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