purchased at the wellhead by us from
various producers and is located in Northwest Oklahoma near the town of Carmen.
We gather casinghead gas and natural gas from more than 300 wells that are
connected to the system. The gas is gathered through low-pressure pipelines and
is redelivered to the plant for processing. Natural gas liquids are extracted
from the gas stream at the plant. The liquids are transported via pipeline to
Koch's Medford facility for fractionation. Residue gas is sold at the tailgate
of the plant to either intrastate or interstate pipelines. Natural gas and
casinghead gas are purchased at the wellhead primarily under market sensitive
percent-of-proceeds-index contracts or fee-based contracts. Under
percent-of-proceeds-index contracts, we receive a fixed percentage of the
monthly index posted price for natural gas and a fixed percentage of the resale
price for natural gas liquids. We generally receive between 20% and 30% of the
posted index price for natural gas sales and 20% to 30% of the proceeds received
from the natural gas liquids. Under the fee-based contracts, we receive a fixed
rate per MMBTU for gas sold. This rate per MMBTU remains fixed regardless of
commodity prices.
Matli Gas Plant and Gas Gathering System. In 2003 we completed construction
and commenced operation of our Matli Gas Processing Plant. The plant is utilized
to process gas purchased at the wellhead by us from various producers and is
located in Central Oklahoma near the town of Watonga. The system, which was
constructed in 1998, gathers natural gas from more than 35 wells that are
connected to the system. The gas is gathered through low-pressure pipelines and
is redelivered to the plant for processing. Natural gas liquids are extracted
from the gas stream at the plant. The liquids are transported via truck to
Koch's Medford facility for fractionation. Residue gas is sold on an intrastate
pipeline located at the tailgate of the plant. Natural gas and casinghead gas
are purchased at the wellhead primarily under fee-based contracts. Under the
fee-based contracts, we receive a fixed rate per MMBTU for gas sold. This rate
per MMBTU remains fixed regardless of commodity prices.
Badlands Gas Plant & Gas Gathering System. In 1998 we completed
construction and commenced operation of our Badlands Gas Processing Plant. The
plant, which is located in North Dakota, is utilized to process gas purchased at
the wellhead by us from various producers that are located in North Dakota,
South Dakota and Montana. We gather casinghead gas and natural gas from more
than 150 wells that are connected to the system. The gas is gathered through
low-pressure pipelines and is redelivered to the plant for processing. Natural
gas liquids are extracted from the gas stream at the plant. Propane is derived
from the fractionation of natural gas liquids at the plant. The propane is sold
to various end-users at the tailgate of the plant. The remaining natural gas
liquids are transported via truck for fractionation. Residue gas is sold at the
tailgate of the plant to end-users or on the interstate pipeline located at the
tailgate of the plant. Natural gas and casinghead gas are purchased at the
wellhead primarily under market sensitive percent-of-proceeds-index contracts.
Under percent-of-proceeds-index contracts, we receive a fixed percentage of the
monthly index posted price for natural gas and a fixed percentage of the resale
price for natural gas liquids. We generally receive between 0% and 50% of the
posted index price for natural gas sales and 50% to 90% of the proceeds received
from the natural gas liquids.
OIL AND GAS MARKETING
Our oil and gas production is sold primarily under market-sensitive or spot
price contracts. We sell substantially all of our casinghead gas to purchasers
under varying percentage-of-proceeds contracts. By the terms of these contracts,
we receive 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 our gas. We normally receive 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 our 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 us from the sale of
natural gas liquids are included in natural gas sales. As a result of the
natural gas liquids contained in our production, we have historically improved
our price realization on our natural gas sales as compared to Henry Hub or other
natural gas price indexes. For the year ended December 31, 2003, purchases of
our natural gas production by Crosstek Corpus Christi accounted for 30% of our
total gas sales for such period and for the same period purchases of our oil
production by Link Energy Corporation, formerly EOTT Energy Corporation,
accounted for 65% of our total produced oil sales. Due to the availability of
other markets, we do not believe that the loss of any crude oil or gas customer
would have a material effect on our results of operations.
Periodically we utilize various price risk management strategies to fix the
price of a portion of our future oil and gas production. We do not establish
hedges in excess of our 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 what we pay the hedging partner and below which the
hedging partner pays us. These contracts allow us to predict with greater
certainty the effective oil and gas prices to be received for our hedged
production and benefit us when market prices are less than the fixed prices
provided in our forward-sale contracts. However, we do not benefit from market
prices that are higher than the fixed prices in such contracts for our hedged
production. In August 1998, we began engaging in oil trading arrangements as
part of our oil marketing activities. Under these arrangements, we contracted to
purchase oil from one source and to sell oil to an unrelated purchaser, usually
at disparate prices. During the second quarter of 2002, we discontinued crude
oil trading contracts.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are a party to litigation or other legal proceedings
that we consider to be a part of the ordinary course of our business. We are not
involved in any legal proceedings nor are we a party to any pending or
threatened claims that could reasonably be expected to have a material adverse
effect on our financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is no established trading market for our common stock. As of March
29, 2004, there were three record holders of our common stock. We issued no
equity securities during 2003. During 2000, we established a Stock Option Plan
with 1,020,000 shares available, of which options to purchase an aggregate of
172,000 shares have been granted.
ITEM 6. SELECTED FINANCIAL 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, 1999, 2000,
2001, 2002, and 2003 and the balance sheet data as of December 31, 1999, 2000,
2001, 2002 and 2003, have been derived from, and should be reviewed in
conjunction with, our consolidated financial statements, and the notes thereto.
Ernst & Young LLP audited our financial statements for 2003 and 2002; Arthur
Andersen LLP audited the remaining years. The balance sheets as of December 31,
2002, and 2003, and the statements of operations for the years ended December
31, 2001, 2002 and 2003, 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.
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
Statement of Operating Data: YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
(Dollars in thousands, except per share data) 1999 2000 2001 2002 2003
--------------- ----------------- ---------------- ---------------- ------------
Revenue:
Oil and Gas Sales $ 65,949 $ 115,478 $ 112,170 $ 108,752 $ 138,948
Crude Oil Marketing Income 241,630 279,834 245,872 153,547 168,092
Change in Derivative Fair Value - - - (1,455) 1,455
Gas Gathering, Marketing and Processing 21,563 32,758 44,988 33,708 74,459
Oil and Gas Service Operations 3,368 5,760 6,047 5,739 9,114
--------------- ----------------- ---------------- ---------------- -------------
Total Revenues 332,510 433,830 409,077 300,291 392,068
Operating Costs and Expenses:
Production 14,796 20,301 28,406 28,383 37,604
Production Taxes 4,572 9,506 8,385 7,729 10,251
Exploration 3,191 9,965 15,863 10,229 17,221
Crude Oil Marketing 236,135 278,809 245,003 152,718 166,731
Gas Gathering, Marketing and Processing 18,391 28,303 36,367 29,783 68,969
Oil and Gas Service Operations 3,420 5,582 5,294 6,462 8,046
Depreciation, Depletion and Amortization
of Oil and Gas Properties 15,638 15,738 23,678 26,942 37,329
Depreciation and Amortization of Other Assets 3,911 3,814 4,053 4,438 5,038
Property Impairments 5,154 5,631 10,113 25,686 8,975
ARO Accretion - - - - 1,151
General and Administrative 4,540 7,142 8,753 10,713 11,178
--------------- ----------------- ---------------- ---------------- -------------
Total Operating Costs and Expenses 309,748 384,791 385,915 303,083 372,493
Operating Income (Loss) 22,762 49,039 23,162 (2,792) 19,575
Interest Income 310 756 630 285 108
Interest Expense (17,370) (16,514) (15,674) (18,401) (20,258)
Other Revenue (Expense), net 266 4,499 3,549 876 753
--------------- ----------------- ---------------- ---------------- -------------
Total Other Income (Expense) (16,794) (11,259) (11,495) (17,240) (19,397)
Change in Accounting Principle(2,048) - - - 2,162
Net Income (Loss) $ 3,920 $ 37,780 $ 11,667 $ (20,032) $ 2,340
=============== ================= ================ ================ =============
BASIC EARNING (LOSS) PER COMMON SHARE:
Earnings before cumulative effect of
accounting change $ 0.42 $ 2.63 $ $0.81 $ (1.39) $ 0.01
Cumulative effect of accounting change (0.15) - - - 0.15
--------------- ----------------- ---------------- ---------------- -------------
Basic $ 0.27 $ 2.63 $ 0.81 $ (1.39) $ 0.16
=============== ================= ================ ================ =============
DILUTED EARNING (LOSS) PER COMMON SHARE:
Earnings before cumulative effect of
accounting change $ 0.42 $ 2.62 $ 0.81 $ (1.39) $ 0.01
Cumulative effect of accounting change (0.15) - - - 0.15
--------------- ----------------- ---------------- ---------------- -------------
Diluted $ 0.27 $ 2.62 $ 0.81 $ (1.39) $ 0.16
============ == ================= ================ ================ =============
OTHER FINANCIAL DATA:
Adjusted EBITDA$ 49,184 $ 89,442 $ 81,048 $ 65,664 $ 90,150
Net cash provided by operations 26,179 72,262 63,413 46,997 65,246
Net cash used in investing (15,972) (44,246) (106,384) (113,295) (108,791)
Net cash provided by (used in) financing (15,602) (31,287) 43,045 61,593 43,302
Capital expenditures57,530 51,911 111,023 113,447 114,145
RATIOS:
Adjusted EBITDA to interest expense 2.8x 5.4x 5.2x 3.6x 4.5x
Total funded debt to Adjusted EBITDA3.5x 1.6x 2.2x 3.6x 3.1x
Earnings to fixed charges1.2x 3.3x 1.7x N/A 1.1x
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents $ 10,421 $ 7,151 $ 7,225 $ 2,520 $ 2,277
Total assets 282,559 298,623 354,485 406,677 484,988
Long-term debt, including current maturities 170,637 140,350 183,395 247,105 290,920
Stockholder's equity 86,666 123,446 135,113 115,081 116,932
Change in accounting principle in the year 1999 represents the cumulative effect impact of adopting EITF 98-10 "Accounting
for Energy Trading and Risk Management Activities." The cumulative effect of change in accounting principle adjustment in
the year 2003 represents the adopting SFAS No. 143, Accounting for Asset Retirement Obligations.
Adjusted EBITDA represents earnings before change in accounting, interest expense, income taxes, depreciation, depletion,
amortization, accretion expense, impairment of property 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. Our
computation of adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that
adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our
ability to meet future debt service requirements, if any. Adjusted EBITDA does not give effect to our exploration
expenditures, which are largely discretionary by us and which, to the extent expended, would reduce cash available for debt
service, repayment of indebtedness and dividends. (See Item 15.(a)3. Exhibit 12.1 for EBITDA reconciliation)
Capital expenditures include costs related to our acquisitions of producing oil and gas properties and include the
contribution of the Worland properties by our principal stockholder of $22.4 million during the year ended December 31,
1999, and the purchase of the assets of Farrar Oil Company and Har-Ken Oil Company for $33.7 million during the year ended
December 31, 2001. Capital expenditures for 2002 included $47.2 million for Cedar Hill's development and $9.9 million for
capital leases. Capital expenditures for 2003 included $36.7 million for Cedar Hill's development and $4.7 million for
capital leases.
Total funded debt to Adjusted EBITDA excludes capital leases of $13.8 million in 2003 and $12.0 million in 2002. (See
Item 15.(a)3. Exhibit 12.1 for EBITDA reconciliation)
For purposes of computing the ratio of earnings to fixed charges, earnings are computed as income from continuing
operations before fixed charges. Fixed charges consist of interest expense and amortization of debt issuance costs. For the
year ended December 31, 2002, earnings were insufficient to cover fixed charges by $20.0 million, respectively. (See
Item 15.(a)3. Exhibit 12.2)
Reconciliation of Non-GAAP Measures
We define adjusted EBITDA as net income plus interest, income tax expense,
depreciation, depletion and amortization, and exploration expense. We have
included information in this report because investors use it as a measure of the
ability of a company to service or incur indebtedness and because it is a
financial measure commonly used in our industry.
A reconciliation of adjusted EBITDA to net income (loss) from continuing
operations as determined in accordance with generally accepted accounting
principles is as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1999 2000 2001 2002 2003
----------- ----------- ---------- ----------- -----------
Net Income (loss) $ 3,920 $ 37,780 $ 11,667 $ (20,032) $ 2,340
Add back:
Income taxes - - - - -
Interest expense 17,370 16,514 15,674 18,401 20,258
Depreciation, depletion and amortization 19,549 19,552 27,731 31,380 42,367
Property impairments 5,154 5,631 10,113 25,686 8,975
Accretion expense - - - - 1,151
Exploration expense 3,191 9,965 15,863 10,229 17,221
Less change in accounting principle - - - - (2,162)
----------- ----------- ---------- ----------- -----------
Adjusted EBITDA $ 49,184 $ 89,442 $ 81,048 $ 65,664 $ 90,150
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with our
consolidated financial statements and notes thereto and the selected
consolidated financial data included elsewhere herein.
OVERVIEW
Significant Events of 2003
Cedar Hills Units 2003 Summary
In 2003 CRI continued in its development of the secondary recovery projects
for the North Cedar Hills Unit in North Dakota. This huge secondary oil recovery
project continues to be on-schedule, both from an expense/cost standpoint and a
production standpoint, and 96% complete. High-pressure air injection was
initiated on January 14, 2003. A total of 24 in-fill horizontal injection wells
were drilled during 2003 at an approximate cost of $29 million. There were 48
wells converted to injection during 2003 for a cost of $10.5 million. Air
injection started in mid-January into four wells and by December injection
averaged 40 MMcfd into 47 wells. By December, nine wells were beginning to
respond to injection. The actual response time corresponds favorably with the
computer simulation and analog models.
Middle Bakken Field, Richland County, Montana
During 2003 we entered a new play that is proving to be another significant
discovery/development of oil in the Rocky Mountain Region. The potential size of
the discovery could rival that of Cedar Hills and be of similar proportion to
Continental's interest. The producing Bakken reservoir is widespread, Devonian
age shale deposited within the central portions of the Williston Basin. The
Bakken is considered to be one of the primary source rocks for the basin. This
play has been emerging over the last two years through the efforts of various
operators in the basin. The play is being developed using a combination of
horizontal drilling and frac technology. During 2003 we assembled approximately
65,000 net acres and successfully drilled and completed four producers. These
producers were completed flowing 400 to 1200 BOPD and gross PDP reserves average
500 MBO per well. We are planning to move a second rig and its horizontal
drilling experienced crews from the Cedar Hills project to the Middle Bakken
Field to develop acreage in the field recently acquired by CRI. We also have
plans to add a third rig later in the year in this field. Scheduled development
of this prolific field is expected to take three years.
Continental Gas, Inc.
CGI entered into a formal Purchase and Sale Agreement with Great Plains
Pipeline Company to acquire the Carmen Gathering System, effective August 1,
2003. The system is located in Woods, Alfalfa and Major Counties and is
comprised of 290 miles of pipeline connected to approximately 200 wells. The
system currently provides wellhead gathering for natural gas, crude oil and
saltwater.
Due to higher than normal commodity prices, many exploration companies have
increased their drilling programs. Acquisition of the system places CGI squarely
in the middle of an active exploration program being conducted by multiple
producers. Ownership of the system will allow CGI to compete for additional
supplies of natural gas to process through our Eagle Chief Plant.
Since the gas gathered by this system is currently processed by CGI at our
Eagle Chief Plant, the acquisition of this system is consistent with CGI's
strategy to expand and grow our assets in our core operating areas. CGI
currently owns and operates natural gas pipelines and processing plants in 6
states.
Growth has been the key driver to Continental Gas in 2003 with throughput
up by 50% over 2002. The increased volumes resulted from growth on the Company's
existing systems and the acquisition of the Carmen Gas Gathering System from
Great Plains Pipeline Company in mid-2003. Continental Gas, Inc. ("CGI") remains
a strong subsidiary of Continental Resources, contributing $5 million in
earnings in 2003 with good capital and natural gas throughput growth.
Continental Resources of Illinois, Inc.
Continental Resources of Illinois, Inc. ("CRII"), with Richard Straeter as
President, continues to develop its projects through teamwork and coordination
within all their departments. PV10 growth from $28.2 million in 2002 to $31.9
million in 2003 is a direct result of this teamwork. Their production has
recently been bolstered from their successful McCollum and Gannon waterfloods.
CRII's focus for 2003 is on continued reserve development, growth through
exploration, and secondary recovery.
RESULTS OF OPERATIONS
The following tables set forth selected financial and operating information
for each of the three years in the periods indicated:
December 31,
--------------------------------------------
(Dollars in thousands, except price data) 2001 2002 2003
- -------------------------------------------- ------------ ------------ ------------
Revenues $ 409,077 $ 300,291 $ 392,068
Operating expenses 385,915 303,083 372,493
Non-Operating income(11,495) (17,240) (17,235)
Net income (loss) 11,667 (20,032) 2,340
Adjusted EBITDA81,048 65,664 90,150
Production Volumes:
Oil and condensate (MBbl) 3,489 3,810 3,463
Natural gas (MMcf) 8,411 9,229 10,751
Oil equivalents (MBoe) 4,893 5,352 5,255
Average Prices:
Oil and condensate, without hedges ($/Bbl) $ 23.79 $ 24.05 $ 28.88
Oil and condensate, with hedges ($/Bbl) $ 23.87 $ 22.56 $ 25.98
Natural gas ($/Mcf) $ 3.41 $ 2.46 $ 4.55
Oil equivalents, without hedges ($/Boe) $ 22.82 $ 21.36 $ 28.35
Oil equivalents, with hedges ($/Boe) $ 22.92 $ 20.32 $ 26.44
Includes amount for change in accounting principle.
See "Item 6. Reconciliation of Non-GAAP Measures."
YEAR ENDED DECEMBER 31, 2003, COMPARED TO YEAR ENDED DECEMBER 31, 2002, AND YEAR
ENDED DECEMBER 31, 2002, COMPARED TO YEAR ENDED DECEMBER 31, 2001
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
REVENUES
OIL AND GAS SALES
During 2003, our oil and gas sales increased to $138.9 million versus
$108.8 million in 2002 and $112.2 million in 2001. In 2003, we produced 5,255
MBoe at an average price of $28.35 per Boe, compared to 5,352 MBoe at an average
price of $21.36 per Boe for 2002, and 4,893 MBoe at an average price of $22.82
per Boe in 2001.
In 2003, we realized an average price per barrel of oil of $28.88,
excluding hedges, compared to $24.05 in 2002, and $23.79 in 2001. Our hedging
activities resulted in a decrease in oil sales of $10.1 million or $1.91 per
barrel in 2003 and a decrease of $5.6 million or $1.49 per barrel in 2002. In
2001, our hedging activities resulted in an increase in oil sales of $293,000 or
$0.10 per barrel. Natural gas prices per MCF were $4.55 for 2003, $2.46 for
2002, and $3.41 for 2001.
Oil production made up 66% of our total produced volume for 2003, compared
to 71% in 2002 and 71% in 2001. The decrease in oil production from 2002 to 2003
was the result of converting producing wells into injectors in the Cedar Hills
Field in the Rocky Mountain region along with the natural decline in production
in this region. This was partially offset by the increase in gas production in
the Gulf region.
The following table shows our production by region for 2001, 2002, and
2003:
Year Ended December 31,
-------------------------------------------------------------------
2001 2002 2003
--------------------- --------------------- ----------------------
MBoe Percent MBoe Percent MBoe Percent
----------- ---------- --------- ------------ --------- -----------
Rocky Mountain 3,108 63.52% 3,265 61.01% 2,918 55.53%
Mid-Continent 1,485 30.35% 1,700 31.76% 1,659 31.57%
Gulf 300 6.13% 387 7.23% 678 12.90%
=========== ========== ========= ============ ========= ===========
4,893 100.00% 5,352 100.00% 5,255 100.00%
CRUDE OIL MARKETING
Prior to May 2002, we conducted crude oil trading activities, exclusive of
our own production. Such activity was discontinued in May 2002. Since May 2002,
we have entered into third party contracts to purchase and resell only our
physical production. We will continue to repurchase our physical production from
the Rocky Mountain area and resell equivalent barrels at Cushing, Oklahoma to
take advantage of better pricing and to reduce our credit exposure from sales to
our first purchaser. We present sales and purchases of our production from the
Rocky Mountain area as crude oil marketing income and crude oil marketing
expense, respectively. For the year ended December 31, 2003, we recognized
revenue of $168.1 million and expenses of $166.7 million on crude oil marketing
activities. In 2002 we recognized revenue of $153.5 million for revenues and
$152.7 million in expenses, which included revenues of $85.8 million, and
expenses of $85.1 million related to crude oil trading activities discontinued
in May 2002. In 2001 we recognized revenue of $245.9 million and $245.0 million
for expenses, which included revenues of $98.4 million, and expenses of $97.8
million related to crude oil trading activities that were discontinued.
CHANGE IN DERIVATIVE FAIR VALUE
We recognized $1.5 million of derivative fair value income in 2003,
compared to a loss of $1.5 million in 2002, and no income or loss in 2001. The
2003 balance of $1.5 million and the 2002 loss of $1.5 million are the changes
in a fair value derivative not designated as a cash flow hedge. This derivative
contract terminated on December 31, 2003.
GAS GATHERING, MARKETING AND PROCESSING
Our 2003 gathering, marketing and processing revenues increased to $74.5
million, compared to $33.7 million in 2002, and $45.0 million in 2001. The
increase from 2002 to 2003 of $40.8 million was due to higher natural gas prices
and increased throughput volumes. The increased volumes resulted from growth on
our existing systems and the acquisition of the Carmen Gas Gathering System from
Great Plains Pipeline Company. In 2003, $8.2 million of additional revenues were
attributable to the Carmen Gas Gathering System acquisition.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenue was $9.1 million in 2003,
compared to $5.7 million in 2002, and $6.0 million in 2001. The increase in 2003
was due primarily to an increase in reclaimed oil income of $2.6 million due to
higher prices and approximately 40,000 more barrels of reclaimed oil sold from
our central treating unit in 2003. The decrease in 2002 from 2001 was due to
lower prices in 2002 and fewer volumes of reclaimed oil sold from our central
treating unit in 2002.
COSTS AND EXPENSES
PRODUCTION EXPENSES
Our production expenses were $37.6 million in 2003, compared to $28.4
million in 2002 and in 2001. The increase of $9.2 million in 2003 was mainly the
result of increased energy costs of $5.5 million, or a 69% increase due to HPAI
costs in the Cedar Hills unit, which began in 2003, and additional HPAI in MPHU
started in 2003. The increased number of field employees in 2003 contributed to
a $1.2 million, or 25% increase in labor costs in 2003. On a unit of production
basis, production expenses were as follows:
On a Boe Basis 2001 2002 2003
---------- ---------- -----------
Production expenses, without taxes $ 5.81 $ 5.30 $ 7.16
Production expenses and taxes $ 7.52 $ 6.75 $ 9.11
PRODUCTION TAXES
Our production taxes were $10.3 million in 2003 compared to $7.7 million in
2002 and $8.4 million in 2001. The increase of $2.6 million, or 33% was the
result of higher oil and gas prices in 2003 compared to 2002. The decrease of
$0.7 million in 2002 was primarily the result of lower gas prices in 2002
compared to 2001.
EXPLORATION EXPENSE
In 2003, our exploration expenses were $17.2 million compared to $10.2
million in 2002 and $15.9 million in 2001. Exploration expenses in 2003
increased $7.0 million compared to 2002 from an increase in 2003 dry hole costs
of $2.7 million primarily in the South Texas area of the Gulf Coast region, $2.5
in the Rocky Mountain region, and $1.2 million in the Mid-Continent region and
seismic expenses. The decrease from 2001 to 2002 was mainly due to a decrease in
dry hole expense of $6.9 million, offset by an increase of $1.3 million in
seismic and geological and geophysical expenses along with a $0.9 million
increase in other expenses. Exploration expenses in 2003 increased $7.0 million
compared to 2002 from an increase in dry hole and seismic expenses.
CRUDE OIL MARKETING EXPENSE
We discontinued our crude oil trading activities effective May 2002. Prior
to May 2002, we entered into third party contracts to purchase and resell crude
oil. Although we no longer enter into third party contracts, we will continue to
repurchase our physical production from our Rocky Mountain region and resell
equivalent barrels at Cushing, Oklahoma, to take advantage of better pricing and
to reduce our credit exposure from sales to our first purchaser. We present
sales and purchases of our production from our Rocky Mountain region as crude
oil marketing income and crude oil marketing expense, respectively. We
recognized crude oil marketing expenses of $166.7 million for 2003, compared to
$152.7 million for 2002, and $245.0 million for 2001.
GAS GATHERING, MARKETING AND PROCESSING
Our 2003 gathering, marketing and processing expenses increased to $69.0
million, compared to $29.8 million and $36.4 million in 2002 and 2001,
respectively. The $39.2 million, or 132% increase from 2002 to 2003 was due to
higher natural gas prices and increased throughput volumes. The increased
volumes resulted from growth on our existing systems and the acquisition of the
Carmen Gas Gathering System from Great Plains Pipeline Company. In 2003, $7.1
million of additional expenses were attributable to the Carmen Gas Gathering
System acquisition.
OIL AND GAS SERVICE OPERATIONS
During 2003, oil and gas service operations expenses increased to $8.0
million compared to $6.5 million in 2002 and $5.3 million in 2001. The volumes
treated at our central treating unit increased 30,000 barrels in 2003, which
contributed to the $1.2 million increase in the cost of purchasing and treating
oil for resale. In addition, labor related expenses increased $0.4 million
making up the $1.6 million, or 23% increase from 2002 to 2003. The increase from
2001 to 2002 was due to an increase in the cost of purchasing and treating
reclaimed oil for resale by $0.4 million, salaries increased $0.3 million and
general repairs and maintenance made up most of the remaining difference.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES
For the year ended December 31, 2003, depreciation, depletion and
amortization of oil and gas properties was $37.3 million, compared to $26.9
million for 2002 and $23.6 million for 2001. The average depreciation, depletion
and amortization rate per Boe was $7.10 for 2003, $5.04 for 2002, and $4.90 for
2001. The increase in DD&A rates for 2003 compared to 2002 was caused by higher
production decline rates in the Gulf Coast region.
DEPRECIATION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
Depreciation and amortization of other property and equipment was $5.0
million in 2003 compared to $4.4 million in 2002 and $4.1 million in 2001. The
increase in 2003 was primarily due to higher depreciation cost on fixed assets
related to the acquisition of the Carmen Gathering System on August 1, 2003.
PROPERTY IMPAIRMENTS
During 2003, we recorded property impairments of $9.0 million, compared to
$25.7 million in 2002 and $10.1 million in 2001. This includes impairment of our
nonproducing leaseholds as well as FASB 144 impairments. In 2003, leasehold
impairment was $4.8 million compared to $23.4 million in 2002. The majority of
the 2002 impairment was related to our acquisition of leasehold properties in
the Worland Field. Our acquisition included 466 proved undeveloped, or PUD,
locations with a PV-10 value of $145.5 million. We allocated $26.7 million to
these potential locations as part of the acquisition price. We have not
developed any of the identified PUD locations during the past 5 1/2 years due to
capital constraints imposed by our development of the Cedar Hills Field. A
review of the PUD valuation by our reservoir-engineering department of the
original Ryder Scott report indicates that Ryder Scott's analysis of reserve
potential was accurate for the up-dip portion of the field, but potentially not
applicable to all identified PUD locations. As a result, an impairment change of
$13.5 million was recorded in 2002 on these PUD locations. We initiated a
detailed review of the remaining PUD locations by a consulting firm and the
results were completed on January 2004. This review involved geostatistical
analysis of all available data and development of a neural network correlation
to predict well performance. After economic analysis of specific locations the
recommendation is to begin drilling these locations in 2006. Leasehold
impairment was $5.2 million in 2001, representing a more normalized expense.
We may be required to write-down the carrying value of our oil and gas
properties when oil and gas prices are depressed or unusually volatile or as a
result of reserve revisions, 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. We recorded a $3.8 million FASB 144 write-downs in 2003 compared to a $2.3
million FASB 144 write-down in 2002 and a $5.3 million FASB 144 write-down in
2001.
GENERAL AND ADMINISTRATIVE EXPENSE
Our general and administrative expense for 2003 was $11.2 million compared
to $10.7 million for 2002 and $8.8 million for 2001. The majority of the $0.5
million increase in 2003 is the result of increased salaries and employment
expenses due to an increased number of employees in 2003. The $1.9 million
increase in 2002 was primarily attributable to an increased number of employees
in 2002 compared to 2001.
INTEREST EXPENSE
Our interest expense for 2003 was $20.3 million compared to interest
expense in 2002 of $18.4 million and $15.7 million in 2001. The increase in
interest expense in 2002 and 2003 was the result of additional interest paid on
our credit facility due to higher average debt balances outstanding.
NET INCOME
Our net profit for 2003 was $2.3 million compared to a $20.0 million loss
in 2002 and a profit of $11.7 million in 2001. The 2003 increase of $22.3
million reflects the higher oil and gas prices in 2003, which created an
increase in oil and gas sales of $30.2 million, the increase in production costs
and expenses of $11.7 million, the reduction of property impairments of $16.7
million, the increase in DD&A expense of $11.0 million, and the cumulative
effect of change in accounting principal adjustment of $2.2 million for the
adoption of SFAS No. 143 on January 1, 2003. The 2002 decrease of $31.7 million
reflects, among other items, the lower gas prices in 2002, which created a
decrease in gas revenues of $8.0 million, an increase in DD&A expense and
property impairments of $18.6 million, a $4.5 million decrease in gathering,
marketing and processing margins, an increase in interest expense of $2.1
million, and a decrease in other income of $2.6 million.
FINANCIAL CONDITION
CASH FLOWS
Our primary sources of liquidity have been cash flow from operating
activities, financing provided by our credit facility and by our principal
stockholder, and a private debt offering. Our cash requirements, other than for
operations, are for acquisition, exploration, exploitation and development of
oil and gas properties and debt service payments.
CASH FLOW FROM OPERATING ACTIVITIES
Our net cash provided by operating activities was $ 65.2 million for 2003
compared to $47.0 million for 2002 and $63.4 million in 2001. At December 31,
2003, we had a working capital deficit of $15.3 million, cash and cash
equivalents of $2.3 million and available capital on our credit facility of
$12.0 million. The working capital deficit is not indicative of our inability to
pay our liabilities but rather a result of cash management. The increase in 2003
was mostly due to the increase in net income from operations, which was
attributable to higher oil and gas prices in 2003. The decrease in 2002 was
primarily due to the decrease in net income from operations, which was primarily
attributable to the decreased gas prices and crude oil hedging losses.
INVESTING ACTIVITIES
We spent $114.1 million in 2003 compared to $113.4 million in 2002 and
$111.0 million in 2001 on acquisitions, exploration, exploitation and
development of oil and gas properties. Our total estimated proved reserves
increased from 68.4 MMBoe in 2001 to 74.9 MMBoe in 2002 and 84.2 MMBoe in 2003.
Our estimated total proved oil reserves increased from 59.7 MMBbls at year-end
2001 to 63.3 MMBbls at year-end 2002 and 73.0 MMBbls at year-end 2003 and
natural gas increased from 52.3 Bcf at year-end 2001 to 69.9 Bcf at year-end
2002 and decreased slightly to 67.1 Bcf at year-end 2003. In 2002, we sold
approximately 12 MBbls of reserves and in 2003 we sold 318 MBbls and 2033 MMcf
of reserves.
FINANCING ACTIVITIES
Our long-term debt, including current portion, was $290.9 million at
December 31, 2003 compared to $247.1 million at December 31, 2002, and $183.4
million at December 31, 2001. The $43.8 million, or 18% increase in 2003 was
primarily due to the increase in our bank debt of $24.9 million for development
of Cedar Hills, a $17.0 million increase in bank debt of Continental Gas, Inc.,
or CGI, for the Carmen Gathering System, and additional capital leases of $1.9
million. The $63.7 million, or 35%, increase in 2002 was primarily attributable
to a $51.8 million increase in our bank debt along with capital leases of $12.0
million. We used the majority of the proceeds of our 2003 and 2002 borrowings
for development of the Cedar Hills Field and the purchase of the Carmen
Gathering System.
LIQUIDITY AND CAPITAL REQUIREMENTS
CREDIT FACILITY
We had $132.9 million outstanding debt balance under our primary credit
facility at December 31, 2003. Our secured credit facility matures on March 28,
2005. Borrowings under our credit facility bear interest based on a rate per
annum equal to the rate at which eurodollar deposits for one, two, three or six
months are offered by the lead bank plus an applicable margin ranging from 150
to 250 basis points or the lead bank's reference rate plus an applicable margin
ranging from 25 to 50 basis points. The effective rate of interest under our
credit facility was 3.75% at December 31, 2003 and 4.37% at December 31, 2002.
At December 31, 2003, the borrowing base of our credit facility was $145.0
million. The borrowing base is re-determined semi-annually. Borrowings under our
credit facility are secured by liens on substantially all of our assets.
Between December 31, 2003 and March 29, 2004, we have drawn $7.5 million
under our credit facility and currently $140.4 million is outstanding under this
facility. On October 22, 2003, our subsidiary, Continental Gas, Inc., or CGI,
established a new $35.0 million secured credit facility consisting of a senior
secured term loan facility of up to $25.0 million and a senior revolving credit
facility of up to $10.0 million. The initial advance under the term loan
facility was $17.0 million, which was paid to us to reduce the outstanding
balance on our credit facility. No funds were initially advanced under the
revolving loan facility. Advances under either facility can be made, at the
borrower's election, as reference rate loans or LIBOR loans and, with respect to
LIBOR loans, for interest periods of one, two, three, or six months. Interest is
payable on reference rate loans monthly and on LIBOR loans at the end of the
applicable interest period. The principal amount of the term loan facility is to
be amortized on a quarterly basis through June 30, 2006, the final payment being
due September 30, 2006. The amount available under the revolving loan facility
may be borrowed, repaid and reborrowed until maturity on September 30, 2006.
Interest on reference rate loans is calculated with reference to a rate equal to
the higher of the reference rate of Union Bank of California, N.A. or the
federal funds rate plus 0.5%. Interest on LIBOR loans is calculated with
reference to the London interbank offered interest rate. Interest accrues at the
reference rate or the LIBOR rate, as applicable, plus the applicable margin. The
margin is based on the then current senior debt to EBITDA ratio. The credit
agreement contains certain covenants and requires certain quarterly mandatory
prepayments of 75% of excess cash flow. The credit facility is secured by a
pledge of all of the assets of CGI.
On October 22, 2003, CGI ceased to be a guarantor of our obligations under
our credit agreement. At that time, the borrowing base under the amended credit
agreement was revised to $145.0 million and our outstanding balance was reduced
by the $17.0 million funded to CGI.
SENIOR SUBORDINATED NOTES
On July 24, 1998, we issued $150.0 million of our 10 1/4% Senior
Subordinated Notes due August 1, 2008, in a private placement. Interest on the
senior subordinated notes is payable semi annually on each February 1 and August
1. In connection with the issuance of the senior subordinated notes, we incurred
debt issuance costs of approximately $4.7 million, which we have capitalized as
other assets and amortize on a straight-line basis over the life of the senior
subordinated notes.
During 2001, we repurchased $3.0 million principal amount of our senior
subordinated notes at a cost of $2.7 million. We wrote off $0.1 million of the
issuance costs associated with the repurchased senior subordinated notes.
FUTURE CAPITAL EXPENDITURES AND COMMITMENTS
We had capital expenditures of $114.1 million during the year ended
December 31, 2003. We will initiate, on a priority basis, as many projects as
cash flow allows. We anticipate that we will initiate approximately 88 projects
in 2004 for projected capital expenditures of $81.9 million. However, the amount
and timing of capital expenditures may vary depending on the rate at which we
expand and develop our oil and gas properties and whether we consummate
additional debt at its final maturities
Although we cannot provide any assurance, assuming successful
implementation of our strategy, including the future development of our proved
reserves and realization of our cash flows as anticipated, we believe that
borrowings available to us under our credit facilities, the remaining balance of
our unrestricted cash and cash flows from operations will be sufficient to
satisfy our current expected capital expenditures, working capital and debt
service obligations for the foreseeable future. The actual amount and timing of
our future capital requirements may differ materially from our estimates as a
result of, among other things, the market prices of oil and natural gas, and
regulatory, technological and competitive developments. Sources of additional
financing may include commercial bank borrowings, vendor financing and the sale
of equity or debt securities. We cannot assure you that any such financing will
be available on acceptable terms or at all.
STOCKHOLDER DISTRIBUTION
During 2003, we paid no dividends to our stockholders. The terms of the
indenture and our credit facility restrict our ability to pay dividends.
However, because we are an "S Corporation" for federal income tax purposes, we
pay dividends to our shareholders in an amount sufficient to pay the taxes on
our taxable income passed through to the shareholders.
HEDGING
From time to time, we utilize energy derivative contracts to hedge the
price or basis risk associated with the specifically identified purchase or
sales contracts, oil and gas production or operational needs. Prior to January
1, 2001, we accounted for changes in the market value of derivative instruments
used for hedging as a deferred gain or loss until the production month of the
hedged transaction, at which time the gain or loss on the derivative instruments
was recognized in earnings. Effective January 1, 2001, we account for derivative
instruments in accordance with SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities." The specific accounting treatment for
changes in the market value of the derivative instruments used in hedging
activities is determined based on the designation of the derivative instruments
as a cash flow, fair value, or foreign currency exposure hedge, and
effectiveness of the derivative instruments.
Additionally, in the normal course of business, we will enter into fixed
price forward sales contracts related to our oil and gas production to reduce
our sensitivity to oil and gas price volatility. We deem forward sales contracts
that will result in physical delivery of our production to be in the normal
course of our business and we do not account for them as derivatives. Revenues
from fixed price sales contracts in the normal course of business are recognized
as production occurs. As of December 31, 2003, we had no fixed price swaps or
forward contracts in place.
Our amended credit agreement requires us to have 50% of our oil production
hedged on a rolling six-month term. Beginning in October 2003, we established
costless collars to satisfy this requirement and at December 2003 we had the
following costless collars in place. These contracts are being accounted for as
cash flow hedges.
In order to mitigate price risk exposure on production, CGI has forward
sales contracts in place that will result in the physical delivery of production
and qualify as being in the normal course of business sales and are not
accounted for as derivatives. As of December 31, 2003, CGI has 50,000 MMBTU per
month hedged from January 2004 thru December 2007 at an average price of $4.579
per MMBTU. These hedges account for 9% of the total delivery point volumes and
4% of overall company throughput.
The following table summarizes our hedged contracts in place at December
31, 2003:
2004 2005 2006 2007
---- ---- ---- ----
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 600,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Collars:
Contract Volumes (Bbls)
Floor 1,115,000 - - -
Ceiling 1,115,000 - - -
Weighted-average Fixed Price per Bbl
Floor $ 22.00 $ - $ - $ -
Ceiling $ 35.24 $ - $ - $ -
OBLIGATIONS AND COMMITMENTS
We have the following contractual obligations and commitments as of
December 31, 2003:
Payments Due by Period ($ in thousands)
More Than
Contractual Obligations Total 1 Year 1 - 3 Years 3 - 5 Years 5 Years
------------------------------------------------------------------------
Long-Term Debt $ 277,050 $ 2,428 $ 147,472 $ 127,150 $ -
Capital Lease Obligations 13,827 3,336 10,005 486 -
Operating Lease Obligations - - - - -
Purchase Obligations 43 12 31 - -
Asset Retirement Obligations 26,609 899 1,767 3,301 20,642
Other Long-Term Obligations - - - - -
------------------------------------------------------------------------
Total Contractual Cash Obligations $ 317,529 $ 6,675 $ 159,275 $ 130,937 $ 20,642
CRITICAL ACCOUNTING POLICIES AND PRACTICES
Our consolidated financial statements and notes to our consolidated
financial statements contain information that is pertinent to the following
Management's Discussion and Analysis. Preparation of financial statements in
conformity with accounting principles generally accepted in the United States
requires that our management make estimates, judgments and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and
the disclosure of contingent assets and liabilities. However, the accounting
principles used by us generally do not change our reported cash flows or
liquidity. Generally, accounting rules do not involve a selection among
alternatives, but involve a selection of the appropriate policies for applying
the basic principles. Interpretation of the existing rules must be done and
judgments made on how the specifics of a given rule apply to us.
In management's opinion, the more significant reporting areas impacted by
management's judgments and estimates are crude oil and natural gas reserve
estimation, asset retirement obligations, impairment of assets, and derivative
instruments. Management's judgments and estimates in these areas are based on
information available from both internal and external sources, including
engineers, geologists and historical experience in similar matters. Actual
results could differ from the estimates, as additional information becomes
known.
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
We utilize the successful efforts method of accounting for our oil and gas
exploration and development activities. Exploration expenses, including
geological and geophysical costs, rentals and dry holes, are charged against
income as incurred. Costs of successful wells and related production equipment
and developmental dry holes are capitalized and amortized on an individual
property basis using the unit-of-production method as oil and gas is produced.
The accounting method may yield significantly different operating results than
the full cost method.
Depreciation, depletion and amortization, or DD&A of capitalized
exploratory drilling and development costs of producing oil and gas properties
are generally computed using the units of production method on an individual
property or unit basis based on total estimated proved developed oil and gas
reserves. Amortization of producing leasehold is based on the unit-of-production
method using total estimated proved reserves. In arriving at rates under the
unit-of-production method, the quantities of recoverable oil and natural gas are
established based on estimates made by our geologists and engineers. Gas
gathering systems and gas processing plants are depreciated using the
straight-line method over an estimated useful life of 14 years. Service
properties, equipment and other assets are depreciated using the straight-line
method over estimated useful lives of 5 to 40 years. Upon sale or retirement of
depreciable or depletable property, the cost and related accumulated DD&A are
eliminated from the accounts and the resulting gain or loss is recognized.
As stated above, DD&A of capitalized exploratory drilling and development
costs of producing oil and gas properties are generally computed using the units
of production method on total estimated proved developed oil and gas reserves.
However, successful efforts of accounting provides that in instances in which a
significant amount of development costs relate to both proved developed and
proved undeveloped reserves, a distortion in the DD&A rate would occur if such
development costs were amortized over only proved developed reserves. At
December 31, 2003, we have capitalized drilling and development costs of
approximately $168.6 million related to the high-pressure air injection project
currently in process in the Cedar Hills Field. Proved reserves associated with
this field are approximately 42.2 MBoe of which 28.5 MBoe or 67% are proved
undeveloped. At December 31, 2003, we have excluded approximately $112.9 million
or 67% of the development costs from its costs base for purposes of computing
DD&A. In future periods, the proved undeveloped reserves will be transferred to
proved developed as such reserves meet the definition of proved reserves under
SEC guidelines. Costs associated with the Cedar Hills Field will be added to the
cost base based on the ratio of proved developed reserves to proved undeveloped
reserves. Our future DD&A rate on this field could be significantly impacted by
upward or downward revisions in the oil and gas reserve estimates associated
with this field.
OIL AND GAS RESERVES AND STANDARDIZED MEASURE OF FUTURE CASH FLOWS
Our geologists and engineers and independent engineers, prepare the
estimates of our oil and gas reserves and associated future net cash flows.
Current accounting guidance allows only proved oil and gas reserves to be
included in our financial statement disclosures. The SEC has defined proved
reserves as the estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Even though our geologists and engineers, and independent
engineers are knowledgeable and follow authoritative guidelines for estimating
reserves, they must make a number of subjective assumptions based on
professional judgments in developing the reserve estimates. Reserve estimates
are updated at least annually and consider recent production levels and other
technical information about each field. Periodic revisions to the estimated
reserves and future cash flows may be necessary as a result of a number of
factors, including reservoir performance, new drilling, oil and gas prices and
cost changes, technological advances, new geological or geophysical data, or
other economic factors. We cannot predict the amounts or timing of future
reserve revisions. If such revisions are significant, they could significantly
alter future DD&A and /or result in impairment of assets that may be material.
ASSET RETIREMENT OBLIGATIONS
In June 2001, the FASB issued SFAS No. 143, which applies to legal
obligations associated with the retirement of long-lived assets that result from
the acquisition, construction, development and/or the normal operation of a
long-lived asset. The primary impact of this standard on us relates to oil and
gas wells on which we have a legal obligation to plug and abandon. SFAS No. 143
requires us to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a corresponding increase in
the carrying amount of the related long-lived asset. The determination of the
fair value of the liability requires us to make numerous judgments and
estimates, including judgments and estimates related to the future salvage value
of well equipment, future costs to plug and abandon wells, future inflation
rates and estimated lives of the related assets.
IMPAIRMENT OF ASSETS
All of our long-lived assets are monitored for potential impairment when
circumstances indicate that the carrying value of the asset may be greater than
its future net cash flows, including cash flows from risk adjusted provable
reserves. The evaluations involve a significant amount of judgment since the
results are based on estimated future events, such as future sales prices for
oil and gas, future costs to produce these products, estimates of future oil and
gas reserves to be recovered and the timing thereof, the economic and regulatory
climates and other factors. The need to test a field for impairment may result
from significant declines in sales prices or unfavorable adjustments to oil and
gas reserves. Any assets held for sale are reviewed for impairment when we
approve the plan to sell. Estimates of anticipated sales prices are highly
judgmental and subject to material revision in future periods. Because of the
uncertainty inherent in these factors, we cannot predict when or if future
impairment charges will be recorded.
DERIVATIVE ACTIVITY
We attempt to reduce our exposure to unfavorable oil and natural gas prices
by utilizing fixed-price physical delivery contracts and zero-cost collar
contracts. We account for these derivative contracts under the guidance
prescribed by Statement of Financial Accounting Standards No. 133, Accounting
for Derivative Instruments and Hedging Activities (SFAS No. 133). Except for
certain fixed price contracts qualifying for the normal sales exception under
SFAS No. 133, all derivative contracts are recorded as assets and liabilities in
the consolidated balance sheet at fair value, determined based on quoted market
prices. The counter parties to these contractual arrangements are limited to
creditworthy institutions.
The above description of our critical accounting policies is not intended
to be an all-inclusive discussion of the uncertainties considered and estimates
made by management in applying accounting principles and policies. Results may
vary significantly if different policies were used or required and if new or
different information becomes known to management.
Newly Issued Accounting Pronouncements
Statement of Financial Accounting Standards No. 141, Business Combinations
(FAS 141), and Statement of Financial Accounting Standards No. 142, Goodwill and
Other Intangible Assets (FAS 142), were issued in June 2001 and became effective
for the Company on July 1, 2001 and January 1, 2002, respectively. We understand
the majority of the oil and gas industry did not change accounting and
disclosures for mineral interest use rights upon the implementation of FAS 141
and 142. However, an interpretation of FAS 141 and 142 is being considered as to
whether mineral interest use rights in oil and gas properties are intangible
assets. Under this interpretation, mineral interest use rights for both
undeveloped and developed leaseholds would be classified as intangible assets,
separate from oil and gas properties. This interpretation would not affect our
results of operations or cash flows.
In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others-an Interpretation of FASB
Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34. For
certain guarantees, FIN 45 requires recognition at the inception of a guarantee
of a liability for the fair value of the obligation assumed in issuing the
guarantee. FIN 45 also requires expanded disclosures for outstanding guarantees,
even if the likelihood of the guarantor having to make any payments under the
guarantee is considered remote. The recognition provisions of FIN 45 were
effective for guarantees issued or modified after December 31, 2002. We have not
issued or modified any material guarantees within the scope of FIN 45 during
2003; therefore, implementation of this new standard has not impacted our
consolidated financial condition or results of operations.
In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities - an Interpretation of ARB No. 51. This interpretation
clarifies the application of ARB 51, Consolidated Financial Statements to
certain entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. Because application of the majority voting interest
requirement in ARB 51 may not identify the party with a controlling financial
interest in situations where controlling financial interest is achieved through
arrangements not involving voting interests, this interpretation introduces the
concept of variable interests and requires consolidation by an enterprise having
variable interests in previously unconsolidated entity if the enterprise is
considered the primary beneficiary, meaning the enterprise will absorb a
majority of the variable interest entity's expected losses or residual returns.
For variable interest entities in existence as of February 1, 2003, FIN 46, as
originally issued, required consolidation by the primary beneficiary in the
third quarter of 2003. In October 2003, the FASB deferred the effective date of
FIN 46 to the fourth quarter. We have reviewed the effects of FIN 46 relative to
its relationships with possible variable interest entities and have determined
that the adoption of such standard had no material impact on us as we have no
interests in any material variable interest entities.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to a variety of market risks including credit risks,
commodity price risk and interest rate risk. We address these risks through a
controlled program of risk management including the use of derivative
instruments.
COMMODITY PRICE EXPOSURE
We are exposed to market risk as the prices of crude oil, natural gas, and
natural gas liquids are subject to fluctuations resulting from changes in supply
and demand. To partially reduce price risk caused by these market fluctuations,
we may hedge (through the utilization of derivatives, including zero-cost
collars and fixed price contracts) a portion of our production and sale
contracts. A sensitivity analysis has been prepared to estimate the price
exposure to the market risk of our crude oil, natural gas and natural gas
liquids commodity positions. Our daily net commodity position consists of crude
inventories, commodity sales contracts and derivative commodity instruments. The
fair value of such position is a summation of the fair values calculated for
each commodity by valuing each net position at quoted futures prices. Market
risk is estimated as the potential loss in fair value resulting from a
hypothetical 10 percent adverse change in such prices over the next 12 months.
Based on this analysis, we have no significant market risk related to our
hedging portfolio. See "Hedging" paragraph in Item 7 above for discussion of
derivative and hedging contracts outstanding at December 31, 2003.
INTEREST RATE RISK
Our exposure to changes in interest rates relates primarily to long-term
debt obligations. We manage our interest rate exposure by limiting our
variable-rate debt to a certain percentage of total capitalization and by
monitoring the effects of market changes in interest rates. We might utilize
interest rate derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues. Interest rate
derivatives are used solely to modify interest rate exposure and not to modify
the overall leverage of the debt portfolio. The fair value of long-term debt is
estimated based on quoted market prices and management's estimate of current
rates available for similar issues. The following table itemizes our long-term
debt maturities and the weighted-average interest rates by maturity date.
2003
(Dollars in thousands) 2004 2005 2006 2007 Thereafter Total Fair Value
- --------------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Senior subordinated
notes
Principal amount $ - $ - $ - $ - $ 127,150 $ 127,150 $ 128,422
Weighted-average
interest rate 10.25% 10.25% 10.25% 10.25% 10.25%
- ---------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Credit facility
Principal amount $ 2,428 $ 135,327 $ 12,145 $ - $ - $ 149,900 $ 149,900
Weighted-average
interest rate 3.75% 3.75% 3.75% 3.75% 3.75%
- ---------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Capital lease agreement
Principal amount $ 3,336 $ 3,336 $ 3,336 $ 3,333 $ 486 $ 13,827 $ 13,827
Weighted-average
interest rate 3.75% 3.75% 3.75% 3.75% 3.75%
- ---------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Ford Credit agreement
Principal amount $ 12 $ 13 $ 10 $ 8 $ - $ 43 $ 43
Weighted-average
interest rate 5.50% 5.50% 5.50% 5.50% 5.50%
- ---------------------------------------------------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 15 Exhibits, Financial Statement Schedules, and Reports on Form
8-K
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Arthur Andersen LLP audited our financial statements for 2000 and 2001. As
a result of Andersen's liquidation, we changed our auditors to Ernst & Young LLP
on July 12, 2002. This change was reported in a current report on Form 8-K dated
July 16, 2002.
ITEM 9A. CONTROLS AND PROCEDURES
Our Chief Executive Officer and our Chief Financial Officer evaluated the
effectiveness of the design and operation of our disclosure controls and
procedures as of the end of the period covered by this report. Our disclosure
controls and procedures are the controls and other procedures that we designed
to ensure that we record, process, summarize, and report in a timely manner the
information we must disclose in reports that we file with the SEC. Our
disclosure controls and procedures include our internal accounting controls.
Based on the evaluation of our Chief Executive Officer and our Chief Financial
Officer, our disclosure controls and procedures are effective. There were no
significant changes in our internal controls or in other factors that could
significantly affect these controls subsequent to the date of our evaluation.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
AUDIT COMMITTEE FINANCIAL EXPERT
The Board of Directors has determined that Mark Monroe, a member of our
Audit Committee, qualifies as an Audit Committee Financial Expert and he meets
the requirements set forth in Section 407 of the Sarbanes-Oxley Act of 2002.
CODE OF ETHICS FOR SENIOR FINANCIAL OFFICERS
We have adopted a Business Code of Ethics which is available on our website
at http://www.contres.com. This code applies to our principal executive officer,
our principal financial officer, our principal accounting officer or controller,
or persons performing similar functions.
The following table sets forth names, ages and titles of our directors and
executive officers:
Name Age Position
- ----------------------- ------------- --------------------------------------
Harold Hamm (1) (3) 58 Chairman of the Board of Directors,
President, Chief Executive Officer,
Director
Jack Stark (1) (3) 49 Senior Vice President-Exploration,
Director
Jeff Hume (1) (3) 53 Senior Vice President-Resource
Development
Randy Moeder (1) (3) 43 President of Continental Gas, Inc.
Roger Clement (1) (4) 59 Senior Vice President, Chief Financial
Officer, Treasurer, Director
Mark Monroe (2) (3) 49 Director
H. R. Sanders (2) (4) 71 Director
Roger Farrell (4) 51 Director
- --------------------------------------------------------------------------------
(1) Member of the Executive Committee
(2) Member of the Audit Committee
(3) Term expires in 2005
(4) Term expires in 2004
HAROLD HAMM, L.L.M., has been our President and Chief Executive Officer and
a Director since our inception in 1967 and currently serves as Chairman of the
Board. Mr. Hamm is a long-time Oklahoma Independent Petroleum Association board
member and currently its Vice President of the Western Region. He is the founder
and served as the Chairman of Save Domestic Oil, Inc. Currently, Mr. Hamm is the
President of the National Stripper Well Association, serves on the Executive
Boards of the Oklahoma Independent Petroleum Association and the Oklahoma Energy
Explorers.
JACK STARK joined us as Vice President of Exploration in June 1992 and was
promoted to Senior Vice President and Director in May 1998. He holds a Masters
degree in Geology from Colorado State University and has 24 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 became our Senior Vice President of Resource Development in July
2002. He had been our Vice President of Drilling Operations 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 us, Mr. Hume held various engineering positions with Sun Oil Company,
Monsanto Company and FCD Oil Corporation. Mr. Hume is a Registered Professional
Engineer and member of the Society of Petroleum Engineers, Oklahoma Independent
Petroleum Association, and the Oklahoma and National Professional Engineering
Societies.
RANDY MOEDER has been President of Continental Gas, Inc. since January 1995
and was its Vice President from November 1990 to January 1995. Mr. Moeder was
our Senior Vice President and General Counsel from May 1998 to August 2000 and
was our Vice President and General Counsel from November 1990 to April 1998.
From January 1988 to summer 1990, Mr. Moeder was in private law practice. From
1982 to 1988, Mr. Moeder held various positions with Amoco Corporation. Mr.
Moeder is a member of the Oklahoma Independent Petroleum Association and the
Oklahoma and American Bar Associations. Mr. Moeder is also a Certified Public
Accountant.
ROGER CLEMENT became our Vice President, Chief Financial Officer, Treasurer
and a Director in March 1989 and was promoted to Senior Vice President in May
1998. He holds a Bachelor of Business Administration degree from the University
of Oklahoma and is a Certified Public Accountant. Prior to joining the Company,
Mr. Clement was a partner in the accounting firm of Hunter and Clement in
Oklahoma City for 17 years. The firm provided accounting, tax, audit and
consulting services for various industries. Mr. Clement's clients were primarily
involved in oil and gas and real estate. He was also a 50% partner in a
construction company from 1973 to 1984 that constructed residential real estate
and small commercial properties. He is a member of the Oklahoma Independent
Petroleum Association, the American Institute of Certified Public Accountants
and the Oklahoma Society of Certified Public Accountants.
MARK MONROE was the Chief Executive Officer and President of Louis Dreyfus
Natural Gas prior to its merger with Dominion Resources in October 2001. Prior
to the formation of Louis Dreyfus Natural Gas in 1990, he was the Chief
Financial Officer of Bogert Oil Company. He has served as the President of the
Oklahoma Independent Petroleum Association and on the Domestic Petroleum
Council, National Petroleum Council and on the Boards of the Independent
Petroleum Association of America, the Oklahoma Energy Explorers and the
Petroleum Club of Oklahoma City. Currently, he is a Board member of Unit
Corporation and the Oklahoma Independent Petroleum Association. Mr. Monroe is a
Certified Public Accountant and received his Bachelor of Business Administration
degree from the University of Texas at Austin.
H. R. SANDERS, JR. served as a Director of Devon Energy Corporation from
1981 through 2000. In addition, he held the position of Executive Vice President
of Devon from 1981 until his retirement in 1997. Prior to joining Devon, Mr.
Sanders served Republic Bank of Dallas, N.A. from 1970 to 1981 as the bank's
Senior Vice President with direct responsibility for independent oil, gas and
mining loans. Mr. Sanders is a former member of the Independent Petroleum
Association of America, Texas Independent Producers and Royalty owners
Association and Oklahoma Independent Petroleum Association. He currently is a
Director of Toreador Resources Corporation and a past Director of Triton Energy
Corporation.
ROGER FARRELL was the Chief Executive Officer and President of Enogex Inc.
from 1998 until his retirement in 2002. Enogex Inc. is a subsidiary of OG&E
Energy Corporation, which is a natural gas gathering, processing,
transportation, production, and energy services company. Prior to becoming
President, Mr. Farrell held various positions at Enogex, Inc. from 1989 to 2002.
Mr. Farrell received his Bachelor of Science degree in 1975 from Kansas State
University. He is a member of the Oklahoma Independent Petroleum Association,
founding Board member and Treasurer of the Oklahoma Explorers Club, Board member
and on the Audit and Finance Committee of the Southern Gas Association, and
Board member of the Gas Processors Association.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
Securities
Underlying
Other Annual Option All Other
Annual Compensation Compensation Compensation Compensation
--------------------------- -------------- ------------- ------------
# of
Name Year Salary Bonusshares
- ------------------ ------ ------------ -------------- -------------- ------------ -------------
Harold Hamm2003 $ - $ - $ - - $ -
2002 $ - $ - $ - - $ -
2001 $ - $ - $ - - $ -
Jack Stark 2003 $ 172,354.32 $ 6,685.95 $ - - $ 8,618
2002 $ 161,512.00 $ 36,651.00 $ - 8,000 $ 11,751
2001 $ 151,384.00 $ 17,996.00 $ - - $ 11,244
Jeff Hume 2003 $ 138,203.40 $ 5,925.46 $ - - $ 22,660
2002 $ 135,012.00 $ 20,450.00 $ - - $ 22,501
2001 $ 125,580.00 $ 15,747.00 $ - - $ 22,029
Roger Clement 2003 $ 163,828.00 $ 5,656.79 $ - - $ 6,412
2002 $ 146,424.00 $ 32,841.00 $ - - $ 8,544
2001 $ 127,500.00 $ 15,883.00 $ - - $ 12,068
Randy Moeder 2003 $ 142,333.00 $ 5,440.00 $ - - $ 22,828
2002 $ 132,619.00 $ 23,930.00 $ - - $ 21,625
2001 $ 124,208.00 $ 25,197.00 $ - - $ 21,217
Represents the value of perquisites and other personal benefits in excess of the lesser of
$50,000 or 10% of annual salary and bonus. For the years ended December 31, 2001, 2002 and
2003, we paid no other annual compensation to its named executive officers.
We adopted our 2000 Stock Option Plan effective October 1, 2000, and allocated a maximum
of 1,020,000 shares of Common Stock to this plan. Effective October 1, 2000, we granted
Incentive Stock Options to purchase 90,000 shares and Non-qualified Options to purchase
54,000 shares. Effective April 1, 2002, we granted Incentive Stock Options to purchase
13,000 shares and Non-qualified Options to purchase 5,000 shares. Effective July 1, 2002,
we granted Incentive Stock Options to purchase 5,000 shares and Non-qualified Options to
purchase 5,000 shares. There were no shares granted in 2003.
Represents contributions made by us to the accounts of executive officers under our profit
sharing plan and under our nonqualified compensation plan.
Received no compensation during the calendar year 2001, 2002 and 2003.
2003 Year-End Option Value
Number of Securities Underlying Value of Unexercised In-the-Money
Unexercised Options at 12/31/03 Options at 12/31/03
---------------------------------------- -----------------------------------
Name Exercisable (#) Unexercisable (#) Exercisable ($) Unexercisable ($)
- -------------------- ------------------- ------------------- ---------------- ------------------
Jack Stark 25,600 14,400 $ 368,400 $ 194,240
Jeff Hume 24,000 8,000 $ 341,280 $ 85,760
Roger Clement 32,000 8,000 $ 483,040 $ 85,760
Randy Moeder 17,000 8,000 $ 217,240 $ 85,760
The value of unexercised in-the-money options at December 31, 2003, is computed as the product
of the stock value at December 31, 2003, assumed to be $24.72 per share less the stock option
exercise price, and the number of underlying securities at December 31, 2003.
Equity Compensation Plan Information
This table gives information about our common stock that may be issued upon
the exercise of options, warrants of rights under our 2000 Stock Incentive Plan,
which is our only existing equity compensation plan. The table also includes
information with respect to our outstanding restricted stock that has not vested
and restricted stock available for issuance under our existing equity
compensation plan.
(a) (b) (c)
Number of
securities
remaining
available for
future issuance
under equity
Number of securities Weighted average compensation plan
to be issued exercise price of (excluding
upon exercise of outstanding options securities
outstanding options, warrants and rights reflected
warrants and rightsin column (a)
------------------- ------------------- -------------
Equity compensation
plans approved by
security holders 171,998 10.79 1,028,002
Equity compensation
plans not approved by
security holders - - -
------- ----- ---------
Total 171,998 10.79 1,028,002
For purposes of the calculation of the weighted average exercise price, all
options to purchase shares of stock granted under our existing equity
compensation plan were deemed to have an exercise price of $10.79.
Employment Agreements
We do not have formal employment agreements with any of our senior
management employees.
Stock Option Plan
We adopted our 2000 stock incentive plan effective October 1, 2000 to
encourage our key employees by providing opportunities to participate in our
ownership and future growth through the grant of incentive stock options and
nonqualified stock options. The plan also permits the grant of options to our
directors. Our Board of Directors presently administers the plan.
The maximum number of shares for which options may be granted under the
plan is 1,020,000 shares of common stock, subject to adjustment in the event of
any stock dividend, stock split, recapitalization, reorganization or certain
defined change of control events. Shares subject to previously expired,
canceled, forfeited or terminated options become available again for grants of
options.
The Chairman of the Board of Directors determines the number of shares and
other terms of each grant. Under this plan, we may grant either incentive stock
options or nonqualified stock options. The price payable upon the exercise of an
incentive stock option may not be less than 100% of the fair market value of our
common stock at the time of grant, or in the case of an incentive stock option
granted to an employee owning stock possessing more than 10% of the total
combined voting power of all classes of our common stock, 110% of the fair
market value on the date of grant. We may grant incentive stock options to an
employee only to the extent that the aggregate exercise price of all such
options under all of our plans becoming exercisable for the first time by the
employee during any calendar year does not exceed $100,000. We may not grant a
nonqualified stock option at an exercise price that is less than 50% of the fair
market value of our common stock on the date of grant.
Each option that we have granted or will grant under the plan will expire
on the date we specify, but not more than ten years from the date of grant or,
in the case of a 10% shareholder, not more than five years from the date of
grant. Unless otherwise agreed, an incentive stock option will terminate not
more than 90 days, or twelve months in the event of death or disability, after
the optionee's termination of employment.
An optionee may exercise an option by us giving written notice, accompanied
by full payment:
o in cash or by check, bank draft or money order payable to us;
o by delivering shares of our common stock or other equity securities
having a fair market value equal to the exercise price; or
o a combination of the foregoing.
Outstanding options become non-forfeitable and exercisable in full
immediately prior to certain defined change of control events. Unless otherwise
determined by us, outstanding options will terminate on the effective date of
our dissolution or liquidation.
The plan may be terminated or amended by us at any time subject, in the
case of certain amendments, to shareholder approval. If not earlier terminated,
the plan expires on September 30, 2010.
With certain exceptions, Section 162(m) of the Internal Revenue Code denies
a deduction to publicly held corporations for compensation paid to certain
executive officers in excess of $1.0 million per executive per taxable year
(including any deduction with respect to the exercise of an option). An
exception exists; however, for amounts received upon exercise of stock options
pursuant to certain grand fathered plans. Options granted under our plan are
expected to satisfy this exception.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The following table sets forth certain information regarding the beneficial
ownership of our common stock as of March 29, 2004, held by:
o Each of our directors who owns common stock,
o Each of our executive officers who owns common stock,
o Each person known or believed by the Company to own beneficially 5% or
more of our common stock, and
o All of our directors and executive officers as a group.
Unless otherwise indicated, each person has sole voting and dispositive
power with respect to such shares. The number of shares of common stock
outstanding for each listed person includes any shares the individual has the
right to acquire within 60 days of this prospectus.
Shares of Ownership
Name of Beneficial Owner Common Stock Percentage
- --------------------------------------------- --------------- ----------
Harold Hamm13,037,328 90.73%
Harold Hamm DST Trust and HJ Trust1,331,591 9.27%
Jack Stark27,200 *
Jeff Hume24,000 *
Roger Clement32,000 *
Randy Moeder17,000 *
All executive officers and directors as a group 13,137,528 90.80%
* Less than 1%.
Executive officer
Director
The trustee of each Trust is an independent trustee. Harold Hamm has no
voting or investment power over the assets in either Trust, and has no
power to direct the sale of any of the shares or our common stock held by
each such Trust. Harold Hamm disclaims beneficial interest in all shares of
our common stock held by each such Trust.
Represents shares that may be acquired upon the exercise of options which
are exercisable within the next 60 days.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Set forth below is a description of transactions entered into between us
and certain of our officers, directors, employees and stockholders during 2003.
Certain of these transactions will continue in the future and may result in
conflicts of interest between us and such individuals, and there can be no
assurance that conflicts of interest will always be resolved in favor of us.
Oil and Gas Operations. We are provided certain oilfield services by
companies which are substantially owned and are controlled by Harold Hamm, our
Chairman, President and Chief Executive Officer and principal shareholder. These
services include leasehold acquisition, well location, site construction and
other well site services, saltwater trucking, use of rigs for completion and
workovers of oil and gas wells and the rental of oil field tools and equipment.
The aggregate amounts paid by us to these affiliated companies during 2003 was
$13.6 million and at December 31, 2003, we owed these companies an aggregate of
approximately $2.3 million in current accounts payable. The services were
provided at costs and upon terms that management believes are no less favorable
to us than could have been obtained from unaffiliated parties. In addition,
Harold Hamm and certain companies controlled by him own interests in wells
operated by us. At December 31, 2003, we owed such persons an aggregate of $0.09
million, representing their shares of oil and gas production sold by us.
During 2001, in our capacity as operator of certain oil and gas properties
we began selling natural gas produced to Hiland Partners, LLC, which is 75%
owned by two of our executive officers. During 2003, we sold natural gas valued
at $1.0 million to Hiland Partners, LLC. We have two lease agreements with
Hiland Partners, each for a term of five years, expiring in 2007 and 2008,
respectively. These leases cover compressors we use in our Cedar Hills HPAI
project. The aggregate rentals payable by us under these leases is $16.7
million, of which $2.7 million had been paid as of December 31, 2003. These
leases have been capitalized on our financial statements and rental payments are
made monthly over the five-year terms. We believe that the terms of these lease
arrangements are no less favorable to us than we could have obtained from an
unrelated third party. Our independent directors approved the terms of this
lease.
Office Lease. We lease office space in buildings owned by Harold Hamm, our
Chairman, President and Chief Executive Officer and principal shareholder. In
2003, we paid monthly rents associated with these operating leases aggregating
approximately $505,000. The leases have terms of one year or less. We believe
that the terms of these leases are no less favorable to us than those that would
be obtained from unaffiliated parties. Our independent directors approved the
terms of these leases.
Participation in Wells. Certain of our officers and directors have
participated in, and may participate in the future in, wells drilled by us, or
in the case of our principal stockholder in the acquisition of properties. At
December 31, 2003, the aggregate unpaid balance owed to us by such officers and
directors was $6,251, none of which was past due.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following fees set forth our accounting fees and services for the
fiscal years ended December 31, 2003 and 2002 by Ernst & Young LLP, our
principal accounting firm for external auditing and Arthur Andersen LLP our
former auditors.
Year Ended
December 31,
2002 2003
------------------ ------------------
Audit Fees $ 148,274 $ 203,800
Audit-Related Fees - -
Tax Fees - -
All Other Fees - -
------------------ ------------------
Total $ 148,274 $ 203,800
In 2003, our audit committee adopted a formal policy concerning approval of
audit and non-audit services. The policy requires pre-approval of all audit and
non-audit services to be provided to us and our subsidiaries; provided that we
may establish guidelines for (i) the delegation of authority for pre-approval to
a single member of the committee and/or (ii) establishing a de minimis exception
in accordance with applicable laws and regulations.
Our audit committee has established guidelines for the retention of the
independent auditor for any allowed non-audit service. Under the policy, the
following non-audit services may not be performed by our auditor
contemporaneously with audit services:
o Bookkeeping or other services related to our accounting records or
financial statements and our subsidiaries;
o Financial information systems design and implementation;
o Appraisal or valuation services, fairness opinions, or
contribution-in-kind reports;
o Actuarial services;
o Internal audit outsourcing services;
o Management functions or human resources;
o Broker or dealer, investment advisor, or investment banking services;
o Legal services and expert services unrelated to the audit; and
o Any other service that the audit committee determines is
impermissible.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following consolidated financial statements of the Company and the
Reports of the Company's Independent Auditors thereon are included on pages
45 through 66 of this Form 10-K.
Reports of Independent Auditors
Consolidated Balance Sheets as of December 31, 2002 and 2003
Consolidated Statement of Operations for the three years in the period
ended December 31, 2003
Consolidated Statement of Cash Flows for the three years in the period
ended December 31, 2003
Consolidated Statement of Stockholder's Equity for the three years in the
period ended December 31, 2003
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES: None.
3. EXHIBITS:
DESCRIPTION AND METHOD OF FILING
2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc.
dated October 1, 2000. [2.1](4)
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc. [3.1](1)
3.2 Amended and Restated Bylaws of Continental Resources, Inc. [3.2](1)
3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3](1)
3.4 Bylaws of Continental Gas, Inc., as amended and restated.[3.4](1)
3.5 Certificate of Incorporation of Continental Crude Co. [3.5](1)
3.6 Bylaws of Continental Crude Co. [3.6](1)
4.1 Restated Credit Agreement dated April 21, 2000, among Continental
Resources, Inc. and Continental Gas Inc., as Borrowers and MidFirst
Bank as Agent (the `Credit Agreement') [4.4] (3)
4.1.1 Form of Consolidated Revolving Note under the Credit Agreement [4.4]
(3)
4.1.2 Second Amended and Restated Credit Agreement among Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and MidFirst Bank, dated July 9, 2001.
[10.1](5)
4.1.3 Third Amended and Restated Credit Agreement among Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc., as Borrowers, and MidFirst Bank, dated January 17,
2002. [4.13](7)
4.1.4 Fourth Amended and Restated Credit Agreement dated March 28, 2002,
among the Registrant, Union Bank of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1](8)
4.1.5 First Amendment to the Revolving Credit Agreement dated June 12, 2003,
among the Registrant, Union Bank of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1](9)
4.1.6 Second Amendment to the Revolving Credit Agreement dated October 22,
2003, among the Registrant, Union Bank of California, N.A., Guaranty
Bank, FSB and Fortis Capital Corp. [10.1](10)
4.2 Indenture dated as of July 24, 1998, between Continental Resources,
Inc. as Issuer, the Subsidiary Guarantors named therein and the United
States Trust Company of New York, as Trustee. [4.2](1)
10.1 Unlimited Guaranty Agreement dated March 28, 2002. [10.2](8)
10.2 Security Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.3](8)
10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.4](8)
10.4 Conveyance Agreement of Worland Area Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April
23, 1984, to Continental Resources, Inc. [10.4](2)
10.5 Purchase Agreement signed January 2000, effective October 1, 1999, by
and between Patrick Energy Corporation as Buyer and Continental
Resources, Inc. as Seller. [10.5](2)
10.6 + Continental Resources, Inc. 2000 Stock Option Plan. [10.6](4)
10.7 + Form of Incentive Stock Option Agreement. [10.7](4)
10.8 + Form of Non-Qualified Stock Option Agreement. [10.8](4)
10.9 Purchase and Sales Agreement between Farrar Oil Company and Har-Ken
Oil Company, as Sellers, and Continental Resources of Illinois, Inc.
as Purchaser, dated May 14, 2001. [2.1](5)
10.10 Collateral Assignment of Contracts dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as Agent. [10.5](8)
12.1 * Statement re computation of ratio of debt to Adjusted EBITDA.
[12.1](11)
12.2 * Statement re computation of ratio of earning to fixed charges.
[12.2](11)
12.3 * Statement re computation of ratio of adjusted EBITDA to interest
expense. [12.3](11)
21.0 * Subsidiaries of Registrant. [21](6)
31.1 * Certification pursuant to section 302 of the Sarbanes-Oxley Act of
2002 - Chief Executive Officer
31.2 * Certification pursuant to section 302 of the Sarbanes-Oxley Act of
2002 - Chief Financial Officer
99.1 Letter to the Securities and Exchange Commission dated March 28, 2002,
regarding the audit of the Registrant's financial statements by Arthur
Andersen LLP. [99.1](7)
- -------------
* Filed herewith
+ Represents management compensatory plans or agreements
(1) Filed as an exhibit to the Company's Registration Statement on Form S-4,
as amended (No. 333-61547), which was filed with the Securities and
Exchange Commission. The exhibit number is indicated in brackets and is
incorporated herein by reference.
(2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1999. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the fiscal quarter ended March 31, 2000. The exhibit number is indicated
in brackets and is incorporated herein by reference.
(4) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current report on Form 8-K dated July 18, 2001.
The exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 2001. The exhibit number is indicated
in brackets and is incorporated herein by reference.
(7) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(8) Filed as an exhibit to current report on Form 8-K dated April 11, 2002.
The exhibit number is indicated in brackets and is incorporated herein by
reference.
(9) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 2003. The exhibit number is indicated
in brackets and is incorporated herein by reference.
(10) Filed as an exhibit to current report on Form 8-K dated October 22, 2003.
The exhibit number is indicated in brackets and is incorporated herein by
reference.
(11) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2003. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(b) REPORTS ON FORM 8-K
On October 31, 2003, the Registrant filed a current report on Form 8-K
describing the Second Amended and Restated Credit Agreement with Union Bank of
California, N.A., Guaranty Bank, FSB and Fortis Capital Corp.
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 25, 2004 CONTINENTAL RESOURCES, INC.
By HAROLD HAMM
Harold Hamm
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in capacities and on the dates indicated.
Signatures Title Date
- ---------- ----- ----
HAROLD HAMM Chairman of the Board, President, Chief Executive Officer, March 25, 2004
Harold Hamm and Director (Principal Executive Officer)
ROGER V. CLEMENT Senior Vice President, Chief Financial Officer, Treasurer, March 25, 2004
Roger V. Clement and Director (Principal Financial Officer and Principal
Accounting Officer)
JACK STARK Senior Vice President of Exploration and Director March 25, 2004
Jack Stark
MARK MONROE Director March 25, 2004
Mark Monroe
H.R. SANDERS, JR. Director March 25, 2004
H.R. Sanders, Jr.
ROGER FARRELL Director March 25, 2004
Roger Farrell
Supplemental Information to be Furnished With Reports Pursuant to Section
15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to
Section 12 of the Act.
The Company has not sent, and does not intend to send, an annual report to
security holders covering its last fiscal year, nor has the Company sent a proxy
statement, form of proxy or other proxy soliciting material to its security
holders with respect to any annual meeting of security holders.
INDEX OF CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Auditors...............................................45
Copy of Report of Independent Public Accountants ............................46
Consolidated Balance Sheets as of December 31, 2002 and 2003.................47
Consolidated Statements of Operations for the Years Ended December 31,
2001, 2002 and 2003.....................................................49
Consolidated Statements of Stockholders' Equity
for the Years Ended December 31, 2001, 2002 and 2003....................50
Consolidated Statements of Cash Flows for the Years Ended December 31,
2001, 2002 and 2003.....................................................51
Notes to Consolidated Financial Statements...................................52
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and stockholders of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Continental
Resources, Inc. and subsidiaries as of December 31, 2003 and 2002, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the two years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. The consolidated financial statements of Continental Resources, Inc.
and subsidiaries as of December 31, 2001, were audited by other auditors who
ceased operations and whose report dated February 15, 2002, expressed an
unqualified opinion on those statements.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
As discussed above, the financial statements of Continental Resources, Inc. as
of December 31, 2001, and for the year then ended were audited by other auditors
who have ceased operations. As described in Note 10, the Company changed the
composition of its reportable segments in 2003, and the amounts in the 2001
financial statements relating to reportable segments have been restated to
conform to the 2003 composition of reportable segments. We audited the
adjustments that were applied to restate the disclosures for reportable segments
reflected in the 2001 financial statements. Our procedures included (a) agreeing
the adjusted amounts of segment revenues, operating income and assets to the
Company's underlying records obtained from management, and (b) testing the
mathematical accuracy of the reconciliation's of segment amounts to the
consolidated financial statements. In our opinion, such adjustments are
appropriate and have been properly applied. However, we were not engaged to
audit, review, or apply any procedures to the 2001 financial statements of the
Company other than with respect to such adjustments and, accordingly, we do not
express an opinion or any other form of assurance on the 2001 financial
statements taken as a whole.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Continental
Resources, Inc. and subsidiaries at December 31, 2003 and 2002, and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 2003, the Company adopted Statement of Financial Accounting Standards
No, 143, Accounting for Asset Retirement Obligations.
Oklahoma City, Oklahoma, ERNST & YOUNG LLP
March 25, 2004
INFORMATION REGARDING PREDECESSOR INDEPENDENT PUBLIC ACCOUNTANTS' REPORT
The following report is a copy of a previously issued report by Arthur Andersen
LLP ("Andersen"). Andersen has not reissued the report nor has Andersen
consented to its inclusion in this annual report on Form 10-K. The Andersen
report refers to the consolidated balance sheet as of December 31, 2000 and the
consolidated statements of operations, stockholders' equity, and cash flows for
the year ended December 31, 1999 and 2000, which are no longer included in the
accompanying 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,
2000 and 2001, and the related consolidated statements of income, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2001. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Continental
Resources, Inc. and subsidiaries as of December 31, 2000 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
Oklahoma City, Oklahoma ARTHUR ANDERSEN LLP
February 15, 2002
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
December 31,
--------------- -------------
CURRENT ASSETS: 2002 2003
--------------- -------------
Cash and cash equivalents $ 2,520 $ 2,277
Accounts receivable -
Oil and gas sales 14,756 19,035
Joint interest and other, net 7,884 13,577
Inventories 6,700 5,465
Prepaid expenses 450 336
Fair value of derivative contracts 628 151
--------------- -------------
Total current assets 32,938 40,841
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties, based on successful
efforts of accounting 522,213 601,325
Gas gathering and processing facilities 33,113 49,600
Service properties, equipment and other 18,430 19,515
--------------- -------------
Total property and equipment 573,756 670,440
Less accumulated depreciation,
depletion and amortization 205,853 231,008
--------------- -------------
Net property and equipment 367,903 439,432
OTHER ASSETS:
Debt issuance costs, net 5,828 4,707
Other assets 8 8
--------------- -------------
Total other assets 5,836 4,715
--------------- -------------
Total assets $ 406,677 $ 484,988
=============== =============
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
December 31,
---------------------------
CURRENT LIABILITIES: 2002 2003
-------------- ------------
Accounts payable $ 26,665 $ 27,950
Current portion of long-term debt 2,400 5,776
Revenues and royalties payable 5,299 8,250
Accrued liabilities:
Interest 6,273 6,312
Other 4,047 7,212
Fair value of derivative contracts 2,082 640
-------------- ------------
Total current liabilities 46,766 56,140
LONG-TERM DEBT, net of current portion 244,705 285,144
ASSET RETIREMENT OBLIGATION - 26,608
OTHER NONCURRENT LIABILITIES 125 164
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 1,000,000 shares
authorized, no shares issued and outstanding - -
Common stock, $0.01 par value, 20,000,000 shares
authorized, 14,368,919 shares issued and outstanding 144 144
Additional paid-in-capital 25,087 25,087
Retained earnings 89,850 92,190
Accumulated other comprehensive income - (489)
-------------- ------------
Total stockholders' equity 115,081 116,932
-------------- ------------
Total liabilities and stockholders' equity $ 406,677 $ 484,988
============== ============
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except share data)
December 31,
----------------------------------------------
REVENUES: 2001 2002 2003
------------ ------------ ------------
Oil and gas sales $ 112,170 $ 108,752 $ 138,948
Crude oil marketing 245,872 153,547 168,092
Change in derivative fair value - (1,455) 1,455
Gathering, marketing and processing 44,988 33,708 74,459
Oil and gas service operations 6,047 5,739 9,114
------------ ------------ ------------
Total revenues 409,077 300,291 392,068
OPERATING COSTS AND EXPENSES:
Production 28,406 28,383 37,604
Production taxes 8,385 7,729 10,251
Exploration 15,863 10,229 17,221
Crude oil marketing 245,003 152,718 166,731
Gathering, marketing and processing 36,367 29,783 68,969
Oil and gas service operations 5,294 6,462 8,046
Depreciation, depletion and amortization
of oil and gas properties 23,646 26,942 37,329
Depreciation and amortization of other
property and equipment 4,085 4,438 5,038
Property impairments 10,113 25,686 8,975
Asset retirement obligation accretion - - 1,151
General and administrative 8,753 10,713 11,178
------------ ------------ ------------
Total operating costs and expenses 385,915 303,083 372,493
OPERATING INCOME (LOSS) 23,162 (2,792) 19,575
OTHER INCOME (EXPENSES):
Interest income 630 285 108
Interest expense (15,674) (18,401) (20,258)
Other income, net 48 653 197
Gain on sale of assets 3,501 223 556
------------ ------------ ------------
Total other income (expense) (11,495) (17,240) (19,397)
------------ ------------ ------------
INCOME (LOSS) BEFORE
CHANGE IN ACCOUNTING PRINCIPLE 11,667 (20,032) 178
------------ ------------ ------------
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE - - 2,162
------------ ------------ ------------
NET INCOME $ 11,667 $ (20,032) $ 2,340
============ ============ ============
BASIC EARNINGS PER COMMON SHARE:
Earnings before cumulative effect
of accounting change $ 0.81 $ (1.39) $ 0.01
Cumulative effect of accounting change - - 0.15
------------ ------------ ------------
Basic $ 0.81 $ (1.39) $ 0.16
============ ============ ============
DILUTED EARNINGS PER COMMON SHARE:
Earnings before cumulative effect
of accounting change $ 0.81 $ (1.39) $ 0.01
Cumulative effect of accounting change - - 0.15
------------ ------------ ------------
Diluted $ 0.81 $ (1.39) $ 0.16
============ ============ ============
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, 2001, 2002 AND 2003
(Dollars in thousands)
Accumulated
Additional Other Total
Shares Common Paid-In Retained Comprehensive Stockholders'
Outstanding Stock Capital Earnings Income Equity
------------ ----------- ------------ ------------- ------------- --------------
BALANCE, December 31, 2000 14,368,919 $ 144 $ 25,087 $ 98,215 $ - $ 123,446
------------ ----------- ------------ ------------- ------------- --------------
Net Income - - - 11,667 - 11,667
------------ ----------- ------------ ------------- ------------- --------------
BALANCE, December 31, 2001 14,368,919 $ 144 $ 25,087 $ 109,882 $ - $ 135,113
------------ ----------- ------------ ------------- ------------- --------------
Net Loss - - - (20,032) - (20,032)
------------ ----------- ------------ ------------- ------------- --------------
BALANCE, December 31, 2002 14,368,919 $ 144 $ 25,087 $ 89,850 $ - $ 115,081
------------ ----------- ------------ ------------- ------------- --------------
Comprehensive Income:
Net Income - - - 2,340 - 2,340
Change in fair value of
derivative contracts - - - - (489) (489)
--------------
Total comprehensive income 1,851
------------ ----------- ------------ ------------- ------------- --------------
BALANCE, December 31, 2003 14,368,919 $ 144 $ 25,087 $ 92,190 $ (489) $ 116,932
============ =========== ============ ============= ============= ==============
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31, 2001, 2002 AND 2003
(Dollars in thousands)
2001 2002 2003
-------------- ------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 11,667 $ (20,032) $ 2,340
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Depreciation, depletion and amortization 27,731 31,380 42,473
Accretion of asset retirement obligation - - 1,151
Impairment of properties 6,595 25,686 8,975
Change in derivative fair value - 1,455 (1,455)
Amortization of debt issuance costs 534 1,171 1,633
Gain on sale of assets (3,460) (223) (239)
Change in accounting principle - - (2,162)
Dry hole costs 12,996 5,880 13,566
Cash provided by (used in) changes in assets and liabilities-
Accounts receivable 7,360 (4,383) (9,972)
Inventories (1,333) (379) 1,341
Prepaid expenses (278) 5 115
Accounts payable 5,411 4,089 1,285
Revenues and royalties payable (3,776) 1,895 2,951
Accrued liabilities (469) 414 3,204
Other noncurrent assets 435 5 -
Other noncurrent liabilities - 34 40
-------------- -------------- ---------------
Net cash provided by operating activities 63,413 46,997 65,246
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (67,843) (106,532) (95,880)
Gas gathering and processing facilities and service
properties, equipment and other (6,645) (6,260) (18,085)
Purchase of oil and gas properties (36,535) (655) (180)
Proceeds from sale of assets 4,639 152 5,354
-------------- -------------- ---------------
Net cash used in investing activities (106,384) (113,295) (108,791)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 52,245 138,830 49,405
Repayment of Senior Subordinated Notes (3,000) - -
Repayment of line of credit and other (6,200) (75,120) (5,590)
Debt issuance costs - (2,117) (513)
-------------- -------------- ---------------
Net cash provided by financing activities 43,045 61,593 43,302
NET INCREASE (DECREASE) IN CASH 74 (4,705) (243)
CASH and CASH EQUIVALENTS, beginning of year 7,151 7,225 2,520
-------------- -------------- ---------------
CASH and CASH EQUIVALENTS, end of year $ 7,225 $ 2,520 $ 2,277
============== ============== ===============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 15,269 $ 16,386 $ 20,386
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
ORGANIZATION
Continental Resources, Inc. ("CRI or Continental") 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. Effective June 1, 1997, the Company
converted to an S-corporation under subchapter S of the Internal Revenue Code.
Continental has three wholly owned subsidiaries, Continental Gas, Inc.
("CGI"), Continental Resources of Illinois, Inc. ("CRII") and Continental Crude
Co. ("CCC"). CGI was incorporated in April 1990, CRII was incorporated in June
2001 for the purpose of acquiring the assets of Farrar Oil Company and Har-Ken
Oil Company and CCC was incorporated in May 1998. Since its incorporation, CCC
has had no operations, has acquired no assets and has incurred no liabilities.
The Company operates principally in two segments:
1. Exploration and Production - Continental and Continental Resources of
Illinois, Inc.'s principal business is oil and natural gas exploration,
development and production. CRI and CRII have interests in approximately 2,207
wells and serve as the operator in the majority of these wells. CRI and CRII's
operations are primarily in Oklahoma, North Dakota, South Dakota, Montana,
Wyoming, Texas, Illinois, Mississippi and Louisiana.
2. Gas Gathering, Marketing and Processing - Continental Gas, Inc. is
engaged principally in natural gas marketing, gathering and processing
activities and currently operates seven gas gathering systems and three gas
processing plants in its operating areas. In addition, CGI participates with CRI
in certain oil and natural gas wells.
Basis of Presentation
The accompanying consolidated financial statements include the accounts and
operations of CRI, CRII, CGI and CCC (collectively the "Company"). All
significant inter-company accounts and transactions have been eliminated in the
consolidated financial statements. Certain reclassifications have been made to
prior year amounts to conform to the current year presentation.
Recently Issued Accounting Pronouncements
In 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method and the liability
should be accreted to its face amount. The Company adopted SFAS No. 143 on
January 1, 2003. The primary impact of this standard relates to oil and gas
wells on which the Company has a legal obligation to plug and abandon the wells.
Prior to SFAS No. 143, the Company had not recorded an obligation for these
plugging and abandonment costs due to its assumption that the salvage value of
the surface equipment would substantially offset the cost of dismantling the
facilities and carrying out the necessary clean up and reclamation activities.
The adoption of SFAS No. 143 on January 1, 2003, resulted in a net increase to
Property and Equipment and Asset Retirement Obligations of approximately $27.8
million and $25.6 million, respectively, as a result of the Company separately
accounting for salvage values and recording the estimated fair value of its
plugging and abandonment obligations on the balance sheet. The impact of
adopting SFAS No. 143 has been accounted for through a cumulative effect
adjustment that amounted to $2.2 million increase to net income recorded on
January 1, 2003. The increase in expense resulting from the accretion of the
asset retirement obligation and the depreciation of the additional capitalized
well costs is expected to be substantially offset by the decrease in
depreciation from the Company's consideration of the estimated salvage values in
the calculation.
The following table summarizes our activity related to asset retirement
obligations:
Asset Retirement Obligation liability at January 1, 2003 $25,636
Asset Retirement Obligation accretion expense 1,151
Plus: Additions for new assets 676
Less: Plugging costs and sold assets (855)
--------
Asset Retirement Obligation liability at December 31, 2003 $26,608
========
Pro forma asset retirement obligation at January 1, 2002, was $25.2
million.
The following table describes the pro forma effect on net income and
earnings per share for the years December 31, 2001 and 2002, as if SFAS No. 143
had been adopted in January 1 2001.
Year Ended Year Ended
December 31, 2001 December 31, 2002
---------------- -----------------
Net income (loss) - as reported $ 11,667 $ (20,032)
Less: Asset retirement obligation accretion expense (967) (1,023)
Less: Asset retirement cost depreciation expense (613) (665)
Plus: Reduction in depreciation expense on salvage
value 637 717
--------------- -----------------
Net income - pro forma $ 10,724 $ (21,003)
=============== =================
Earnings per share:
As reported
Basic $ 0.81 $ (1.39)
Diluted $ 0.81 $ (1.39)
Pro Forma
Basic $ 0.75 $ (1.46)
Diluted $ 0.75 $ (1.46)
Statement of Financial Accounting Standards No. 141, Business Combinations
(FAS 141), and Statement of Financial Accounting Standards No. 142, Goodwill and
Other Intangible Assets (FAS 142), were issued in June 2001 and became effective
for the Company on July 1, 2001 and January 1, 2002, respectively. The Company
understands the majority of the oil and gas industry did not change accounting
and disclosures for mineral interest use rights upon the implementation of FAS
141 and 142. However, an interpretation of FAS 141 and 142 is being considered
as to whether mineral interest use rights in oil and gas properties are
intangible assets. Under this interpretation, mineral interest use rights for
both undeveloped and developed leaseholds would be classified as intangible
assets, separate from oil and gas properties. This interpretation would not
affect our results of operations or cash flows however could result in the
reclassification of $33.8 million for 2002 and $33.4 million for 2003 from
property and equipment to other intangible assets.
In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others-an Interpretation of FASB
Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34. For
certain guarantees, FIN 45 requires recognition at the inception of a guarantee
of a liability for the fair value of the obligation assumed in issuing the
guarantee. FIN 45 also requires expanded disclosures for outstanding guarantees,
even if the likelihood of the guarantor having to make any payments under the
guarantee is considered remote. The recognition provisions of FIN 45 were
effective for guarantees issued or modified after December 31, 2002. The Company
has not issued or modified any material guarantees within the scope of FIN 45
during 2003; therefore, implementation of this new standard has not impacted its
consolidated financial condition or results of operations.
In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities - an Interpretation of ARB No. 51. This interpretation
clarifies the application of ARB 51, Consolidated Financial Statements to
certain entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. Because application of the majority voting interest
requirement in ARB 51 may not identify the party with a controlling financial
interest in situations where controlling financial interest is achieved through
arrangements not involving voting interests, this interpretation introduces the
concept of variable interests and requires consolidation by an enterprise having
variable interests in previously unconsolidated entity if the enterprise is
considered the primary beneficiary, meaning the enterprise will absorb a
majority of the variable interest entity's expected losses or residual returns.
For variable interest entities in existence as of February 1, 2003, FIN 46, as
originally issued, required consolidation by the primary beneficiary in the
third quarter of 2003. In October 2003, the FASB deferred the effective date of
FIN 46 to the fourth quarter. Continental has reviewed the effects of FIN 46
relative to its relationships with possible variable interest entities and has
determined that the adoption of such standard had no material impact on the
Company as it has no interests in any material variable interest entities.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested
in short-term investments with original maturities of three-months or less.
Accounts Receivable
The Company operates exclusively in the oil and natural gas exploration and
production, gas gathering and processing and gas marketing industries. Joint
interest and oil and gas sales receivables are generally unsecured. The
Company's joint interest receivables at December 31, 2002 and 2003 are recorded
net of an allowance for doubtful accounts of approximately $544,000 and
$230,000, respectively, in the accompanying consolidated balance sheets. The
allowance for uncollectable accounts is established on a case-by-case basis when
the Company believes the required payment of specific amounts owed is unlikely
to occur. The Company's provision for doubtful accounts was $24,503, $114,819
and $13,348 during 2001, 2002 and 2003 respectively.
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, 2002 and 2003, tubular goods and production equipment totaled
approximately $5,572,000 and $4,151,000, respectively and crude oil in tanks
totaled approximately $1,128,000 and $1,314,000, respectively.
Property and Equipment
The Company utilizes the successful efforts method of accounting for oil
and gas activities whereby costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. 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.
Depreciation, Depletion, Amortization and Impairment
Depreciation, depletion, and amortization (DD&A) of capitalized drilling
and development costs of producing oil and gas properties are generally computed
using the units of production method on an individual property or unit basis
based on total estimated proved developed oil and gas reserves. Amortization of
producing leasehold is based on the unit-of-production method using total
estimated proved reserves. In arriving at rates under the unit-of-production
method, the quantities of recoverable oil and natural gas are established based
on estimates made by the Company's geologist and engineers. Gas gathering
systems and gas processing plants are depreciated using the straight-line method
over an estimated useful life of 14 years. Service properties, equipment and
other assets are depreciated using the straight-line method over estimated
useful lives of 5 to 40 years. Upon sale or retirement of depreciable or
depletable property, the cost and related accumulated DD&A are eliminated from
the accounts and the resulting gain or loss is recognized.
As stated above, DD&A of capitalized drilling and development costs of
producing oil and gas properties are generally computed using the units of
production method on total estimated proved developed oil and gas reserves.
However, successful efforts accounting provides that in instances in which a
significant amount of development costs relate to both proved developed and
proved undeveloped reserves, a distortion in the DD&A rate would occur if such
developmental costs were amortized over only proved developed reserves. At
December 31, 2003, the Company has capitalized drilling and development costs of
approximately $168.6 million related to the high-pressure air injection project
currently in process in the Cedar Hills Field. Proved reserves associated with
this field are approximately 42.2 MMBoe of which 28.5 MMBoe, or 67% are proved
undeveloped. At December 31, 2003, the Company has excluded approximately $112.9
million, or 67% of the development costs from the amortization base for purposes
of computing DD&A. In future periods, the proved undeveloped reserves will be
transferred to proved developed as such reserves meet the definition of proved
reserves under SEC guideline. Costs associated with the Cedar Hills Field will
be added to the amortization base based on the ratio of proved developed
reserves to proved undeveloped reserves. The Company's future DD&A rate on this
field could be significantly impacted by upward or downward revisions in the oil
and gas reserve estimates associated with this field.
Non-producing properties consist of undeveloped leasehold costs and costs
associated with the purchase of certain proved undeveloped reserves.
Individually significant non-producing properties are periodically assessed for
impairment of value and a loss is recognized at the time of impairment by
providing an impairment allowance. Other non-producing properties are amortized
on a composite method based on the Company's estimated experience of successful
drilling and the average holding period. Impairment of non-producing properties
was $4.8 million, $23.4 million, and $5.2 million for 2001, 2002, and 2003.
Geological and geophysical costs, delay rentals and costs to drill exploratory
wells that do not find proved reserves are expensed. Repairs and maintenance are
charged to expense as incurred.
In accordance with the provisions of Financial Accounting Standards (SFAS)
No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the
Company recognizes impairment losses for developed oil and gas properties and
other long-lived assets when indicators of impairment are present and the
undiscounted cash flows from proved and risk adjusted probable reserves are not
sufficient to recover the assets' carrying amount. The impairment loss is
measured by comparing the fair value of the asset to its carrying amount. Fair
values are based on discounted future cash flows. The Company's oil and gas
properties were reviewed for indicators of impairment on a field-by-field basis,
resulting in the recognition of impairment provisions of $5.3 million, $2.3
million, and $3.8 million respectively, for 2001, 2002 and 2003. The majority of
the impairment recognized in these years relates to fields comprised of a small
number of properties or single wells on which the Company does not expect
sufficient future net cash flow to recover its carrying cost.
Income Taxes
Effective June 1, 1997, the Company converted to an S-Corporation under
Subchapter S of the Internal Revenue Code. As a result, income taxes
attributable to Federal taxable income of the Company after May 31, 1997, if
any, will be payable by the stockholders of the Company.
Earnings per Common Share
Basic earnings per common share is computed by dividing income available to
common stockholders by the weighted-average number of shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if dilutive stock options were exercised calculated using the treasury
stock method. The weighted-average number of shares used to compute basic
earnings per common share was 14,368,919 in 2001, 2002 and 2003. Using the
treasury stock method the weighted-average number of shares used to compute
diluted earnings per share for 2001 and 2003 was 14,393,132 and 14,463,210,
respectively. The outstanding stock options (see Note 6) were not considered in
the diluted earnings per share calculation for 2002, as the effect would be
antidilutive.
Accounting for Derivatives
The Company periodically utilizes derivative contracts to hedge the
commodity price risk associated with specifically identified purchase or sales
contracts, oil and gas production or operational needs. Effective January 1,
2001, the Company accounts for its non-trading derivative activities under the
guidance provided by SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. Under SFAS No. 133, the Company recognizes all of its
derivative instruments as assets or liabilities in the balance sheet at fair
value with such amounts classified as current or long-term based on their
anticipated settlement. The accounting for the changes in fair value of a
derivative depends on the intended use of the derivative and resulting
designation. For derivative instruments that are designated and qualify as a
fair value hedge, the gain or loss on the derivative instrument as well as the
offsetting loss or gain on the hedged item attributable to the hedged risk are
recognized in the same line item associated with the hedged item in current
earnings during the period of the change in fair values. For derivatives that
are designated and qualify as a cash flow hedge, the effective portion of the
change in fair value of the derivative instrument is reported as a component of
accumulated other comprehensive income and recognized into earnings in the same
period during which the hedged transaction affects earnings. The ineffective
portion of a derivative's change in fair value is recognized currently in
earnings. Hedge effectiveness is measured at least quarterly based on relative
changes in fair value between the derivative contract and hedged item during the
period of hedge designation. Forecasted transactions designated as the hedged
item in a cash flow hedge are regularly evaluated to assess whether they
continue to be probable of occurring. If the forecasted transaction is no longer
probable of occurring, hedge accounting will cease on a prospective basis and
all future changes in the fair value of the derivative will be reconciled
directly in earnings.
Crude Oil Marketing
The Company engages in a series of contracts in order to exchange its crude
oil production in the Rocky Mountain area for equal quantities of crude oil
located at Cushing, Oklahoma. Such activity is done to take advantage of better
pricing as well as to reduce the Company's credit risk associated with its first
purchaser. This purchase and sale activity is presented gross in the
accompanying income statement as crude oil marketing revenues and expenses under
the guidance provided by EITF 99-19, Reporting Revenues Gross as a Principal and
or Net as an Agent.
Additionally, prior to May 2002, the Company engaged in certain crude oil
trading activities, exclusive of its own production, utilizing fixed price and
variable priced physical delivery contracts. Effective May 2002, the Company
ceased all crude oil trading activity. For the years ended December 31, 2001 and
2002, crude oil marketing revenues included $85.8 million and $98.4 million,
respectively, and crude oil marketing expenses included $85.1 million and $97.8
million, respectively, related to the Company's crude oil trading activities.
Oil and Gas Sales and Gas Balancing Arrangements
The Company sells oil and natural gas to various customers, recognizing
revenues as oil and gas is produced and sold. The Company uses the sales method
of accounting for gas imbalances in those circumstances were it has under
produced or overproduced its ownership percentage in a property. Under this
method, a receivable or liability is recognized only to the extent that an
imbalance cannot be recouped from the reserves in the underlying properties. The
Company's aggregate imbalance positions at December 31, 2002 and 2003 were not
material. Charges for gathering and transportation are included in production
expenses.
Fair Value of Financial Instruments
The Company's financial instruments consist primarily of cash, trade
receivables, trade payables and bank debt. The carrying value of cash, trade
receivables and trade payables are considered to be representative of their
respective fair values, due to the short maturity of these instruments. The fair
value of long-term debt, less the senior subordinated notes discussed in Note 4,
approximates its carrying value based on the borrowing rates currently available
to the Company for bank loans with similar terms and maturities.
The fair value of the Company's senior subordinated notes at December 31,
2002 and 2003 was $117.0 million and $128.4 million, respectively.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Of the estimates and assumptions that affect reported results, the estimate of
the Company's oil and natural gas reserves, which is used to compute
depreciation, depletion, amortization and impairment on producing oil and gas
properties, is the most significant.
Stock Based Compensation
Pursuant to the provisions of SFAS No. 123, Accounting for Stock Based
Compensation, the Company has elected to continue using the intrinsic value
method of accounting for its stock based compensation in accordance with APB
Opinion No. 25. Under APB 25, no compensation expense is recognized relating to
stock options issued under a fixed price plan with a strike price at or above
the fair market value of the underlying shares of common stock at the date of
grant. For stock options issued with a strike price below the fair market value
of the underlying shares of common stock in-the-money, compensation expense is
recognized over the vesting period equal to the fair market value of the common
stock at the date of grant less the strike price. During 2001, 2002 and 2003,
compensation expenses related to in-the-money options were immaterial.
Had the Company determined compensation expense based on the fair value at
the grant date for its stock options under SFAS No. 123, the Company's net
income (loss) would have been adjusted as indicated below.
(Dollars in thousands except per share amounts) 2001 2002 2003
--------- ---------- ---------
Net Income (Loss):
As Reported $ 11,667 $ (20,032) $ 2,340
Pro Forma $ 11,575 $ (20,117) $ 2,259
Basic Earnings Per Share:
As Reported $ 0.81 $ (1.39) $ 0.16
Pro Forma $ 0.81 $ (1.40) $ 0.15
Diluted Earnings Per Share:
As Reported $ 0.81 $ (1.39) $ 0.16
Pro Forma $ 0.81 $ (1.40) $ 0.16
2. HEDGING CONTRACTS:
The Company utilizes fixed-price contracts and zero-cost collars to reduce
exposure to the unfavorable changes in oil and gas prices that are subject to
significant and often volatile fluctuation. Under the fixed price physical
delivery contracts the Company receives the fixed price stated in the contract.
Under the zero-cost collars, if the market price of crude oil exceeds the
ceiling strike price or falls below the floor strike price, then the Company
receives the fixed price. If the market price is between the floor strike price
and the ceiling strike price, the Company receives market price.
These contracts allow the Company to predict with greater certainty the
effective oil and gas prices to be received for hedged production and benefit
operating cash flows and earnings when market prices are less than the fixed
prices provided in the contracts. However, the Company will not benefit from
market prices that are higher than the fixed prices in the contracts for hedged
production.
The terms of the Company's revolving credit agreement require it to have at
least 50% of its forecasted crude oil production from its exploration and
production segment hedged on a rolling six-month term. At December 31, 2003, the
Company has costless collars in place covering approximately 1.1 million barrels
of crude oil representing approximately 63% of the Company's forecasted
production through June 30, 2004. At December 31, 2003, the Company has a
mark-to-market unrealized loss of approximately $489,000 on its zero-cost collar
contracts. As such contracts have been designated and qualify as cash flow
hedges, the loss has been recorded as a component of Accumulated Other
Comprehensive Income at December 31, 2003. The ineffectiveness associated with
the Company's cash flow hedging strategy was immaterial.
Additionally, CGI has executed fixed price forward sales contracts related
to the Company's gas gathering, marketing and processing segment on
approximately 50,000 MMBtu per month through December 2007. Such contracts have
been designated as normal sales under SFAS No. 133 and are therefore not marked
to market as derivatives. These volumes under these fixed price forward sales
contracts represent approximately 9% of total delivery point volumes and 4% of
the overall throughput volumes of the gas gathering, marketing and processing
segment.
The following table summarizes the Company's hedging contracts in place at
December 31, 2003:
2004 2005 2006 2007
---------- ---------- ---------- ----------
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 600,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Collars:
Contract Volumes (Bbls)
Floor 1,115,000 - - -
Ceiling 1,115,000 - - -
Weighted-average Fixed Price per Bbl
Floor $ 22.00 $ - $ - $ -
Ceiling $ 35.24 $ - $ - $ -
3. ACQUISITIONS:
On July 9, 2001, the Company's subsidiary, CRII, purchased the assets of
Farrar Oil Company, Inc. and Har-Ken Oil Company (collectively "Farrar") for
$33.7 million using funds borrowed under the Company's credit facility. This
purchase was accounted for as a purchase and the cost of the acquisition was
allocated to the acquired assets and liabilities. The allocation of the $33.7
million purchase price on July 9, 2001, was as follows:
Current assets $ 950
Producing properties 30,603
Non-producing properties 1,117
Service properties 1,000
-------
$33,670
The unaudited pro forma information set forth below includes the operations
of Farrar assuming the acquisition of Farrar by CRII occurred at the beginning
of the period presented. The unaudited pro forma information is presented for
information only and is not necessarily indicative of the results of operations
that actually would have achieved had the acquisition been consummated at that
time:
Pro Forma (Unaudited)
For the twelve months ended December 31, 2001
($ In thousands except share data) Farrar CRI Consolidated
- ---------------------------------- ------------------------------------------------
Revenue $18,219 $404,062 $422,281
Net Income $7,700 $10,954 $18,654
Earnings Per Common Share
Basic $0.54 $0.76 $1.30
Diluted $0.54 $0.76 $1.30
On August 1, 2003, Continental Gas, Inc. (CGI), a wholly owned subsidiary
of CRI, acquired the Carmen Gathering System located in western Oklahoma for
$15.0 million. After various adjustments and other reductions in the purchase
and sale agreement, the net cost to CGI was $12.0 million. Funding for the
acquisition was obtained from borrowings under our revolving credit facility as
discussed in Note 4.
4. LONG-TERM DEBT:
Long-term debt consists of the following:
December 31, December 31,
(Dollars in thousands) 2002 2003
------------ ------------
10.25% Senior Subordinated Notes due Aug. 2008 (a) $ 127,150 $ 127,150
Credit Facility due March 28, 2005 (b) 108,000 132,900
Credit Facility due September 30, 2006 (c) - 17,000
Capital Lease Agreement (d) 11,955 13,827
Ford Credit (e) - 43
---------- ----------
Outstanding Debt 247,105 290,920
Less Current Portion 2,400 5,776
---------- ----------
Total Long-Term Debt $ 244,705 $ 285,144
========== ==========
(a) On July 24, 1998, the Company consummated a private placement of $150.0
million of 10 1/4% Senior Subordinated Notes ("the Notes") due August 1,
2008, in a private placement under Securities Act Rule 144A. Interest on
the Notes is payable semi-annually on each February 1 and August 1. In
connection with the issuance of the Notes, the Company incurred debt
issuance costs of approximately $4.7 million, which have been capitalized
as other assets and are being amortized on a straight-line basis over the
life of the Notes. Effective November 14, 1998, the Company registered the
Notes through a Form S-4 Registration Statement under the Securities
Exchange Act of 1933. During 2000, the Company repurchased $19.9 million
principal amount of its Notes at a cost of $18.3 million and during 2001,
the Company repurchased $3.0 million principal amount of its Notes at a
cost of $2.7 million.
(b) On March 31, 2002, the Company executed a Fourth Amended and Restated
Credit Agreement in which a group of lenders agreed to provide a $175.0
million senior secured revolving credit facility with a current borrowing
base of $140.0 million. Borrowings under the credit facility are secured by
liens on all oil and gas properties and associated assets of the Company.
Borrowings under the credit facility bear interest, payable quarterly, at
(a) a rate per annum equal to the rate at which eurodollar deposits for
one, two, three or six months are offered by the lead bank plus a margin
ranging from 150 to 250 basis points, or (b) at the lead bank's reference
rate plus an applicable margin ranging from 25 to 50 basis points. The
Company paid approximately $2.2 million in debt issuance fees for the new
credit facility, which have been capitalized as other assets and are being
amortized on a straight-line basis over the life of the credit facility.
The credit facility matures on March 28, 2005. On October 22, 2003, the
Company executed the Second Amendment to the Credit Agreement and deleted
CGI as a guarantor of the Company's obligations under the Credit Agreement.
The borrowing base under the Second Amendment to the Credit Agreement was
revised to $145.0 million and the outstanding balance was reduced by $17.0
million funded by CGI as disclosed in (c) below. The lead bank's reference
rate plus margins at December 31, 2003, was 3.75%. The Company's line of
credit agreement contains certain negative financial and certain
information reporting covenants. As of March 26, 2004, the Company has
drawn an additional $7.5 million on its line of credit and currently has
$140.4 million of outstanding debt on its line of credit.
(c) On October 22, 2003, CGI, a wholly owned subsidiary of the Company, closed
a new $35.0 million secured credit facility consisting of a senior secured
term loan facility of up to $25.0 million, and a senior revolving credit
facility of up to $10.0 million. The initial advance under the term loan
facility was $17.0 million, which was paid to CRI to reduce the outstanding
balance on its credit facility. No funds were initially advanced under the
revolving loan facility. Advances under either facility can be made, at the
borrower's election, as reference rate loans or LIBOR loans and, with the
respect to LIBOR loans, for interest periods of one, two, three, or six
months. Interest is payable on reference rate loans monthly and on LIBOR
loans at the end of the applicable interest period. The principal amount of
the term loan facility is to be amortized on a quarterly basis through June
30, 2006, with the final payment due on September 30, 2006. The amount
available under the revolving loan facility may be borrowed, repaid and
reborrowed until maturity on September 30, 2006. Interest on reference rate
loans is calculated with reference to a rate equal to the higher of the
reference rate of Union Bank of California, N.A. or the federal funds rate
plus 0.5%. Interest on LIBOR loans is calculated with reference to the
London interbank offered interest rate. Interest accrues at the reference
rate or the LIBOR rate, as applicable, plus the applicable margins. The
margin is based on the then current senior debt to EBITDA ratio. The credit
agreement contains certain covenants and requires certain quarterly
mandatory prepayments on the term loan of 75% of excess cash flow. The
credit facility is secured by a pledge of all the assets of CGI.
(d) On December 9, 2002, December 12, 2002 and August 20, 2003, the Company
entered into a long-term lease arrangement with a related party for $2.1
million, $9.9 million, and $4.3 million, respectively. We believe these
lease arrangements were entered into at rates equal to, or better than what
could have been negotiated with a third party.
(e) In 2003, CRII, a wholly owned subsidiary of the Company, entered into an
agreement with Ford Credit to purchase company vehicles and take advantage
of low interest rates.
The annual maturities of long-term debt subsequent to December 31, 2003,
are as follows (in thousands):
2004 $ 5,776
2005 138,676
2006 15,491
2007 3,341
2008 127,636
---- --------
Total maturities $290,920
========
At December 31, 2003, the Company had $1.1 million of outstanding letters
of credit that expire during 2004.
The estimated fair value of long-term debt is approximately $292,192,000
and $236,933,000 at December 31, 2003 and 2002, respectively. The fair value of
long-term debt is estimated based on quoted market prices and management's
estimate of current rates available for similar issues.
5. STOCKHOLDERS' EQUITY:
On October 1, 2000, the Company's Board of Directors and shareholders
approved an Agreement and Plan of Recapitalization (the "Recapitalization Plan")
and the Amended and Restated Certificate of Incorporation to be filed with the
Oklahoma Secretary of State. As outlined in the Recapitalization Plan, the
authorized number of shares of capital stock was increased from 75,000 shares of
common stock to 21 million shares consisting of 20 million shares of common
stock and one million shares of $0.01 par value Preferred Stock. In addition,
the par value of common stock was adjusted from $1 per share to $0.01 per share
and 1.02 million shares of the common stock were reserved for issuance under the
2000 incentive Stock Option Plan discussed in Note 6.
Concurrent with the approval of the Recapitalization Plan, the Company
affected an approximate 293: 1 stock split whereby the Company issued new
certificates for 14,368,919 shares of the newly authorized common stock in
exchange for the 49,041 previously outstanding shares of common stock. As a
result of the stock split, additional paid-in capital was reduced by
approximately $95,000, offset by an increase in the common stock at par.
6. STOCK OPTIONS:
Effective October 1, 2000, the Company adopted the Continental Resources,
Inc. 2000 Stock Option Plan (the "Plan").
Under the Plan, the Company may, from time to time, grant options to
directors and eligible employees. These options may be Incentive Stock Options
or Nonqualified Stock Options, or a combination of both. The earliest the
granted options may be exercised is over a five year vesting period at the rate
of 20% each year for the Incentive Stock Options and over a three year period at
the rate of 33 1/3% for the Nonqualified Stock Options, both commencing on the
first anniversary of the grant date. The maximum shares covered by options shall
consist of 1,020,000 shares of the Company's common stock, par value $.01 per
share. The Company granted 144,000 shares during 2000. No options were granted
in 2001, 28,000 shares were granted during 2002, and no additional shares were
granted in 2003. No shares have been exercised or canceled as of December 31,
2003.
Stock options outstanding under the Plan are presented for the periods
indicated.
Number of Shares Option Price Range
- ----------------------------------- ---------------- -------------------
Outstanding December 31, 2000 144,000 $ 7.00 - $ 14.00
Granted - - -
Exercised - - -
Canceled - - -
---------------- -------------------
Outstanding December 31, 2001 144,000 $ 7.00 - $ 14.00
Granted 28,000 $ 7.77 - $ 14.00
Exercised - - -
Canceled - - -
---------------- -------------------
Outstanding December 31, 2002 172,000 $ 7.00 - $ 14.00
Granted - - -
Exercised - - -
Canceled - - -
---------------- -------------------
Outstanding December 31, 2003 172,000 $ 7.00 - $ 14.00
The weighted average exercise price of the options outstanding at December 31,
2003, was $11.15.
7. COMMITMENTS AND CONTINGENCIES:
The Company maintains a defined contribution retirement plan for its
employees under which it makes discretionary contributions to the plan based on
a percentage of eligible employees compensation. During 2001, 2002 and 2003,
contributions to the plan were 5% of eligible employees' compensation. Expense
for the years ended December 31, 2001, 2002 and 2003, was approximately
$392,000, $353,590 and $404,391, 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 $150,000 and $500,000, respectively,
per claim. Any amounts paid above these are reinsured through third-party
providers. Premiums charged to the Company are based on estimated costs per
employee of the Pool. No additional premium assessments are anticipated for
periods prior to December 31, 2003. 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 of the Company.
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 environmental issues or
claims.
8. RELATED PARTY TRANSACTIONS:
The Company, acting as operator on certain properties, utilizes
unconsolidated affiliated companies to provide oilfield services such as
drilling and trucking. The total amount paid to these companies, a portion of
which was billed to other interest owners, was approximately $10,942,000,
$11,679,000 and $13,608,000 during the years ended December 31, 2001, 2002 and
2003, respectively. These services were provided at amounts which management
believes approximate the costs that would have been paid to an unrelated party
for the same services. At December 31, 2002 and 2003, the Company owed
approximately $919,000 and $2,280,000, respectively, to these companies, which
is included in accounts payable and accrued liabilities in the accompanying
consolidated balance sheets. These companies and other companies, owned by the
Company's principal stockholder, also own interests in wells operated by the
Company and provide oilfield related services to the Company. At December 31,
2002 and 2003, approximately $481,000 and $330,000, respectively, from
affiliated companies is included in accounts receivable in the accompanying
consolidated balance sheets.
The Company leases office space under operating leases directly or
indirectly from the principal stockholder. Rents paid associated with these
leases totaled approximately $334,000, $421,000 and $505,000 for the years ended
December 31, 2001, 2002 and 2003, respectively. See Note 4 for discussion of
related party capital lease transaction.
During 2001, the Company, acting as operator on certain properties began
selling natural gas to a related party. The Company sold $1.77 million of
natural gas to this related party in 2001, $1.24 million of natural gas to this
related party in 2002 and $1.0 million of natural gas in 2003 to this related
party.
9. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, Continental Gas, Inc. ("CGI"),
Continental Resources of Illinois, Inc. ("CRII"), and Continental Crude Co.
("CCC") have guaranteed the Company's outstanding Senior Subordinated Notes and
its bank credit facility. The following is a summary of the condensed
consolidating financial information of CGI and CRII as of December 31, 2002 and
2003:
As of December 31, 2002 Condensed Consolidating Balance Sheet
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
------------------------------------------------------
Current Assets $ 6,524 $ 49,276 $ (22,862) $ 32,938
Property and Equipment 42,664 325,239 0 367,903
Other Assets 7 5,843 (14) 5,836
-------------------------------------------------------
Total Assets $ 49,195 $ 380,358 $ (22,876) $ 406,677
Current Liabilities $ 11,443 $ 42,257 $ (6,934) $ 46,766
Long-Term Debt 15,928 244,705 (15,928) 244,705
Other Liabilities 0 125 0 125
Stockholders' Equity 21,824 93,271 (14) 115,081
-------------------------------------------------------
Total Liabilities and
Stockholders' Equity $ 49,195 $ 380,358 $ (22,876) $ 406,677
As of December 31, 2003 Condensed Consolidating Balance Sheet
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Current Assets $ 11,162 $ 44,428 $ (14,749) $ 40,841
Property and Equipment 58,826 380,606 0 439,432
Other Assets 281 4,448 (14) 4,715
-------------------------------------------------------
Total Assets $ 70,269 $ 429,482 $ (14,763) $ 484,988
Current Liabilities $ 18,512 $ 44,694 $ (7,066) $ 56,140
Long-Term Debt 22,286 270,541 (7,683) 285,144
Other Liabilities 4,943 21,829 0 26,772
Stockholders' Equity 24,528 92,418 (14) 116,932
-------------------------------------------------------
Total Liabilities and
Stockholders' Equity $ 70,269 $ 429,482 $ (14,763) $ 484,988
As of December 31, 2001 Condensed Consolidating Statements of Operations
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Total Revenue $ 52,051 $ 357,589 $ (563) $ 409,077
Operating Expenses (46,695) (339,783) 563 (385,915)
Other Income (Expense) (95) (11,400) 0 (11,495)
-------------------------------------------------------
Net Income $ 5,261 $ 6,406 $ 0 $ 11,667
As of December 31, 2002 Condensed Consolidating Statements of Operations
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Total Revenue $ 48,248 $ 253,624 $ (1,581) $ 300,291
Operating Expenses (44,575) (260,089) (1,581) (303,083)
Other Income (Expense) (1,632) (15,608) 0 (17,240)
-------------------------------------------------------
Net Income (Loss) $ 2,041 $ (22,073) $ 0 $ (20,032)
As of December 31, 2003 Condensed Consolidating Statements of Operations
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Total Revenue $ 89,422 $ 304,204 $ (1,559) $ 392,067
Operating Expenses (85,053) (288,998) 1,559 (372,492)
Other Income (Expense) (1,616) (17,781) 0 (19,397)
Cumulative Effect of Change
in Accounting Principle (50) 2,212 0 2,162
-------------------------------------------------------
Net Income (Loss) $ 2,703 $ (363) $ 0 $ 2,340
As of December 31, 2001 Condensed Consolidated Cash Flow Statements
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Cash Flow from Operating
Activities $ 8,499 $ 80,843 $ (25,929) $ 63,413
Cash Flow from Investing
Activities (27,787) (78,597) - (106,384)
Cash Flow from Financing
Activities 19,895 23,150 - 43,045
---------------------------------------------------
Net Increase (Decrease) in
Cash 607 25,396 (25,929) 74
Cash and Cash Equivalents
at Beginning of Period 101 7,050 - 7,151
---------------------------------------------------
Cash and Cash Equivalents
at End of Period $ 708 $ 32,446 $ (25,929) $ 7,225
As of December 31, 2002 Condensed Consolidated Cash Flow Statements
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Cash Flow from Operating $ 9,290 $ 60,323 $ (22,616) $ 46,997
Activities
Cash Flow from Investing (6,369) (106,926) - (113,295)
Activities
Cash Flow from Financing (3,173) 64,766 - 61,593
Activities ---------------------------------------------------
Net Increase (Decrease) in
Cash (252) 18,163 (22,616) (4,705)
Cash and Cash Equivalents
at Beginning of Period 707 6,518 - 7,225
---------------------------------------------------
Cash and Cash Equivalents
at End of Period $ 455 $ 24,681 $ (22,616) $ 2,520
As of December 31, 2003 Condensed Consolidated Cash Flow Statements
- -------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
-------------------------------------------------------
Cash Flow from Operating $ 9,555 $ 70,328 $ (14,637) $ 65,246
Activities
Cash Flow from Investing (18,182) (90,609) - (108,791)
Activities
Cash Flow from Financing 8,873 34,429 - 43,302
Activities ---------------------------------------------------
Net Increase (Decrease) in
Cash 246 14,148 (14,637) (243)
Cash and Cash Equivalents
at Beginning of Period 456 2,064 - 2,520
---------------------------------------------------
Cash and Cash Equivalents
at End of Period $ 702 $ 16,212 $ (14,637) $ 2,277
At December 31, 2002 and 2003, current liabilities payable from the
subsidiaries to CRI totaled approximately $22.6 million and $14.6 million,
respectively. For the years ended December 31, 2002 and 2003, depreciation,
depletion and amortization, included in operating costs, totaled approximately
$5.6 million and $6.5 million, respectively. Since its incorporation, CCC has
had no operations, has acquired no assets and has incurred no liabilities.
10. BUSINESS SEGMENTS:
The Company has two reportable segments pursuant to Statement of Financial
Accounting Standards (SFAS) No. 131, Disclosure About Segments of an Enterprise
and Related Information, consisting of exploration and production, and gas
gathering, marketing and processing. The Company's reportable business segments
have been identified based on the differences in products or services provided.
Revenues from the exploration and production segment are derived from the
production and sale of crude oil and natural gas. Revenues from the gas
gathering, marketing and processing segment come from the transportation and
sale of natural gas and natural gas liquids at retail. The accounting policies
of the segments are the same as those described in the summary of significant
accounting policies. Financial information by operating segment is presented
below:
Exploration Gas Gathering,
and Marketing and
2001 Production Processing Intersegment Total
- ---------------------------------------- -------------- ------------- ------------- --------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 111,620 $ 550 $ - $ 112,170
Crude oil marketing 245,872 - - 245,872
Change in derivative fair value - - - -
Gas gathering, marketing and processing - 45,619 (631) 44,988
Service operations 6,047 - - 6,047
-------------- ------------- ------------- --------------
Total revenues $ 363,539 $ 46,169 $ (631) $ 409,077
OPERATING COSTS AND EXPENSES:
Production expenses and taxes 36,627 164 - 36,791
Exploration 15,832 31 - 15,863
Crude oil marketing 245,003 - - 245,003
Gas gathering, marketing and processing - 36,998 (631) 36,367
Service operations 5,294 - - 5,294
Depreciation, depletion and
amortization 25,588 2,143 - 27,731
Property Impairments 10,113 - - 10,113
General and administrative 8,061 692 - 8,753
- ---------------------------------------- -------------- ------------- ------------- -------------
Total operating costs and expenses $ 346,518 $ 40,028 $ (631) $ 385,915
Operating income $ 17,021 $ 6,141 $ - $ 23,162
Interest income 1,604 29 (1,003) 630
Interest expense (16,327) (350) 1,003 (15,674)
Other income (expense), net 3,467 82 - 3,549
- ---------------------------------------- -------------- ------------- ------------- --------------
Total other income (expense) $ (11,256) $ (239) $ - $ (11,495)
Income from operations $ 5,765 $ 5,902 $ - 11,667
- ---------------------------------------- -------------- ------------- ------------- --------------
Net income $ 5,765 $ 5,902 $ - 11,667
======================================== ============== ============= ============= ==============
Capital expenditures $ 104,378 6,645 $ - $ 111,023
Exploration Gas Gathering,
and Marketing and
2002 Production Processing Intersegment Total
- ---------------------------------------- -------------- -------------- ------------- --------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 108,194 $ 559 $ - $ 108,753
Crude oil marketing 153,547 - - 153,547
Change in derivative fair value (1,455) - - (1,455)
Gas gathering, marketing and processing - 35,288 (1,581) 33,708
Service operations 5,739 - - 5,739
-------------- ------------- ------------- --------------
Total revenues $ 266,024 $ 35,847 $ (1,581) $ 300,291
OPERATING COSTS AND EXPENSE:
Production expenses and taxes 35,946 166 - 36,112
Exploration 10,141 89 - 10,229
Crude oil marketing 152,718 - - 152,718
Gas gathering, marketing and processing - 31,364 (1,581) 29,783
Service operations 6,462 - - 6,462
Depreciation, depletion and
amortization 28,870 2,510 - 31,380
Property Impairments 25,686 - - 25,686
General and administrative 9,607 1,106 - 10,713
- ---------------------------------------- -------------- ------------- ------------- --------------
Total operating costs and expenses $ 269,430 $ 35,234 $ (1,581) $ 303,084
Operating income (loss) $ (3,406) $ 613 $ - $ (2,792)
Interest income 1,934 10 (1,659) 285
Interest expense (19,875) (185) 1,659 (18,401)
Other income (expense), net 859 17 - 876
- ---------------------------------------- -------------- ------------- ------------- --------------
Total other income (expense) $ (17,082) $ (158) $ - $ (17,240)
Income (loss) from operations $ (20,487) 455 - (20,032)
- ---------------------------------------- -------------- ------------- ------------- --------------
Net income (loss) $ (20,487) $ 455 $ - $ (20,032)
======================================== ============== ============= ============= ==============
Total assets $ 401,492 $ 28,061 $ (22,876) $ 406,677
Capital expenditures $ 107,187 $ 6,260 - $ 113,447
Exploration Gas Gathering,
and Marketing and
2003 Production Processing Intersegment Total
- ---------------------------------------- -------------- -------------- ------------- --------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 138,344 $ 604 $ - $ 138,948
Crude oil marketing 168,092 - - 168,092
Change in derivative fair value 1,455 - - 1,455
Gas gathering, marketing and processing - 76,018 (1,559) 74,459
Service operations 9,114 - - 9,114
-------------- ------------- ------------- --------------
Total revenues $ 317,005 $ 76,622 $ (1,559) $ 392,068
OPERATING COSTS AND EXPENSES:
Production expenses and taxes 47,568 287 - 47,855
Exploration 17,149 72 - 17,221
Crude oil marketing expense 166,731 - - 166,731
Gas gathering, marketing and processing - 70,528 (1,559) 68,969
Service operations 8,046 - - 8,046
Depreciation, depletion and
amortization 38,983 3,384 - 42,367
Property Impairments 8,975 - - 8,975
Asset retirement obligation 1,137 14 - 1,151
General and administrative 10,416 762 - 11,178
- ---------------------------------------- -------------- ------------- ------------- --------------
Total operating costs and expenses $ 299,005 $ 75,047 $ (1,559) $ 372,493
Operating income $ 18,000 $ 1,575 $ - $ 19,575
Interest income 1,612 7 (1,511) 108
Interest expense (21,272) (497) 1,511 (20,258)
Other income (expense), net 783 (30) - 753
- ---------------------------------------- -------------- ------------- ------------- --------------
Total other income (expense) $ (18,877) $ (520) $ - $ (19,397)
Income (loss) from operations $ (877) $ 1,055 $ - $ 178
- ---------------------------------------- -------------- ------------- ------------- --------------
Income (loss) from cumulative effect of
change in accounting principle 273 1,889 - 2,162
- ---------------------------------------- -------------- ------------- ------------- --------------
Net income (loss) $ (604) $ 2,944 $ - $ 2,340
======================================== ============== ============= ============= ==============
Total assets $ 450,361 $ 49,390 $ (14,763) $ 484,988
Capital expenditures $ 96,060 $ 18,085 $ - $ 114,145
The exploration and production segment's total revenues derived from sales
to a single customer during 2001, 2002 and 2003, were approximately 17.8%, 42.4%
and 79.4%, respectively. The gas gathering, marketing and processing segment's
total revenues derived from sales to a single customer were 40%, 31% and 32% for
2001, 2002 and 2003, respectively.
11. OIL AND GAS PROPERTY INFORMATION
Costs Incurred in Oil and Gas Activities
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities for the three years ended December 31,
2001, 2002 and 3003 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.
Property acquisition costs: 2001 2002 2003
------------------- ---------------- ---------------
Proved $ 36,535 $ 655 $ 180
Unproved 11,386 10,504 8,503
------------------- ---------------- ---------------
Total property acquisition costs $ 47,921 $ 11,159 $ 8,683
Exploration costs $ 9,170 $ 11,809 $ 11,858
Development costs 47,567 84,219 74,843
Asset retirement costs (1) - - 676
------------------- ---------------- ---------------
Total $ 104,658 $ 107,187 $ 96,060
Excludes $15,528 of cumulative asset retirement cost recorded to adopt the
provisions of SFAS No. 143 on January 1, 2003.
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):
2002 2003
------------------ ------------------
Proved oil and gas properties $ 505,444 $ 584,661
Unproved oil and gas properties 16,769 16,664
------------------ ------------------
Total $ 522,213 $ 601,325
Less-Accumulated DD&A (182,863) (203,213)
------------------ ------------------
Net capitalized costs $ 339,350 $ 398,112
================== ==================
12. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
Proved Oil and Gas Reserves
The following reserve information was developed from reserve reports as of
December 31, 2000, 2001, 2002 and 2003, prepared by independent reserve
engineers and by the Company's internal reserve engineers and sets forth the
changes in estimated quantities of proved oil and gas reserves of the Company
during each of the three years presented.
Crude Oil and
Natural Gas (MMcf) Condensate (MBbls)
---------------------- ------------------------
Proved reserves as of December 31, 2000 59,873 35,264
Revisions of previous estimates (11,766) (2,378)
Extensions, discoveries and other additions 9,319 27,276
Production (8,411) (3,489)
Sale of minerals in place (2,457) (274)
Purchase of minerals in place 5,709 3,332
---------------------- ------------------------
Proved reserves as of December 31, 2001 52,267 59,731
Revisions of previous estimates 21,854 6,195
Extensions, discoveries and other additions 4,948 1,173
Production (9,229) (3,810)
Sale of minerals in place - (12)
Purchase of minerals in place 107 4
---------------------- ------------------------
Proved reserves as of December 31, 2002 69,947 63,281
Revisions of previous estimates (2,634) 647
Extensions, discoveries and other additions 12,567 12,853
Production (10,751) (3,463)
Sale of minerals in place (2,033) (318)
Purchase of minerals in place - -
---------------------- ------------------------
Proved reserves as of December 31, 2003 67,096 73,000
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, 2001, 2002 and 2003, were not material and have not been included
in the reserve estimates.
Proved Developed Oil and Gas Reserves
The following reserve information was developed by the Company and its
independent engineers and sets forth the estimated quantities of proved
developed oil and gas reserves of the Company as of the beginning of each year.
Crude Oil and
Proved Developed Reserves Natural Gas (MMcf) Condensate (MBbls)
- --------------------------- ------------------ ------------------
January 1, 2001 58,438 33,173
January 1, 2002 56,647 31,325
January 1, 2003 69,273 33,626
January 1, 2004 63,327 36,106
Proved developed reserves are proved reserves expected to be recovered
through existing wells with existing equipment and operating methods.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 2001, 2002 and 2003, as required by SFAS No. 69. The Standard
requires the use of a 10% discount rate. This information is not the fair market
value nor does it represent the expected present value of future cash flows of
the Company's proved oil and gas reserves (in thousands of dollars).
2001 2002 2003
---------------- --------------- ---------------
Future cash inflows $ 1,300,078 $ 2,131,097 $ 2,666,290
Future production, development and abandonment costs (667,533) (827,238) (1,092,623)
Future income tax expenses - - -
---------------- --------------- ---------------
Future net cash flows 632,545 1,303,859 1,573,667
10% annual discount for estimated timing of cash flows (323,941) (670,462) (761,247)
---------------- --------------- ---------------
Standardized measure of discounted future net cash flows $ 308,604 $ 633,397 $ 812,420
================ =============== ===============
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 $18.67, $29.04, and $30.49 per barrel at
December 31, 2001, 2002 and 2003, respectively. The year-end weighted average
gas price utilized in the computation of future cash inflows was approximately
$1.96, $3.33, and $4.64 per Mcf at December 31, 2001, 2002 and 2003,
respectively. Such prices do not include the effect of the Company's fixed price
contracts designated as hedges. Future cash flows are reduced by estimated
future costs to develop and to produce the proved reserves, as well as certain
abandonment costs based on year-end cost estimates assuming continuation of
existing economic conditions.
Income taxes were not computed at December 31, 2001, 2002 or 2003, 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):
2001 2002 2003
------------ ------------ -------------
Standardized measure of discounted future
net cash flows at the beginning of the year $ 491,799 $ 308,604 $ 633,397
Extensions, discoveries and improved recovery, less
related costs 98,719 21,082 142,663
Revisions of precious quantity estimates (33,338) 87,325 1,998
Changes in estimated future development and abandonment costs (107,009) 6,748 (43,900)
Purchase (sales) of minerals in place 10,755 161 (4,823)
Net changes in prices and production costs (136,665) 233,518 54,132
Accretion of discount 49,180 30,860 63,340
Sales of oil and gas produced, net of production costs (75,379) (73,755) (91,677)
Development costs incurred during the period 12,260 52,834 46,290
Change in timing of estimated future production, and other (1,718) (33,980) 11,000
------------ ------------ --------------
Net Change (183,195) 324,793 179,023
Standardized measure of discounted future
net cash flows at the end of the year $ 308,604 $ 633,397 $ 812,420
============ ============ ==============
EXHIBIT INDEX
EXHIBIT
NO. DESCRIPTION METHOD OF FILING
--- ----------- ----------------
2.1 Agreement and Plan of Recapitalization Incorporated herein by reference
of Continental Resources, Inc. dated
October 1, 2000
3.1 Amended and Restated Certificate of Incorporated herein by reference
Incorporation of Continental
Resources, Inc.
3.2 Amended and Restated Bylaws of Incorporated herein by reference
Continental Resources, Inc.
3.3 Certificate of Incorporation of Incorporated herein by reference
Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference
amended and restated
3.5 Certificate of Incorporation of Incorporated herein by reference
Continental Crude Co.
3.6 Bylaws of Continental Crude Co. Incorporated herein by reference
4.1 Restated Credit Agreement dated April Incorporated herein by reference
21, 2000, among Continental Resources,
Inc. and Continental Gas Inc., as
Borrowers and MidFirst Bank as Agent
(the 'Credit Agreement')
4.1.1 Form of Consolidated Revolving Note Incorporated herein by reference
under the Credit Agreement
4.1.2 Second Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois,
Inc., as Borrowers, and MidFirst Bank,
dated July 9, 2001
4.1.3 Third Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois,
Inc., as Borrowers, and MidFirst Bank,
dated January 17, 2002
4.1.4 Fourth Amended and Restated Credit Incorporated herein by reference
Agreement dated March 28, 2002, among
the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB
and Fortis Capital Corp.
4.1.5 First Amendment to the Revolving Incorporated herein by reference
Credit Agreement dated June 12, 2003,
among the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB
and Fortis Capital Corp.
4.1.6 Second Amendment to the Revolving Incorporated herein by reference
Credit Agreement dated October 22,
2003, among the Registrant, Union Bank
of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp.
4.2 Indenture dated as of July 24, 1998, Incorporated herein by reference
between Continental Resources, Inc. as
Issuer, the Subsidiary Guarantors
named therein and the United States
Trust Company of New York, as Trustee
10.1 Unlimited Guaranty Agreement dated Incorporated herein by reference
March 28, 2002
10.2 Security Agreement dated March 28, Incorporated herein by reference
2002, between Registrant and Guaranty
Bank, FSB, as Agent
10.3 Stock Pledge Agreement dated March 28, Incorporated herein by reference
2002, between Registrant and Guaranty
Bank, FSB, as Agent
10.4 Conveyance Agreement of Worland Area Incorporated herein by reference
Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm
Revocable Intervivos Trust dated April
23, 1984, to Continental Resources,
Inc.
10.5 Purchase Agreement signed January Incorporated herein by reference
2000, effective October 1, 1999, by
and between Patrick Energy Corporation
as Buyer and Continental Resources,
Inc. as Seller
10.6 Continental Resources, Inc. 2000 Stock Incorporated herein by reference
Option Plan
10.7 Form of Incentive Stock Option Incorporated herein by reference
Agreement
10.8 Form of Non-Qualified Stock Option Incorporated herein by reference
Agreement
10.9 Purchase and Sales Agreement between Incorporated herein by reference
Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental
Resources of Illinois, Inc. as
Purchaser, dated May 14, 2001
10.10 Collateral Assignment of Contracts Incorporated herein by reference
dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as
Agent
12.1 Statement re computation of ratio of Filed herewith electronically
debt to Adjusted EBITDA
12.2 Statement re computation of ratio of Filed herewith electronically
earning to fixed charges
12.3 Statement re computation of ratio of Filed herewith electronically
adjusted EBITDA to interest expense
21.0 Subsidiaries of Registrant Incorporated herein by reference
31.1 Certification pursuant to section 302
of the Sarbanes-Oxley Act of 2002 - Filed herewith electronically
Chief Executive Officer
31.2 Certification pursuant to section 302 Filed herewith electronically
of the Sarbanes-Oxley Act of 2002 -
Chief Financial Officer
99.1 Letter to the Securities and Exchange Incorporated herein by reference
Commission dated March 28, 2002,
regarding the audit of the
Registrant's financial statements by
Arthur Andersen LLP